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Callaghan, I. C., A. L. McKechnie, J. E. Ray, and J. C. Wainwright. "Identification of Crude Oil Components Responsible for Foaming." Society of Petroleum Engineers Journal 25, no. 02 (April 1, 1985): 171–75. http://dx.doi.org/10.2118/12342-pa.
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Abstract The foaming characteristics of a number of crude oils from a variety of sources were determined by Bikerman's pneumatic method. Extraction of these crudes with both pneumatic method. Extraction of these crudes with both alkali and acid indicated that the crude oil components responsible for the foam stability were removed by the alkali extraction. Further examination of the alkali extract revealed that after neutralization it was the chloroform soluble part of this extract (0.02% wt% of the whole crude) that was responsible for the foaming properties of the crudes investigated. This latter point was confirmed by demonstrating that the surface rheological properties of one of the extracted crudes could be restored by adding back the chloroform-soluble portion of the neutralized alkali extract. Analysis of this extract indicated that the foam-stabilizing materials were short-chain carboxylic acids and phenols of molecular weight -400. In principle, such analytical information could be used to identify principle, such analytical information could be used to identify crude oils likely to present severe foaming problems in the field. Such information could enable the process engineer to take appropriate corrective measures early in the life of a new field, thus avoiding the need for high capital expenditure at a later stage. Introduction Crude oil foams can pose major problems for operators of gas/oil separation plants, causing a loss of crude in the separated gas stream and consequent loss of revenue and possible damage to downstream compressors. Thus, an possible damage to downstream compressors. Thus, an understanding of the factors controlling crude oil foam stability is highly desirable, since it should lead to better methods of foam prediction and control. With this end in mind, we have attempted to identify those crude oil components responsible for foam stabilization. This paper outlines our findings to date and attempts to demonstrate that a similar suite of compounds is responsible for the stabilization of a wide range of crude oil foams. Experimental Materials Crude Oils. Chemical-free samples of 16 different stock-tank crude oils were obtained from a variety of sources (see Table 1). Particular care was taken to ensure that these samples were stored under nitrogen to prevent oxidation of the crudes. prevent oxidation of the crudes. Reagents used were cyclohexane, spectroscopic grade (from BDH); chloroform, general purpose reagent grade (from BDH); diethyl ether, general purpose reagent grade (from BDH); sodium hydroxide pellets, technical grade (from BDH); and SIL-PREP reagent: Applied Science Laboratories Ltd. All solvents were distilled before use, and only an 80% heart cut was taken. Techniques Foaminess Index Measurements. The foaming column used in this work consisted of a graduated glass tube approximately 30 cm [12 in.] in length with two fine sintered glass disks placed 1 cm [0.4 in.] apart, situated at the base of the tube just above the gas inlet. The gas used to create the foam is admitted to the column by way of a pressure reduction and flow meter assembly (see Ref. 1). The measurements were initiated by pipetting an aliquot of crude oil, just sufficient to cover the upper sintered disk, into the foaming column. The oil was allowed to spread over the sintered disk. Compressed air (or natural gas), flowing at a constant rate (40 cm3/sec [40 mL/min]), then was admitted to the column by way of the sintered disk and the crude oil was taken up into the froth. The bubbling was continued for 5 minutes after all the liquid had been taken up into the foam. When a homogeneous foam had been achieved, the height of the upper foam/gas interface was recorded. Three runs were performed on each crude oil studied. The foaminess index performed on each crude oil studied. The foaminess index (E) of each of the stripped and complete stock-tank crude oils then was determined by Bikerman's method. (1) where V, is the constant foam volume at time t and V is the volume of gas injected during time t. Extraction of Crude Oil Surfactants. Treatment with dilute aqueous sodium hydroxide solution was found to be the best means of extracting the acidic components in the crude oils. The oils were dissolved in cyclohexane to give 10% vol/vol solutions, thereby reducing viscosity and thus facilitating rapid phase separation. Despite this precaution some oil still was removed with the aqueous precaution some oil still was removed with the aqueous phase, which necessitated thorough back extraction with phase, which necessitated thorough back extraction with fresh solvent to ensure the selectivity of the separation. The sodium salts in the aqueous extract then were converted back to the free acids by treatment with excess mineral acid. The concentrate obtained was derived for analysis by combined gas chromatography/mass spectrometry (GC/MS). SPEJ P. 171
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Sun, Lin, Wanfen Pu, Jun Xin, Peng Wei, Bing Wang, Yibo Li, and Chengdong Yuan. "High temperature and oil tolerance of surfactant foam/polymer–surfactant foam." RSC Advances 5, no. 30 (2015): 23410–18. http://dx.doi.org/10.1039/c4ra17216g.
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Schramm, Laurier L., and Jerry J. Novosad. "Micro-visualization of foam interactions with a crude oil." Colloids and Surfaces 46, no. 1 (January 1990): 21–43. http://dx.doi.org/10.1016/0166-6622(90)80046-7.
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Anto-Darkwah, Evans, Muhammed Rehan Hashmet, and Ali M. Alsumaiti. "Laboratory Investigation of Static Bulk-Foam Tests in the Absence and Presence of Crude Oil." International Journal of Chemical Engineering and Applications 8, no. 2 (April 2017): 112–16. http://dx.doi.org/10.18178/ijcea.2017.8.2.640.
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Memon, Muhammad Khan, Khaled Abdalla Elraies, and Mohammed Idrees Ali Al-Mossawy. "Surfactant screening to generate strong foam with formation water and crude oil." Journal of Petroleum Exploration and Production Technology 11, no. 9 (August 5, 2021): 3521–32. http://dx.doi.org/10.1007/s13202-021-01251-w.
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AbstractMost of the available commercial surfactants precipitate due to the hardness of formation water. The study of surfactant generated foam and its stability is very complex due to its multifaceted pattern and common physicochemical properties. This research involved the study of foam generation by using the blended surfactants and their evaluation in terms of enhanced oil recovery (EOR). The objective of this study is to systematic screening of surfactants based on their capability to produce stable foam in the presence of two different categories of crude oil. Surfactant types such as non-ionic, anionic and amphoteric were selected for the experimental study. The foam was generated with crude oil, and the synthetic brine water of 34,107 ppm used as formation water. Surfactant concentration with the both types of crude oil, foam decay, liquid drainage and foam longevity was investigated by measuring the generated foam volume above the liquid level. The surfactant with concentration of 0.6wt%AOSC14-16, 1.2wt%AOSC14-16, 0.6wt%AOSC14-16 + 0.6wt%TX100 and 0.6wt%AOSC14-16 + 0.6wt%LMDO resulted in the maximum foam longevity with formation water and two categories of crude oil. The 50% liquid drainage and foam decay of surfactant solutions with concentration of 0.6wt%AOSC14-16 + 0.6wt%LMDO and 0.6wt%AOSC14-16 + 0.6wt%TX100 were noted with the maximum time. The findings of this research demonstrated that the generated foam and its longevity is dependent on the type of surfactant either individual or blended with their concentration. The blend of surfactant solution combines excellent foam properties.
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Abd Rahim, Nurul Suhana, Ismail Mohd Saaid, and Abubakar Abubakar Umar. "Evaluation of foam performance at different temperature for enhanced oil recovery process." World Journal of Engineering 16, no. 3 (June 10, 2019): 412–18. http://dx.doi.org/10.1108/wje-06-2018-0210.
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Purpose Application of foam in enhanced oil recovery requires a production of foam that is strong and stable enough to withstand a long period. There are numerous factors that may affect the performance of foam, among which is temperature. Therefore, this study aims to observe the foam performance at different temperature by evaluating the foamability and the stability of the foam. Design/methodology/approach In this study, bulk foam test using FoamScan was conducted to examine the effect of temperature on foam in the presence of crude oil. Nitrogen gas was sparged through the mixture of crude oil, an in-house developed surfactant, and sodium chloride solution as the brine at different temperatures to produce foam at a certain height. The crude oil was extracted from an oilfield in East Malaysia and the in-house developed surfactant was a mixture of amphoteric and anionic surfactants. A camera continuously recorded the height of foam during the generation and the collapse of the foam. The foamability and foam stability properties of each sample were taken as the indicators for foam performance. Furthermore, the entering, spreading and bridging analysis was run to observe the effect of the presence of crude oil on foam performance. Findings In general, the higher the temperature, the less stable the foam is. As the stability of foam is associated with the rate of liquid drainage, it was observed that as temperature increases, the rate of liquid drainage also increases. On the other hand, the entering, spreading and bridging analysis shows that there is entering of oil droplet happening on the interface of foam film that may promote the rupture of the foam film even more. Originality/value It was found that the temperature has a small impact on foamability, whereas the foam stability was significantly affected by the temperature. Therefore, it can be concluded that foamability is not necessarily interrelated to foam stability, contradicting to the findings of few authors.
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Keshawy, Mohamed, Reem K. Farag, and Amany Gaffer. "Egyptian crude oil sorbent based on coated polyurethane foam waste." Egyptian Journal of Petroleum 29, no. 1 (March 2020): 67–73. http://dx.doi.org/10.1016/j.ejpe.2019.11.001.
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Gomes, Alvaro Luiz, and Felipe Nascimento. "A new water-based foam controller for gas/oil separation on crude oil." Rio Oil and Gas Expo and Conference 20, no. 2020 (December 1, 2020): 185–86. http://dx.doi.org/10.48072/2525-7579.rog.2020.185.
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Ghosh, Pinaki, and Kishore K. Mohanty. "Novel Application of Cationic Surfactants for Foams With Wettability Alteration in Oil-Wet Low-Permeability Carbonate Rocks." SPE Journal 23, no. 06 (September 26, 2018): 2218–31. http://dx.doi.org/10.2118/179598-pa.
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Summary Carbonate rocks are typically heterogeneous at many scales, leading to low waterflood recoveries. Polymers and gels cannot be injected into nonfractured low-permeability carbonates (k < 10 md) because pore throats are smaller than the polymers. Foams have the potential to improve both oil-displacement efficiency and sweep efficiency in such carbonate rocks. However, foams have to overcome two adverse conditions in carbonates: oil-wettability and low permeability. This study evaluates several cationic-foam formulations that combine wettability alteration and foaming in low-permeability oil-wet carbonate cores. Contact-angle experiments were performed on initially oil-wet media to evaluate the wettability-altering capabilities of the surfactant formulations. Static foam-stability tests were conducted to evaluate their foaming performance in bulk; foam-flow experiments (without crude oil) were performed in porous media to estimate the foam strength. Finally, oil-displacement experiments were performed with a crude oil after a secondary gasflood. Two different injection strategies were studied in this work: surfactant slug followed by gas injection and coinjection of surfactant with gas at a constant foam quality. Systematic study of oil-displacement experiments in porous media showed the importance of wettability alteration in increasing tertiary oil recovery for oil-wet media. Several blends of cationic, nonionic, and zwitterionic surfactants were used in the experiments. In-house-developed Gemini cationic surfactant GC 580 was able to alter the wettability from oil-wet to water-wet and also formed strong bulk foam. Static foam tests showed an increase in bulk foam stability with the addition of zwitterionic surfactants to GC 580. Oil-displacement experiments in oil-wet carbonate cores revealed that tertiary oil recovery with injection of a wettability-altering surfactant and foam can recover a significant amount of oil [approximately 25 to 52% original oil in place (OOIP)] over the secondary gasflood. The foam rheology in the presence of oil suggested propagation of only weak foam in oil-wet low-permeability carbonate cores.
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Telmadarreie, Ali, and Japan J. Trivedi. "New Insight on Carbonate-Heavy-Oil Recovery: Pore-Scale Mechanisms of Post-Solvent Carbon Dioxide Foam/Polymer-Enhanced-Foam Flooding." SPE Journal 21, no. 05 (March 23, 2016): 1655–68. http://dx.doi.org/10.2118/174510-pa.
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Summary Carbonate reservoirs, deposited in the Western Canadian Sedimentary Basin (WCSB), hold significant reserves of heavy crude oil that can be recovered by nonthermal processes. Solvent, gas, water, and water-alternating-gas (WAG) injections are the main methods for carbonate-heavy-oil recovery in the WCSB. Because of the fractured nature of carbonate formations, many advantages of these production methods are usually in contrast with their low recovery factor. Alternative processes are therefore needed to increase oil-sweep efficiency from carbonate reservoirs. Foam/polymer-enhanced-foam (PEF) injection has gained interest in conventional heavy-oil recovery in recent times. However, the oil-recovery process by foam, especially PEF, in conjunction with solvent injection is less understood in fractured heavy-oil-carbonate reservoirs. The challenge is to understand how the combination of surfactant, gas, and polymer allows us to better access the matrix and efficiently sweep the oil. This study introduces a new approach to access the unrecovered heavy oil in fractured-carbonate reservoirs. Carbon dioxide (CO2) foam and CO2 PEF were used to decrease oil saturation after solvent injection, and their performance was compared with gas injection. A specially designed fractured micromodel was used to visualize the pore-scale phenomena during CO2-foam/PEF injection. In addition, the static bulk performances of CO2 foam/PEF were analyzed in the presence of heavy crude oil. A high-definition camera was used to capture high-quality images. The results showed that in both static and dynamic studies the PEF had high stability. Unlike CO2 PEF, CO2 foam lamella broke much faster and resulted in the collapse of the foam during heavy-oil recovery after solvent flooding. It appeared that foam played a greater role than just gas-mobility control. Foam showed outstanding improvement in heavy-oil recovery over gas injection. The presence of foam bubbles was the main reason to improve heavy-oil-sweep efficiency in heterogeneous porous media. When the foam bubbles advanced through pore throats, the local capillary number increased enough to displace the emulsified oil. PEF bubbles generated an additional force to divert surfactant/polymer into the matrix. Overall, CO2 foam and PEF remarkably increased heavy-oil recovery after solvent injection into the fractured reservoir.
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Tang, Guo-Qing, Yi Tak Leung, Louis M. Castanier, Akshay Sahni, Frederic Gadelle, Mridul Kumar, and Anthony R. Kovscek. "An Investigation of the Effect of Oil Composition on Heavy Oil Solution-Gas Drive." SPE Journal 11, no. 01 (March 1, 2006): 58–70. http://dx.doi.org/10.2118/84197-pa.
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Summary This study probes experimentally the mechanisms of heavy-oil solution gas drive through a series of depletion experiments employing two heavy crude oils and two viscous mineral oils. Mineral oils were chosen with viscosity similar to crude oil at reservoir temperature. A specially designed aluminum coreholder allows visualization of gas phase evolution during depletion using X-ray computed tomography (CT). In addition, a visualization cell was installed at the outlet of the sandpack to monitor the flowing-gas-bubble behavior vs. pressure. Bubble behavior observed at the outlet corroborates CT measurements of in-situ gas saturation vs. pressure. Both depletion rate and oil composition affect the size of mobile bubbles. At a high depletion rate (0.035 PV/hr), a foam-like flow of relatively small pore-sized bubbles dominates the gas and oil production of both crude oils. Conversely, at a low depletion rate (0.0030 PV/hr), foam-like flow is not observed in the less viscous crude oil; however, foam-like flow behavior is still found for the more viscous crude oil. No foam-like flow is observed for the mineral oils. In-situ imaging shows that the gas saturation distribution along the sandpack is not uniform. As the pattern of produced gas switches from dispersed bubbles to free gas flow, the distribution of gas saturation becomes even more heterogeneous. This indicates that a combination of pore restrictions and gravity forces significantly affects free gas flow. Additionally, results show that solution-gas drive is effective even at reservoir temperatures as great as 80°C. Oil recovery ranges from 12 to 30% OOIP; the higher the depletion rate, the greater the recovery rate. Introduction Solution gas drive has shown unexpectedly high recovery efficiency in some heavy-oil reservoirs. The mechanisms, however, that have been proposed are speculative, sometimes contradictory, and do not explain fully the origin of high primary oil recovery and slow decline in reservoir pressure. Smith (1988) first identified this effect. He hypothesized that gas bubbles smaller than pore constrictions are liberated from the oil, but are not able to form a continuous gas phase and flow freely. Instead, the gas bubbles exist in a dispersed state in the oil and only flow with the oil phase. Smith stated that oil viscosity is reduced significantly, resulting in high recovery performance. Later, many researchers focused on so-called foamy-oil behavior. Claridge and Prats (1995) hypothesized that heavy-oil components (such as asphaltenes) concentrate at the interfaces between oil and gas bubbles, thereby preventing bubbles from coalescing into a continuous gas phase. Bubbles are assumed to be smaller than pore dimensions. Claridge and Prats stated that the concentration of heavy-oil components at the interfaces results in a reduction of the viscosity of the remaining oil. Bora et al. (2000) discussed the flow behavior of solution gas drive in heavy oils. Based on their studies, they found that dispersed gas bubbles do not coalesce rapidly in heavy oil, especially at high depletion rate. They stated that the main feature of the gas/oil dispersion is a reduced viscosity compared to the original oil. Models to explain the experimental results were also established (Sheng et al. 1994, 1996, 1999, 1995).
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Hussain, A. A. A., S. Vincent-Bonnieu, R. Z. Kamarul Bahrim, R. M. Pilus, and W. R. Rossen. "Impact of Crude Oil on Pre-Generated Foam in Porous Media." Journal of Petroleum Science and Engineering 185 (February 2020): 106628. http://dx.doi.org/10.1016/j.petrol.2019.106628.
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Pu, Wanfen, Shishi Pang, and Chongyang Wang. "Experimental investigation of foam performance in the presence of crude oil." Journal of Surfactants and Detergents 20, no. 5 (June 22, 2017): 1051–59. http://dx.doi.org/10.1007/s11743-017-1991-3.
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Telmadarreie, Ali, and Japan J. Trivedi. "CO2 Foam and CO2 Polymer Enhanced Foam for Heavy Oil Recovery and CO2 Storage." Energies 13, no. 21 (November 2, 2020): 5735. http://dx.doi.org/10.3390/en13215735.
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Enhanced oil recovery (EOR) from heavy oil reservoirs is challenging. High oil viscosity, high mobility ratio, inadequate sweep, and reservoir heterogeneity adds more challenges and severe difficulties during any EOR method. Foam injection showed potential as an EOR method for challenging and heterogeneous reservoirs containing light oil. However, the foams and especially polymer enhanced foams (PEF) for heavy oil recovery have been less studied. This study aims to evaluate the performance of CO2 foam and CO2 PEF for heavy oil recovery and CO2 storage by analyzing flow through porous media pressure profile, oil recovery, and CO2 gas production. Foam bulk stability tests showed higher stability of PEF compared to that of surfactant-based foam both in the absence and presence of heavy crude oil. The addition of polymer to surfactant-based foam significantly improved its dynamic stability during foam flow experiments. CO2 PEF propagated faster with higher apparent viscosity and resulted in more oil recovery compared to that of CO2 foam injection. The visual observation of glass column demonstrated stable frontal displacement and higher sweep efficiency of PEF compared to that of conventional foam. In the fractured rock sample, additional heavy oil recovery was obtained by liquid diversion into the matrix area rather than gas diversion. Aside from oil production, the higher stability of PEF resulted in more gas storage compared to conventional foam. This study shows that CO2 PEF could significantly improve heavy oil recovery and CO2 storage.
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Niu, Haifeng, Jianbo Li, Zhe Qiang, and Jie Ren. "Versatile and cost-efficient cleanup of viscous crude oil by an elastic carbon sorbent from direct pyrolysis of a melamine foam." Journal of Materials Chemistry A 9, no. 18 (2021): 11268–77. http://dx.doi.org/10.1039/d1ta01133b.
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Carbon sponge with photothermal and Joule thermal properties was prepared by pyrolysis of melamine sponge. The significantly decreased viscosity of crude oil from heating enables a rapid and continuous crude oil cleanup under all weather conditions.
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Singh, Robin, and Kishore K. Mohanty. "Foams With Wettability-Altering Capabilities for Oil-Wet Carbonates: A Synergistic Approach." SPE Journal 21, no. 04 (August 15, 2016): 1126–39. http://dx.doi.org/10.2118/175027-pa.
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Summary The goal of this work is to systematically study the effect of wettability alteration and foaming, either acting individually or synergistically, on tertiary oil recovery in oil-wet carbonate cores. Three types of anionic-surfactant formulations were used: alkyl propoxy sulfate (APS), which exhibited low interfacial tension (IFT), wettability alteration, and weak foaming; alpha-olefin sulfonate (AOS), which showed no wettability alteration but good foaming; and a blend of APS, AOS, and a zwitterionic-foam booster, which showed low IFT, wettability alteration, and good foaming. First, contact-angle experiments were conducted on oil-wet calcite plates to evaluate their wettability-altering capabilities. Second, spontaneous imbibitions in a microchannel were performed to study the role of IFT reduction and wettability alteration by these formulations. Third, static foam tests were conducted to evaluate their foaming performance in bulk. Fourth, foam-flow experiments were conducted in cores to evaluate potential synergism between the anionic-surfactant AOS and the zwitterionic surfactants in stabilizing foam in the absence of crude oil. Finally, oil-displacement experiments were performed by use of a vuggy, oil-wet, dolomite core saturated with a crude oil. After secondary waterfloods, surfactant solutions were coinjected with methane gas at a fixed foam quality (gas-volume fraction). Contact-angle and spontaneous-imbibition experiments showed that AOS can act as a wettability-altering surfactant in the presence of sodium carbonate, but not alone. No synergy was observed in foam stabilization by means of the blend of zwitterionic surfactant and AOS solution (1:1) in a water-wet carbonate core. Oil-displacement experiments in oil-wet carbonate core revealed that coinjection of wettability-altering surfactant and gas can recover a significant amount of oil [33% original oil in place (OOIP)] over waterflood. During foam flooding, with AOS as the foaming agent, only a weak foam was propagated in a carbonate core, irrespective of the core wettability. A blend of wettability-altering surfactant, AOS, and zwitterionic surfactant not only altered the wettability of carbonate core from oil-wet to water-wet, but also significantly increased the foam-pressure gradient in the presence of crude oil.
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Li, Robert F., George J. Hirasaki, Clarence A. Miller, and Shehadeh K. Masalmeh. "Wettability Alteration and Foam Mobility Control in a Layered, 2D Heterogeneous Sandpack." SPE Journal 17, no. 04 (September 20, 2012): 1207–20. http://dx.doi.org/10.2118/141462-pa.
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Summary In a layered, 2D heterogeneous sandpack with a 19:1 permeability contrast that was preferentially oil-wet, the recovery by waterflood was only 49.1% of original oil in place (OOIP) because of injected water flowing through the high-permeability zone, leaving the low-permeability zone unswept. To enhance oil recovery, an anionic surfactant blend (NI) was injected that altered the wettability and lowered the interfacial tension (IFT). Once IFT was reduced to ultralow values, the adverse effect of capillarity retaining oil was eliminated. Gravity-driven vertical countercurrent flow then exchanged fluids between high- and low-permeability zones during a 42-day system shut-in. Cumulative recovery after a subsequent foam flood was 94.6% OOIP, even though foam strength was weak. Recovery with chemical flood (incremental recovered oil/waterflood remaining oil) was 89.4%. An alternative method is to apply foam mobility control as a robust viscous-force-dominant process with no initial surfactant injection and shut-in. The light crude oil studied in this paper was extremely detrimental to foam generation. However, the addition of lauryl betaine to NI (NIB) at a weight ratio of 1:2 (NI:lauryl betaine) made the new blend a good foaming agent with and without the presence of the crude oil. NIB by itself as an IFT-reducing and foaming agent is shown to be effective in various secondary and tertiary alkaline/surfactant/foam (ASF) processes in water-wet 1D homogeneous sandpacks and in an oil-wet heterogeneous layered system with a 34:1 permeability ratio.
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Pu, Wanfen, Peng Wei, Lin Sun, Yong Pu, and Ying Chen. "Investigation on stabilization of foam in the presence of crude oil for improved oil recovery." Journal of Dispersion Science and Technology 40, no. 5 (September 11, 2018): 646–56. http://dx.doi.org/10.1080/01932691.2018.1476153.
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Medina, Oscar E., Yira Hurtado, Cristina Caro-Velez, Farid B. Cortés, Masoud Riazi, Sergio H. Lopera, and Camilo A. Franco. "Improvement of Steam Injection Processes Through Nanotechnology: An Approach through in Situ Upgrading and Foam Injection." Energies 12, no. 24 (December 6, 2019): 4633. http://dx.doi.org/10.3390/en12244633.
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This study aims to evaluate a high-performance nanocatalyst for upgrading of extra-heavy crude oil recovery and at the same time evaluate the capacity of foams generated with a nanofluid to improve the sweeping efficiency through a continuous steam injection process at reservoir conditions. CeO2±δ nanoparticles functionalized with mass fractions of 0.89% and 1.1% of NiO and PdO, respectively, were employed to assist the technology and achieve the oil upgrading. In addition, silica nanoparticles grafted with a mass fraction of 12% polyethylene glycol were used as an additive to improve the stability of an alpha-olefin sulphonate-based foam. The nanofluid formulation for the in situ upgrading process was carried out through thermogravimetric analysis and measurements of zeta potential during eight days to find the best concentration of nanoparticles and surfactant, respectively. The displacement test was carried out in different stages, including, (i) basic characterization, (ii) steam injection in the absence of nanofluids, (iii) steam injection after soaking with nanofluid for in situ upgrading, (iv) N2 injection, and (v) steam injection after foaming nanofluid. Increase in the oil recovery of 8.8%, 3%, and 5.5% are obtained for the technology assisted by the nanocatalyst-based nanofluid, after the nitrogen injection, and subsequent to the thermal foam injection, respectively. Analytical methods showed that the oil viscosity was reduced 79%, 77%, and 31%, in each case. Regarding the asphaltene content, with the presence of the nanocatalyst, it decreased from 28.7% up to 12.9%. Also, the American Petroleum Institute (API) gravity values increased by up to 47%. It was observed that the crude oil produced after the foam injection was of higher quality than the crude oil without treatment, indicating that the thermal foam leads to a better swept of the porous medium containing upgraded oil.
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Chen, Zhen Ya, He Song, and Xin Ping Zhang. "Air Foam Injection for EOR in Light Oil Reservoirs with High Heterogeneity." Advanced Materials Research 524-527 (May 2012): 1322–26. http://dx.doi.org/10.4028/www.scientific.net/amr.524-527.1322.
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In this paper, we research the blocking effect of air foam, oxidation of oil-air foam and air foam enhanced recovery by experiments. The results show the more injected air foam, the stronger the sealing capacity, but increment trend changes slow. Beside, high-pressure, low-temperature can enhance the sealing capacity of the air foam. Temperature is the principal factor which can influence crude oil-air-foam oxidizing reaction. The reaction rate increases with increase of temperature. What is more, the rise of pressure can accelerate the oxidation response in a certain extent. The air-foam has the good oil displacement efficiency. In the heterogeneous reservoir, air foam injection can seal of high permeable zones, enhances sweep efficiency and is propitious to achieve the low temperature oxidation.
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Schramm, Laurier L., Alexandru T. Turta, and Jerry J. Novosad. "Microvisual and Coreflood Studies of Foam Interactions With a Light Crude Oil." SPE Reservoir Engineering 8, no. 03 (August 1, 1993): 201–6. http://dx.doi.org/10.2118/20197-pa.
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Onoghwarite, Ohimor Evuensiri, Erude Abraham Okeoghene, Onocha Ovonomo, Oreko Benjamin Ufuoma, and Ononiwu Prosper Ikechukwu. "Performance Evaluation of Polydimethylsiloxane-Solvent Blends as Defoamer for Crude Oil Foam." IOP Conference Series: Materials Science and Engineering 413 (September 10, 2018): 012047. http://dx.doi.org/10.1088/1757-899x/413/1/012047.
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Telmadarreie, Ali, and Japan Trivedi. "Static and Dynamic Performance of Wet Foam and Polymer-Enhanced Foam in the Presence of Heavy Oil." Colloids and Interfaces 2, no. 3 (September 8, 2018): 38. http://dx.doi.org/10.3390/colloids2030038.
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Inadequate sweep efficiency is one of the main concerns in conventional heavy oil recovery processes. Alternative processes are therefore needed to increase heavy oil sweep efficiency. Foam injection has gained interest in conventional oil recovery in recent times as it can control the mobility ratio and improve the sweep efficiency over chemical or gas flooding. However, most of the studies have focused on light crude oil. This study aims to investigate the static and dynamic performances of foam and polymer-enhanced foam (PEF) in the presence of heavy oil. Static and dynamic experiments were conducted to investigate the potential of foam and PEF for heavy oil recovery. Static analysis included foam/PEF stability, decay profile, and image analysis. A linear visual sand pack was used to visualize the performance of CO2 foam and CO2 PEF in porous media (dynamic experiments). Nonionic, anionic, and cationic surfactants were used as the foaming agents. Static stability results showed that the anionic surfactant generated relatively more stable foam, even in the presence of heavy oil. Slower liquid drainage and collapse rates for PEF compared to that of foam were the key observations through foam static analyses. Besides improving heavy oil recovery, the addition of polymer accelerated foam generation and propagation in porous media saturated with heavy oil. Visual analysis demonstrated more stable frontal displacement and higher sweep efficiency of PEF compared to conventional foam flooding. Unlike foam injection, lesser channeling (foam collapse) was observed during PEF injection. The results of this study will open a new insight on the potential of foam, especially polymer-enhanced foam, for oil recovery of those reservoirs with viscous oil.
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Arangalage, Mélanie, Jean-Philippe Gingras, Nicolas Passade-Boupat, François Lequeux, and Laurence Talini. "Asphaltenes at Oil/Gas Interfaces: Foamability Even with No Significant Surface Activity." Colloids and Interfaces 3, no. 1 (December 21, 2018): 2. http://dx.doi.org/10.3390/colloids3010002.
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In the oil industry, oil foams can be found at different steps from the crude oil treatment to the gas stations. Their lifetime can sometimes reach several hours and be much longer than the residence times available for gas/liquid separation. However, the conditions of formation and stability of such foams have been poorly studied in the literature, in contrast to the foamability of aqueous systems. On the fields, it is currently observed that crude oils enriched with asphaltenes form particularly stable foams. In this work, we have studied the influence of asphaltenes on the foamability of oil mixtures. All the experiments were performed on model systems of crude oils, that-is-to-say decane/toluene mixtures containing asphaltenes at concentrations ranging from 0.01 to 5 wt%. We in particular demonstrate that, within the investigated concentration range, asphaltenes from two different wells do not have any significant surface active properties despite their contribution to the foamability of oil mixtures. We show that the formation of an asphaltene layer at the interface with air that has been evidenced in the past results from solvent evaporation. Using a recently developed experiment based on the Marangoni effect with our model oils, we demonstrate that asphaltenes are not surface active in those oils. We further characterize the oil foamability by measuring the lifetime of the foam formed by blowing nitrogen through the liquid in a column. At concentrations larger than 1 wt%, asphaltenes significantly enhance the foamability of the oil mixtures. Moreover, the closer the asphaltenes are to their limit of precipitation the larger the foamability. However, we evidence that the oil mixtures themselves foam and we show the importance to consider that effect on the foamability. In addition, we observe that the foamability of the asphaltenes solutions unexpectedly varies with the initial height of the liquid in the column. We suggest that, although not significantly modifying the surface tension, the asphaltenes could be trapped at the oil/gas interface and thus prevent bubble coalescence.
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Guo, Hua, Pacelli L. J. Zitha, Rien Faber, and Marten Buijse. "A Novel Alkaline/Surfactant/Foam Enhanced Oil Recovery Process." SPE Journal 17, no. 04 (November 27, 2012): 1186–95. http://dx.doi.org/10.2118/145043-pa.
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Summary This article reports a laboratory study of a novel alkaline/surfactant/foam (ASF) process. The goal of the study was to investigate whether foaming a specially designed alkaline/surfactant (AS) formulation could meet the two key requirements for a good enhanced oil recovery (EOR) [i.e., lowering the interfacial tension (IFT) considerably and ensuring a good mobility control]. The study included phase-behavior tests, foam-column tests, and computed-tomography (CT)-scan-aided corefloods. It was found that the IFT of the designed AS and a selected crude oil drops by four orders of magnitude at the optimum salinity. The AS proved to be a good foaming agent in the column tests and corefloods in the absence of oil. The mobility reduction caused by the AS foam was hardly sensitive to salinity and increased with decreasing foam quality. CT-scanned corefloods demonstrated that AS foam, after a small AS preflush, recovered almost all the oil left after waterflooding. The oil-recovery mechanism by ASF combines the formation of an oil bank and the transport of emulsified oil by flowing lamellae. Further optimization of the ASF is needed to ensure that the oil is produced exclusively by the oil bank.
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Brancato, Vincenza, Elpida Piperopoulos, Emanuela Mastronardo, Luigi Calabrese, Candida Milone, and Edoardo Proverbio. "Synthesis and Characterization of Graphite Composite Foams for Oil Spill Recovery Application." Journal of Composites Science 4, no. 4 (October 19, 2020): 154. http://dx.doi.org/10.3390/jcs4040154.
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The aim of this paper is the synthesis and characterization of a composite silicone foam filled with expanded graphite (EG) for oil spill recovery applications. The EG foams were obtained using a foaming slurry consisting of a mixture of siloxane compounds as the matrix with an EG filler. The effect of the filler content’s performance on an innovative composite silicone-based foam was investigated. All the obtained samples exhibited an open cell morphology. Each foam was evaluated in four commonly used oils (kerosene, pump oil, naphtha and crude oil). Additionally, kinetics was studied in order to investigate the physical, chemical and mass transport mechanisms that act during the absorption phenomenon and uptake evolution of the contaminants. Foam filled with 3% of EG exhibited the highest absorption capacity, particularly with light oils kerosene and virgin naphtha (854 and 1016 wt.%, respectively). Furthermore, the kinetic study showed that pseudo-second order mechanisms better fitted the composite absorption performances, suggesting that the oil sorption into EG filled polydimethylsiloxane (PDMS) foams could be related to chemisorption mechanism. The results evidenced a good oil sorption capability and water/oil selectivity indicating this class of materials as a potentially applicable material for oil spill remediation.
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Schramm, Laurier L., and Karin Mannhardt. "The effect of wettability on foam sensitivity to crude oil in porous media." Journal of Petroleum Science and Engineering 15, no. 1 (July 1996): 101–13. http://dx.doi.org/10.1016/0920-4105(95)00068-2.
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Syed, Asad Hassan, Nurudeen Yekeen, Eswaran Padmanabhan, Ahmad Kamal Idris, and Dzeti Farhah Mohshim. "Characterization of lauryl betaine foam in the Hele-Shaw cell at high foam qualities (80%–98%)." Petroleum Science 17, no. 6 (June 4, 2020): 1634–54. http://dx.doi.org/10.1007/s12182-020-00470-w.
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AbstractLauryl betaine (LB) as an amphoteric surfactant carries both positive and negative charges and should be able to generate stable foam through electrostatic interaction with nanoparticles and co-surfactants. However, no previous attempts have been made to investigate the influence of nanoparticles and other co-surfactants on the stability and apparent viscosity of LB-stabilized foam. In this study, a thorough investigation on the influence of silicon dioxide (SiO2) nanoparticles, alpha olefin sulfonate (AOS) and sodium dodecyl sulfate (SDS), on foam stability and apparent viscosity was carried out. The experiments were conducted with the 2D Hele-Shaw cell at high foam qualities (80%–98%). Influence of AOS on the interaction between the LB foam and oil was also investigated. Results showed that the SiO2-LB foam apparent viscosity decreased with increasing surfactant concentration from 0.1 wt% to 0.3 wt%. 0.1 wt% SiO2 was the optimum concentration and increased the 0.1 wt% LB foam stability by 108.65% at 96% foam quality. In the presence of co-surfactants, the most stable foam, with the highest apparent viscosity, was generated by AOS/LB solution at a ratio of 9:1. The emulsified crude oil did not imbibe into AOS-LB foam lamellae. Instead, oil was redirected into the plateau borders where the accumulated oil drops delayed the rate of film thinning, bubble coalescence and coarsening.
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Wang, Pu Hui, Chuan Pin Zou, and Hui Zhong. "The Study of Highly Oil Absorption Polyurethane Foam Material and its Application in the Emergency Disposal of Hazardous Chemicals." Advanced Materials Research 518-523 (May 2012): 847–53. http://dx.doi.org/10.4028/www.scientific.net/amr.518-523.847.
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This paper introduced a kind of oil absorption polyurethane foam (PUF) material, which had good absorption on a variety of liquid hazardous chemicals. The absorption rate of this material while absorbing crude oil can reach 40g / g or more and the absorption rate to xylene is 49.9g / g. In addition, this paper also discussed the relationship among the cell opening rate, volume availability and the oil absorption rate of the foam material, comparing with oil absorption felt, the commonly used absorption materials. Researchers observed the microstructure of PUF by the scanning electron microscope, discussed its oil absorption mechanism and analyzed its emergency disposal in the leakage accident of hazardous chemicals.
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Memon, Muhammad Khan, Khaled Abdalla Elraies, and Mohammed Idrees Ali Al-Mossawy. "Performance of surfactant blend formulations for controlling gas mobility and foam propagation under reservoir conditions." Journal of Petroleum Exploration and Production Technology 10, no. 8 (September 8, 2020): 3961–69. http://dx.doi.org/10.1007/s13202-020-00996-0.
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Abstract The use of surfactant is one of the possible solutions to minimize the mobility of gases and improve the sweep efficiency, but the main problem with this process is its stability in the presence of injection water and crude oil under reservoir conditions. In this study, the three types of surfactant anionic, nonionic and amphoteric are examined in the presence of brine salinity at 96 °C and 1400 psia. To access the potential blended surfactant solutions as gas mobility control, laboratory test including aqueous stability, interfacial tension (IFT) and mobility reduction factor (MRF) were performed. The purpose of MRF is to evaluate the blocking effect of selected optimum surfactant solutions. Based on experimental results, no precipitation was observed by testing the surfactant solutions at reservoir temperature of 96 °C. The tested surfactant solutions reduced the IFT between crude oil and brine. The effectiveness and strength of surfactant solutions without crude oil under reservoir conditions were evaluated. A high value of differential pressure demonstrates that the strong foam was generated inside a core that resulted in delay in breakthrough time and reduction in the gas mobility. High mobility reduction factor result was measured by the solution of blended surfactant 0.6%AOS + 0.6%CA406H. Mobility reduction factor of other tested surfactant solutions was found low due to less generated foam by using CO2 under reservoir conditions. The result of these tested surfactant solutions can provide the better understanding of the mechanisms behind generated foam stability and guideline for their implementation as gas mobility control during the process of surfactant alternating gas injection.
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Mumtaz, Mudassar, Isa Mohd Tan, Muhammad Mushtaq, and Muhammad Sagir. "Advances in Evaluation of Surfactant Performances at High Temperature by Static Foam Tests." Advanced Materials Research 1133 (January 2016): 634–38. http://dx.doi.org/10.4028/www.scientific.net/amr.1133.634.
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—Foam stability and mobility reduction are the key parameters for foam assisted enhanced oil recovery. The harsh conditions such as high temperature, pressure and salinity present in an oil reservoir tend to destabilise the foam leading to poor sweep efficiency. Screening for the best performing foaming recipes has been performed to ascertain foam stability in the presence and absence of oil. Static foam test has been performed in order to study the foam stability and foam oil interactions at 90°C. Two anionic surfactants, alpha olefin sulphonate (AOS14-16) and methyl ester sulphonate (MES16-18) were mixed with betaine (foam booster) in different proportions to design the formulations. In addition to the ternary formulations, binary formulation involving surfactant and betaine were also evaluated for foam stability. For the study of oil effects on foaming performance of surfactant formulation, n-decane, diesel and Dulang crude oil are used. The recipes were evaluated by static foam tests to note the foam height and endurance time. It was found that the anionic surfactant played a major role in foam stability and the betaine was found less significant. However, the betaine alone was found effective for foaming and was poor for endurance time. While in mixture, the surfactant and betaine were found to interact strongly and a profound synergistic effect was noted. During oil interaction studies, the alkane type oils of low molecular weight become solubilised with surfactant molecule forming an emulsion and hence decimate the foam stability. However, higher alkanes with molecular chain more than ten carbon atoms (decane) stabilised the foam because of low solubilisation efficiency between surfactant and oil to form emulsions. The obtained results of the designed experiment have been analysed and discussed in detail to understand the contribution of individual component as well as their interactions with each other in order to stabilize foams.Keywords—Static Foam, Foam-Oil interactions, AOS, MES, Enhanced Oil Recovery
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Asri, Asyimah, Rashidah M. Pilus, Ahmad Kamal Idris, Ismail Mohd Saaid, Zakaria Man, and Abdelazim Abbas Ahmed. "IONIC LIQUID-STABILIZED FOAMS IN RELATION TO ENHANCED OIL RECOVERY." Science Proceedings Series 2, no. 1 (April 20, 2020): 50–54. http://dx.doi.org/10.31580/sps.v2i1.1279.
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Foam stability is unfavorably influenced by crude oil and this situation has been a main obstacle for the foam injection application for enhanced oil recovery (EOR) (1, 2). The presence of additives to surfactant solution could improve foam stability (3, 4). In this work, effectiveness of the common ionic liquid (IL) and newly developed eutectic-based IL or known as Deep Eutectic solvent (DES) were determined to evaluate their use as co-surfactant in stabilizing foam in the presence of oil. The novelty of the new chemicals in EOR application is in its capability to enhance the surfactant performance in foam stability while being cheap, biodegradable and easy to produce for bulk application. Several formulation of IL/surfactant mass ratio were investigated based on bulk foam stability test in the presence of oil to find the optimum formulation. A fixed concentration of an in-house-surfactant, MFOMAX (M) was utilized. Core flood experiments were performed to evaluate mobility reduction factor (MRF) and incremental oil recovery. The overall results demonstrated that the addition of ILs in surfactant solution were found to improve foam stability. Increment in MRF value and additional oil recovery (AOR) were also reported.
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Fang, Ji Chao, Cai Li Dai, Kai Wang, Qin Fang Ding, and Si Yu Wang. "Laboratory Evaluation on Foaming Agent for High-Temperature and High-Salinity Reservoir." Advanced Materials Research 884-885 (January 2014): 82–86. http://dx.doi.org/10.4028/www.scientific.net/amr.884-885.82.
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In order to further enhance oil recovery (EOR) of the high temperature and high salt oil fields by foam flooding, one foaming agent was screened by airflow method. The influence of oil-water and pressure on foamability and stability were evaluated,and oil displacement experiment was also conducted. The results show that CS-1 foaming agent has better foamability and stability than the others under the reservoir conditions (Temperature 110 °C, Salinity 11.52×104 mg/L, Ca2+&Mg2+ 7654 mg/L). The foam stability will be better as the pressure rise or be worse when it met the crude oil. Oil recovery was improved by 4.13% after waterflood and the total recovery is 60.75%.
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Mannhardt, Karin, J. J. Novosad, and L. L. Schramm. "Comparative Evaluation of Foam Stability to Oil." SPE Reservoir Evaluation & Engineering 3, no. 01 (February 1, 2000): 23–34. http://dx.doi.org/10.2118/60686-pa.
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Summary Foam performance was evaluated by several experimental methods (corefloods, bulk foam stability, micromodel observations, interfacial parameters) using three commercial surfactants, either by themselves or mixed with a fluorinated surfactant. The presence of oil reduced foam mobility reduction factors (Fmr) to different degrees; excellent Fmr were still attained with some surfactants in the presence of residual oil. Using the fluorinated surfactant as additive enhanced the oil tolerance of some, but not all, foams. The tested foams exhibited oil transporting properties. Each foam adjusted to its own residual oil saturation and corresponding level of mobility reduction. Foam performance in corefloods did not correlate in general with predictions based on the other experimental methods. Introduction Foams have been considered for mobility control in solvent, gas, or vapor injection improved oil recovery (IOR) processes, for blocking and diverting using either conventional or gelled foams, and for gas/oil ratio control at production wells. In a diverse range of applications, a foam encounters a range of oil saturations, which necessitates designing a foam with the required stability to oil. In applications where it is desirable to place a foam into swept (low oil saturation) zones, a foam with intermediate or low stability to oil may be adequate. If a foam is to be used as an oil displacing fluid or for gas/oil ratio control in producing wells, foam stability to oil is essential. Coreflood experiments by different investigators suggest that oil becomes detrimental to foam at oil saturations above 5 to 20%. 1 Among a number of mechanisms of foam/oil interaction suggested in the literature,1–5 three main models have emerged in attempts to predict foam stability to oil: spreading and entering coefficients, lamella number, and pseudoemulsion film models. The classical spreading and entering coefficients, based on interfacial tensions measured with bulk liquids, have been used with some success,6,7 but do not correlate with foam stability to oil in general.2-5,8,9 A geometry-dependent spreading coefficient,10 a "generalized entering coefficient,"4 and a "film excess energy,"5 have been defined in order to take into account thin-film forces important in foam/oil encounters in porous media. The lamella number attempts to quantify the observation that oil can become emulsified and imbibed into foam lamellae, which tends to destabilize a foam to various degrees.2,11,12 Pseudoemulsion film models state that a foam can only be stable in the presence of oil if the oil is wetted by the aqueous phase, i.e., if oil and gas phases remain separated by a film of aqueous phase (the pseudoemulsion film).3-5,13 Although different models have been successfully applied to different situations, translating the fundamental mechanisms of foam/oil interaction into generally applicable rules for field application remains difficult. The objective of this work was to evaluate the performance of six foams in the absence and presence of crude oil using different experimental techniques: corefloods in Berea and North Sea reservoir sandstone, bulk foam heights in a blender and in a high-pressure cell, lamella breakage frequency in an etched-glass micromodel, and interfacial parameters. The purpose of the corefloods was to screen a series of promising surfactant candidates for the application of foam in the North Sea. A large amount of experimental 14 and simulation15 work was simultaneously carried out by Norsk Hydro, and has led to a successful field test.16 The other experimental techniques have been used by others as screening tools or to evaluate foam/oil interactions. They were used in this work to study possible correlations with coreflood performance. Some fluorinated surfactants form foams that are very stable in the presence of oil.2,4,8,17 They are, however, more costly than hydrocarbon surfactants by one to two orders of magnitude. In this study, a fluorinated surfactant was used as an additive at relatively low concentration to improve the oil tolerance of three conventional surfactants. Experiment Materials. Cores were either Berea sandstone (length 30 cm, diameter 3.8 cm, porosity 23%, and absolute permeability to air 940 to 1,200 md), or reservoir sandstone (length 17 cm, diameter 3.7 cm, porosity 26%, and absolute permeability to air 3,400 to 3,900 md) from the Oseberg field (North Sea), supplied by Norsk Hydro. The reservoir cores were extracted in a chloroform/methanol mixture and dried before use. Four commercial surfactants were used: Chaser GR-1080 (Chaser International, proprietary blend containing mostly alpha olefin sulfonates), Enordet X-2001 (Shell Chemical Company, alcohol ethoxyglycerylsulfonate), Dow XSS-84321.05 (Dow Chemical, mixture of C10 diphenyletherdisulfonate and C 14-16 alpha olefin sulfonate), and Fluorad FC-751 (3M Company, fluoroalkylsulfobetaine). They will be referred to as Chaser, Enordet, Dow, and Fluorad in this paper. Cited concentrations are active concentrations in %w/v in sea water. The three hydrocarbon-based surfactants (Chaser, Enordet, and Dow) were used either by themselves or mixed with Fluorad (1:9 by mass Fluorad to Chaser, Enordet, or Dow). The brine was filtered (0.45 ?m) synthetic sea water (density 1.004 g/cm 3 and viscosity 0.38 mPa's, at 75°C and 13.8 MPa), and the gas was methane (CP grade, 99 vol% and density 0.0835 g/cm3 viscosity 0.0160 mPa's, at 75°C and 13.8 MPa). Crude oil (Oseberg Field, North Sea) was supplied by Norsk Hydro and cleaned by centrifugation and filtration (0.22 ?m). The viscosity and density of the dead oil at 23°C and ambient pressure were 9.5 mPa's and 0.87 g/cm3 respectively. Methane-saturated oil had a gas/oil ratio of 70 and a density of 0.75 g/cm 3 at 75°C and 13.8 MPa. Corefloods. The core was contained in a stainless-steel core holder within a lead sleeve to which confining pressure (24 MPa) was applied. Liquids were injected by displacement from floating piston vessels using HPLC pumps. Methane was supplied either from a cylinder, its flow rate being controlled by a mass flow controller, or from a Ruska pump. System pressure was controlled by a gas dome-type backpressure regulator. Pressure drops across the whole core and across the outlet half were monitored by differential pressure transducers. The half-core pressure drops were consistently about 70% of the full-core pressure drops, possibly because of capillary end effects or changing flow rates and foam qualities caused by gas expansion during flow through the core. Materials. Cores were either Berea sandstone (length 30 cm, diameter 3.8 cm, porosity 23%, and absolute permeability to air 940 to 1,200 md), or reservoir sandstone (length 17 cm, diameter 3.7 cm, porosity 26%, and absolute permeability to air 3,400 to 3,900 md) from the Oseberg field (North Sea), supplied by Norsk Hydro. The reservoir cores were extracted in a chloroform/methanol mixture and dried before use. Four commercial surfactants were used: Chaser GR-1080 (Chaser International, proprietary blend containing mostly alpha olefin sulfonates), Enordet X-2001 (Shell Chemical Company, alcohol ethoxyglycerylsulfonate), Dow XSS-84321.05 (Dow Chemical, mixture of C10 diphenyletherdisulfonate and C 14-16 alpha olefin sulfonate), and Fluorad FC-751 (3M Company, fluoroalkylsulfobetaine). They will be referred to as Chaser, Enordet, Dow, and Fluorad in this paper. Cited concentrations are active concentrations in %w/v in sea water. The three hydrocarbon-based surfactants (Chaser, Enordet, and Dow) were used either by themselves or mixed with Fluorad (1:9 by mass Fluorad to Chaser, Enordet, or Dow). The brine was filtered (0.45 ?m) synthetic sea water (density 1.004 g/cm 3 and viscosity 0.38 mPa's, at 75°C and 13.8 MPa), and the gas was methane (CP grade, 99 vol% and density 0.0835 g/cm3 viscosity 0.0160 mPa's, at 75°C and 13.8 MPa). Crude oil (Oseberg Field, North Sea) was supplied by Norsk Hydro and cleaned by centrifugation and filtration (0.22 ?m). The viscosity and density of the dead oil at 23°C and ambient pressure were 9.5 mPa's and 0.87 g/cm3 respectively. Methane-saturated oil had a gas/oil ratio of 70 and a density of 0.75 g/cm 3 at 75°C and 13.8 MPa.
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Mohd, T. A. T., N. Alias, N. A. Ghazali, E. Yahya, A. Sauki, A. Azizi, and Noorsuhana Mohd Yusof. "Mobility Investigation of Nanoparticle-Stabilized Carbon Dioxide Foam for Enhanced Oil Recovery (EOR)." Advanced Materials Research 1119 (July 2015): 90–95. http://dx.doi.org/10.4028/www.scientific.net/amr.1119.90.
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Enhanced oil recovery (EOR) can extend the life of an oil field by providing additional drive mechanism to the crude oil. The use of carbon dioxide (CO2) in EOR application has shown a good potential, but it has some weaknesses such as viscous fingering. Viscous fingering problem can be solved by reducing the CO2gas mobility, which can be achieved by transforming the CO2gas into surfactant-stabilized foam. However, surfactant-stabilized foam is not very stable under harsh reservoir condition, which could be handled by introducing nanoparticle-stabilized CO2foam. Thus, this paper aims to investigate the mobility of nanoparticle-stabilized CO2foam at varying brine salinity (1 - 4 wt%), concentration of AOS surfactant (0.01 - 1 wt%) and concentration of nanoparticle (0.05 - 1 wt%). The volumetric phase ratio was fixed at 8 CO2/aqueous. The sand pack foam flooding test was conducted to measure the effectiveness of the formulated foam to displace the oil inside the porous medium through mobility and oil recovery measurement. It was found that foam mobility is inversely proportional to oil recovery. Mobility decreased when increase of brine salinity, surfactant and nanoparticle concentration, which has increased the oil recovery. Thus, it is important to reduce the foam mobility for efficient displacement process, which could minimize viscous fingering and enhance the oil recovery. This could be achieved by increasing the viscosity of displacing fluid (foam) for more stable displacement in EOR application.
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Hussain, A. A. A., S. Vincent-Bonnieu, R. Z. Kamarul Bahrim, R. M. Pilus, and W. R. Rossen. "The impacts of solubilized and dispersed crude oil on foam in a porous medium." Colloids and Surfaces A: Physicochemical and Engineering Aspects 579 (October 2019): 123671. http://dx.doi.org/10.1016/j.colsurfa.2019.123671.
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Liu, Xiaomin, Zhao Chen, and Zhenggang Cui. "Synergistic Effects between Anionic and Sulfobetaine Surfactants for Stabilization of Foams Tolerant to Crude Oil in Foam Flooding." Journal of Surfactants and Detergents 24, no. 4 (March 13, 2021): 683–96. http://dx.doi.org/10.1002/jsde.12501.
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Medjahdi, M., N. Benderdouche, B. Bestani, L. Duclaux, and L. Reinert. "Modeling of the sorption of crude oil on a polyurethane foam-powdered activated carbon composite." Desalination and Water Treatment 57, no. 47 (January 13, 2016): 22311–20. http://dx.doi.org/10.1080/19443994.2015.1129511.
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Farzaneh, Seyed Amir, and Mehran Sohrabi. "Experimental investigation of CO2-foam stability improvement by alkaline in the presence of crude oil." Chemical Engineering Research and Design 94 (February 2015): 375–89. http://dx.doi.org/10.1016/j.cherd.2014.08.011.
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Gao, Xuedong, Qiyu Huang, Xun Zhang, Yu Zhang, Xiangrui Zhu, and Jinxu Shan. "Experimental study on the wax removal physics of foam pig in crude oil pipeline pigging." Journal of Petroleum Science and Engineering 205 (October 2021): 108881. http://dx.doi.org/10.1016/j.petrol.2021.108881.
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Singh, Robin, and Kishore K. Mohanty. "Foams Stabilized by In-Situ Surface-Activated Nanoparticles in Bulk and Porous Media." SPE Journal 21, no. 01 (February 18, 2016): 121–30. http://dx.doi.org/10.2118/170942-pa.
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Summary Foams for subsurface applications are traditionally stabilized by surfactants. The goal of this work is to study foam stabilization by nanoparticles—in particular, by in-situ surface-hydrophobization of hydrophilic nanoparticles. The interfacial properties of the nanoparticles were modulated by the attachment of short-chain surface modifiers (alkyl gallates) that render them partially hydrophobic, but still fully dispersible in water. First, static foams were generated with nanoparticles with varying concentrations of surface modifiers. The decay of foam height with time was measured, and half-lives were determined. Optical micrographs of foam stabilized by surface-modified nanoparticles (SMNPs) and surfactant were recorded. Second, aqueous foams were created in-situ by coinjecting the SMNP solutions with nitrogen gas through a Berea sandstone core at a fixed quality. Pressure drop across the core was measured to estimate the achieved resistance factor. These pressure-drop results were then compared with those of a typical surfactant (alpha olefin sulfonate, alkyl polyglucoside) under similar conditions. Finally, oil-displacement experiments were conducted in Berea cores with surfactant and SMNP solutions as foaming agents (coinjection with nitrogen gas). A Bartsch shake test revealed the strong foaming tendency of SMNPs even with a very low initial surface-modifier concentration (0.05 wt%), whereas hydrophilic nanoparticles alone could not stabilize foam. The bubble texture of foam stabilized by SMNPs was finer than that with surfactants, indicating a stronger foam. As the degree of surface coating increased, the resistance factor of SMNP foam in a Berea core increased significantly. The corefloods in the sandstone cores with a reservoir crude oil showed that immiscible foams with SMNP solution can recover a significant amount of oil (20.6% of original oil in place) over waterfloods.
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Supriya, Prabhavathi, and Kandikere R. Sridhar. "Proximal and Functional Properties of Edible Ripened Split Beans of Coastal Wild Legume Canavalia maritima." Current Nutrition & Food Science 15, no. 3 (April 25, 2019): 228–33. http://dx.doi.org/10.2174/1573401313666171004150447.
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Background: Utilization of wild legumes has received prime importance in the recent past to compensate the scarcity of protein-rich foods as well as to tackle the protein energy malnutrition. Ripened split beans of Canavalia maritima devoid of seed coat and testa serve as traditional nutraceutical source for the coastal dwellers of Southwest India. Objective: The present study projects proximal and functional attributes of uncooked and cooked ripened split beans of C. maritima to be used in the preparation of functional foods. Methods: Proximal properties (moisture, crude protein, total lipids, crude fibre, carbohydrates and calorific value) and functional properties (protein solubility, gelation capacity, water-absorption, oilabsorption, emulsion qualities and foam qualities) of split beans were evaluated by standard methods. Results: Cooking did not significantly changed the crude protein, total lipids, ash, carbohydrates and calorific value, while it significantly increased the crude fibre. The protein solubility, water-absorption capacity, foam capacity and foam stability were significantly higher in uncooked than cooked beans. The cooked beans were superior to uncooked beans in least gelation concentration, low oil-absorption capacity, emulsion activity and emulsion stability. Conclusion: The functional properties of split bean flours were influenced by the proximal components like crude protein, total lipids and crude fibre. The energy-rich ripened split beans of C. maritima can serve as a new potential source for production of value added functional foods owing to their rich protein, rich carbohydrates, low-lipid and potential bioactive attributes.
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Alcorn, Zachary Paul, Sunniva B. Fredriksen, Mohan Sharma, Tore Føyen, Connie Wergeland, Martin A. Fernø, Arne Graue, and Geir Ersland. "Core-scale sensitivity study of CO2 foam injection strategies for mobility control, enhanced oil recovery, and CO2 storage." E3S Web of Conferences 146 (2020): 02002. http://dx.doi.org/10.1051/e3sconf/202014602002.
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This paper presents experimental and numerical sensitivity studies to assist injection strategy design for an ongoing CO2 foam field pilot. The aim is to increase the success of in-situ CO2 foam generation and propagation into the reservoir for CO2 mobility control, enhanced oil recovery (EOR) and CO2 storage. Un-steady state in-situ CO2 foam behavior, representative of the near wellbore region, and steady-state foam behavior was evaluated. Multi-cycle surfactant-alternating gas (SAG) provided the highest apparent viscosity foam of 120.2 cP, compared to co-injection (56.0 cP) and single-cycle SAG (18.2 cP) in 100% brine saturated porous media. CO2 foam EOR corefloods at first-contact miscible (FCM) conditions showed that multi-cycle SAG generated the highest apparent foam viscosity in the presence of refined oil (n-Decane). Multi-cycle SAG demonstrated high viscous displacement forces critical in field implementation where gravity effects and reservoir heterogeneities dominate. At multiple-contact miscible (MCM) conditions, no foam was generated with either injection strategy as a result of wettability alteration and foam destabilization in presence of crude oil. In both FCM and MCM corefloods, incremental oil recoveries were on average 30.6% OOIP regardless of injection strategy for CO2 foam and base cases (i.e. no surfactant). CO2 diffusion and miscibility dominated oil recovery at the core-scale resulting in high microscopic CO2 displacement. CO2 storage potential was 9.0% greater for multi-cycle SAGs compared to co-injections at MCM. A validated core-scale simulation model was used for a sensitivity analysis of grid resolution and foam quality. The model was robust in representing the observed foam behavior and will be extended to use in field scale simulations.
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Jian, Guoqing, Zachary Alcorn, Leilei Zhang, Maura C. Puerto, Samaneh Soroush, Arne Graue, Sibani Lisa Biswal, and George J. Hirasaki. "Evaluation of a Nonionic Surfactant Foam for CO2 Mobility Control in a Heterogeneous Carbonate Reservoir." SPE Journal 25, no. 06 (September 9, 2020): 3481–93. http://dx.doi.org/10.2118/203822-pa.
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Summary In this paper, we describe a laboratory investigation of a nonionic surfactant for carbon dioxide-(CO2-) foam mobility control in the East Seminole field, a heterogeneous carbonate reservoir in the Permian Basin of west Texas. A method of high-performance liquid chromatography-evaporativelight-scattering detector (HPLC-ELSD) was followed for characterizing the surfactant stability. The foam transport process was studied in the absence and the presence of East Seminole crude oil, with test results showing that strong CO2-foam forms in either a bulk-foam test or foam-flow test. An oxygen scavenger, carbohydrazide, was found effective for controlling the stability of the surfactant up to 80°C and total dissolved solid of ∼34,000 ppm. Moreover, a phosphonate scale inhibitor was investigated and found to be compatible with the oxygen scavenger to accommodate a surfactant solution in a gypsum-oversaturated reservoir brine. During the oil-fractional flow test, an emulsion appears to form, causing a noticeable pressure increase; however, emulsion generation failed to cause a significant phase plugging in the test. Also, a STARS™ (Computer Modelling Group Ltd., Calgary, Alberta, Canada) foam model was applied to obtain the foam parameters from the foam-flow experiments at steady-state conditions. The insights from laboratory experiments better enable translation of the foam technology to the field.
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Dong, Pengfei, Maura Puerto, Guoqing Jian, Kun Ma, Khalid Mateen, Guangwei Ren, Gilles Bourdarot, et al. "Low-IFT Foaming System for Enhanced Oil Recovery in Highly Heterogeneous/Fractured Oil-Wet Carbonate Reservoirs." SPE Journal 23, no. 06 (August 29, 2018): 2243–59. http://dx.doi.org/10.2118/184569-pa.
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Summary Oil recovery in heterogeneous carbonate reservoirs is typically inefficient because of the presence of high-permeability fracture networks and unfavorable capillary forces within the oil-wet matrix. Foam, as a mobility-control agent, has been proposed to mitigate the effect of reservoir heterogeneity by diverting injected fluids from the high-permeability fractured zones into the low-permeability unswept rock matrix, hence improving the sweep efficiency. This paper describes the use of a low-interfacial-tension (low-IFT) foaming formulation to improve oil recovery in highly heterogeneous/fractured oil-wet carbonate reservoirs. This formulation provides both mobility control and oil/water IFT reduction to overcome the unfavorable capillary forces preventing invading fluids from entering an oil-filled matrix. Thus, as expected, the combination of mobility control and low-IFT significantly improves oil recovery compared with either foam or surfactant flooding. A three-component surfactant formulation was tailored using phase-behavior tests with seawater and crude oil from a targeted reservoir. The optimized formulation simultaneously can generate IFT of 10−2 mN/m and strong foam in porous media when oil is present. Foam flooding was investigated in a representative fractured core system, in which a well-defined fracture was created by splitting the core lengthwise and precisely controlling the fracture aperture by applying a specific confining pressure. The foam-flooding experiments reveal that, in an oil-wet fractured Edward Brown dolomite, our low-IFT foaming formulation recovers approximately 72% original oil in place (OOIP), whereas waterflooding recovers only less than 2% OOIP; moreover, the residual oil saturation in the matrix was lowered by more than 20% compared with a foaming formulation lacking a low-IFT property. Coreflood results also indicate that the low-IFT foam diverts primarily the aqueous surfactant solution into the matrix because of (1) mobility reduction caused by foam in the fracture, (2) significantly lower capillary entry pressure for surfactant solution compared with gas, and (3) increasing the water relative permeability in the matrix by decreasing the residual oil. The selective diversion effect of this low-IFT foaming system effectively recovers the trapped oil, which cannot be recovered with single surfactant or high-IFT foaming formulations applied to highly heterogeneous or fractured reservoirs.
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Thi Quynh Hoa, Kieu, Nguyen Vu Giang, Nguyen Thi Yen, Mai Duc Huynh, Nguyen Huu Dat, Vuong Thi Nga, Nguyen Thi Thu Ha, and Pham Thi Phuong. "Enhanced bioremediation of crude oil polluted water by a hydrocarbon-degrading Bacillus strain immobilized on polyurethane foam." Vietnam Journal of Biotechnology 18, no. 3 (November 28, 2020): 581–88. http://dx.doi.org/10.15625/1811-4989/18/3/15714.
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During the production and transportation of petroleum hydrocarbons, unsuitable operation and leakage may result in contamination of water and soil with petroleum hydrocarbons. Petroleum contamination causes significant marine environmental impacts and presents substantial hazards to human health. Bioremediation of contaminated water and soil is currently the effective and least harmful method of removing petroleum hydrocarbons from the environment. To improve the survival and retention of the bioremediation agents in the contaminated sites, microbial cells must be immobilized. It was demonstrated that immobilized microbial cells present advantages for degrading petroleum hydrocarbon pollutants compared to free suspended cells. In this study, the ability of a Bacillus strain (designed as Bacillus sp. VTVK15) to immobilize on PUF and to degrade crude oil was investigated. The immobilized Bacilllus strain had the highest number (5.38 ± 0.12 Í 108 CFU/g PUF) and a maximum attachment efficiency of 92% on PUF after 8 days. Analysis by GC-MS revealed that both free and immobilized cells of Bacillus sp. VTVK15 were able to degrade 65 and 90% of the hydrocarbons in 2% (v/v) crude oil tested after 14 days, respectively. The results suggest the potential of using PUF-immobilized Bacillus sp. VTVK15 to bioremediate petroleum hydrocarbons in an open marine environment.
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Van Nguyen, Quynh, Yeon Seok Choi, Sang Kyu Choi, Yeon Woo Jeong, and Yong Su Kwon. "Improvement of bio-crude oil properties via co-pyrolysis of pine sawdust and waste polystyrene foam." Journal of Environmental Management 237 (May 2019): 24–29. http://dx.doi.org/10.1016/j.jenvman.2019.02.039.
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Dong, Pengfei, Maura C. Puerto, Kun Ma, Khalid Mateen, Guangwei Ren, Gilles Bourdarot, Danielle Morel, Sibani Lisa Biswal, and George J. Hirasaki. "Ultralow-Interfacial-Tension Foam-Injection Strategy in High-Temperature Ultrahigh-Salinity Fractured Oil-Wet Carbonate Reservoirs." SPE Journal 24, no. 06 (August 8, 2019): 2822–40. http://dx.doi.org/10.2118/190259-pa.
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Summary Oil recovery in many carbonate reservoirs is challenging because of unfavorable conditions, such as oil–wet surface wettability, high reservoir heterogeneity, and high brine salinity. We present the feasibility and injection–strategy investigation of ultralow–interfacial–tension (IFT) foam in a high–temperature (greater than 80°C), ultrahigh–formation–salinity [greater than 23% total dissolved solids (TDS)] fractured oil–wet carbonate reservoir. Because a salinity gradient is generated between injection seawater (SW) (4.2% TDS) and formation brine (FB) (23% TDS), a frontal–dilution map was created to simulate frontal–displacement processes and thereafter it was used to optimize surfactant formulations. IFT measurements and bulk–foam tests were also conducted to study the salinity–gradient effect on the performance of ultralow–IFT foam. Ultralow–IFT foam–injection strategies were investigated through a series of coreflood experiments in both homogeneous and fractured oil–wet core systems with initial oil/brine two–phase saturation. The representative fractured system included a well–defined fracture by splitting the core sample lengthwise. A controllable initial oil/brine saturation in the matrix can be achieved by closing the fracture with a rubber sheet at high confining pressure. The surfactant formulation achieved ultralow IFT (magnitude of 10−2 to 10−3 mN/m) with the crude oil at the displacement front and good foamability at underoptimal conditions. Both ultralow–IFT and foamability properties were found to be sensitive to the salinity gradient. Ultralow–IFT foam flooding achieved more than 50% incremental oil recovery compared with waterflooding in fractured oil–wet systems because of the selective diversion of ultralow–IFT foam. This effect resulted in a crossflow near the foam front, with surfactant solution (or weak foam) primarily diverted from the fracture into the matrix before the foam front, and oil/high–salinity brine flowing back to the fracture ahead of the front. The crossflow of oil/high–salinity brine from the matrix to the fracture was found to create challenges for foam propagation in the fractured system by forming Winsor II conditions near the foam front and hence killing the existing foam. It is important to note that Winsor II conditions should be avoided in the ultralow–IFT foam process to ensure good foam propagation and high oil–recovery efficiency. Results in this work contributed to demonstrating the technical feasibility of ultralow–IFT foam in high–temperature, ultrahigh–salinity fractured oil–wet carbonate reservoirs and investigated the injection strategy to enhance the low–IFT foam performance. The ultralow–IFT formulation helped to mobilize the residual oil for better displacement efficiency and reduce the unfavorable capillary entry pressure for better sweep efficiency. The selective diversion of foam makes it a good candidate for a mobility–control agent in a fractured system for better sweep efficiency.
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Wojcieszak, Łukasz. "Expansion of the Oil Terminal in Gdańsk – Outlook and Benefits for the Oil Security of Poland." Security Dimensions 34, no. 34 (December 4, 2020): 186–200. http://dx.doi.org/10.5604/01.3001.0014.5610.
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The paper shows the role of and the outlooks for the extension of Naftoport Oil Terminal in Gdańsk, Poland as well as the impact of the ongoing development on oil import options and, as a result, on the oil security of the country. The expansion of the oil terminal in Gdańsk is an extremely important project and the largest investment of this type in Poland. Key elements of the development of the terminal are: new transshipment stations and their enhancement, new oil tanks, the construction of the second oil pipeline running to the center of Poland, the development of crude oil technological installations, electricity grid, water and foam networks, sanitary networks, roads, and automation systems. The expansion of Naftoport significantly increases Poland’s oil security as well as import capabilities of the country, ensuring continuous oil supplies to Polish refineries, often at a lower price.
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Salman, Mohamad, Konstantinos Kostarelos, Pushpesh Sharma, and Jae Ho Lee. "Application of Miscible Ethane Foam for Gas EOR Conformance in Low-Permeability Heterogeneous Harsh Environments." SPE Journal 25, no. 04 (May 22, 2020): 1871–83. http://dx.doi.org/10.2118/201189-pa.
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Summary Unconventional plays pose a challenging set of operational conditions, including high temperature, high salinity, low permeability, and fracture networks. Aggressive development of these plays and the low primary recovery factors present an opportunity for using enhanced oil recovery (EOR) methods. This work presents a laboratory investigation of miscible ethane (C2H6) foam for gas EOR conformance in low-permeability, heterogeneous, harsh environments [<15 md, 136,000 ppm total dissolved solids (TDS) with divalent ions, 165°F]. The use of C2H6 as an alternative to carbon dioxide (CO2) offers several operational and availability strengths, which might expand gas EOR applications to depleted or shallower wells. Coupling gas conformance also helps improve displacement efficiencies and maximize overall recovery. Minimum miscibility pressure (MMP) displacement tests were performed for dead crude oil from the Wolfcamp Spraberry Trend area using C2H6 and CO2. Aqueous stability, salinity scan, and static foam tests were performed to identify a formulation. Subsequent foam quality and coreflood displacement tests in heterogeneous carbonate outcrop cores were conducted to compare the recovery efficiencies of three processes: gravity-unstable, miscible C2H6 foam; gravity-stable, miscible C2H6; and gravity-unstable, miscible C2H6 processes. Slimtube tests comparing C2H6 to CO2 resulted in a lower MMP value for C2H6. We identified a stable surfactant blend capable of Type I microemulsion and persistent foams in the presence of oil. Corefloods conducted with gravity-unstable miscible C2H6 foam, gravity-stable miscible C2H6, and gravity-unstable miscible C2H6 recovered 98.4, 61.9, and 42.6% oil originally in place, respectively. Our work shows that miscible C2H6 injection processes achieved significant recoveries even under gravity-unstable conditions. The addition of foam provides better conformance control, enhancing overall recovery at the laboratory scale, showing promise for field applications.