• Om Bhavsar
• Mrs.Ujjwala Gaikwad
• Samay Duge
• Rohan Shinde
• Suyash Khaire

whe'use'of'foams'is'a'promising'technique'to'overcome'gas'mobility'challenges'in'petroleum'reservoirsA'Koam'reduces'the' gas'mobility'by'increasing'the'gas'apparent'viscosity'and'reducing'its'relative'permeabilityA'C'major'challenge'facing'foam' application'in'reservoirs'is'its'long-term'stabilityA'Koam'eectiveness'and'stability'depends'on'several'factors'and'ill'typi - cally'diminish'over'time'due'to'degradation'as'ell'as'the'foam-rock-oil'interactionsA'In'this'study,'the'eect'of'crude'oil'on' ' OF2 -foam'stability'and'mobility'ill'be'investigated'using'in - house'build'microuidics'system'developed'for'rapid'precedent - in'of'chemical'formulations'wo-phase'o'emulsication'test'(oil - surfactant'solutions)'and'dynamic'foam'tests'(in'the' absence'and'presence'of'crude'oil)'are'conducted'to'perform'a'comparative'assessment'for'dierent'surfactant'solutions' C'microuidics'device'as'used'to'evaluate'the'foam'strength'in'the'presence'and'absence'of'crude'oil'the'assessment'as' conducted'using've'surfactant'formulations'and'dieren'oil'fractions'the'role'of'foam'quality'(volume'of'gas / total'vol - ume)'on'foam'stability'as'also'addressed'in'this'study'the'mobility'reduction'factor'(MARK)'for' 'OF 2 -foam'as'measured' in'the'absence'and'presence'of'crude'oil'using'high'salinity'ater'and'at'elevated'temperatures'the'results'indicated'that' foam'stability'has'an'inverse'relationship'with'the'amount'of'crude'oil'Crude'oil'has'a'detrimental'erect'on'foams,'and'foam' stability'decreased'as'the'amount'of'crude'oil'as'increased'Depending'on'the'surfactant'type,'the'existence'of'crude'oil'in' porous'media,'even'at'very'low'concentrations'of'5%'can'significantly'impact'the'foam'stability'and'strength'the'oil'can'act' as'an'antifoaming'agentS'It'enters'the'thin'aqueous'lm'and'destabilize'itA'this'resulted'in'a'lower'foam'viscosity'and'less' stable'foams'thus,'the' 'FO 2 'MR'dropped'significantly'in'the'presence'of'higher'oil'fractions'this'study'also'demonstrated' that'in-house'assembled'microuidics'system'allows'for'a'rapid'and'cost - ecient'screening'of'formulations Keywords 'Microuidics*'FO2 'foam*'Rapid'prescreening*'Surfactants Introduction Gas'injection'is'one'of'the'most'promising'techniques'in' enhanced'oil'recovery'(FOR)'processes'(Madathilet'alA' 2015 )A'Gas'injection'can'aid'in'maximizing'the'oil'recovery' when'the'injected'gas'becomes'miscible'with'the'reservoir' hydrocarbons'(Wharton'and'Tieschnick' 1950 )A'the'most' common'was'used'for'this'purpose'is'carbon'dioxide' '(TO 2 )' as'it'has'to'miscibility'pressure'promoting'the'selling' of'crude'oil,'and'reducing'its'viscosity'and,'consequently,'enhancing'the'oil'recovery'(Slobod'and'Touch'1953)A'While' ' FOR 2 'injection'has'been'successful'(Holland'etalA' 1986 ;' Brock'and'Bryan' 1989 )'in'mobilizing'significant'amounts' of'residual'oil,'the'poor'volumetric'seep'science'is'a' major'challenge'associated'with'this'technique' 'OF 2 'has'a' lo'viscosity'and'density'compared'to'the'reservoir'uids' causing'the'challenges'of'gravity'override'and'viscous'n - bering,'which'lead'to'poor'seep'science'(Campbell'etalA' 1985 ;'Fhakravarthy'etalA'2004;'Masalmeh'tala'2010)A Several'methods'have'been'studied'and'tested'to'over- come'the' 'FO2 'mobility'challenge'including'ater'alternating' gas'(BCG),'in-situ'foam'generation,'and'using'thickeners'to' increase'the'gas'viscosity'(Heller'etalA' 1985 ,'Dandge'and' Heller'1987,'Heller'1994,'Nick'1998,'Huang'etalA'2000,' Fhakravarthy'etalA' 2004 ,'Hamilton' 2004 ,'YoUrself'tala' 2019a ,'b)A'One'of'the'widely'used'techniques'to'overcome' the'gas'mobility'challenge'is'the'in-situ'generation'of'foam' '*'Carat'Gizzatov' ' FO 2 'Cramco'Americas:'Cramco'Research'Center-Boston,'400' technology'Square,'Cambridge,'MC02139,'USC Journal of Petroleum Exploration and Production Technology 1 3 Foam can help in reducing gas mobility by increasing the apparent viscosity of the gas and reducing its relative per- meability, thereby improving the gas volumetric sweep e - ciency. (Kovscek and Radke 1994; Falls et al. 1988). Foam is commonly generated using surfactants. How- ever, one of the challenges of using foam generated by surfactants is its long-term stability. Foam stability at res - ervoir conditions can be aected by many factors includ - ing water salinity, reservoir temperature, adsorption of surfactant molecules on rock surfaces, degradation of surfactants, and uid–uid interactions (Mannhardt et al. 1993 ; Yaghoobi 1994 ; Grigg et al. 2004 ; Liu et al. 2005 ; Staszak et al. 2015; Nazari et al. 2017; Skauge et al. 2019; AlYousef et al. 2019a , b). Moreover, the stability of foam can diminish over time due to foam–oil interactions. The oil can act as an antifoaming agent, it enters the thin aque - ous lms. destabilizes and destroys the lm. (Nikolov et al. 1986 ; Manlowe and Radke 1990 ; Schramm and Novosad 1990 ; AlYousef et al. 2017 ). Depending on the surfactant type, the existence of crude oil in porous media, even at very low concentrations, can signicaly impact the foam stability and its strength. The objective of this work is to evaluate the impact of crude oil on foam stability using a custom-made high pressure and high temperature microfluidics system. Microfluidic technology has provided significant ben - efits in research and industry across various fields, with a growing track of applications in industrial fluids and chemistries (Saeed et al. 2021). This work demonstrates the utilization of a microfluidic reservoir analogue and presents an approach to rapidly screen and evaluate CO 2 foam formulations in the presence of crude oil at a high- temperature (100 °C) condition. Five surfactant solutions were used in this study. Two-phase flow emulsification test (oil-surfactant solutions) and A dynamic foam test (in absence and presence of crude oil) were conducted to perform the comparative assessment among different sur- factant solutions. Moreover, the mobility reduction factor for CO 2 -foam was measured in the absence and presence of crude oil at 100 °C. Materials Five different surfactants were used in this experimental study. Commercially available cocamidopropyl betaine surfactant (Amphosol CG-50), lauramidopropyl betaine surfactant (Amphosol LB), and cocamidopropyl hydrox - ysultaine surfactant (Petrostep-SB) used in this study were from Stepan Company (Northfield, USA). Also, tris(2-hydroxyethyl) n-tallow alkyldiaminopropane sur- factant (Ethoduomeen T/13), and tallow trimethylpro - pylenediamine surfactant (Duomeen TTM) both from AkzoNobel (Amsterdam, The Netherlands) were used in this assessment. Table 1 lists the chemical structure of these surfactants. The synthetic brine used in this study had a total dissolved solid (TDS) content of 57,670 ppm, density of 0.99 g/mL, and viscosity of 0.283 measured at 100 °C. More details of the brine compositions can be found in Table 2. The crude oil used had a density of 0.88 g/mL, average viscosity of 3.2 cP measured at 100 °C, and the gas used for foam generation was CO 2 with 99.5% purity. Methodology The eect of crude oil on foam stability and strength was studied using dynamic foam tests. The major objectives of dynamic foam tests were to ensure the foam formation and to evaluate the eect of crude oil on foam stability and CO 2 mobility in porous media. Several assessments were conducted to ensure the solutions are stable at experimen - tal conditions before conducting the dynamic foam tests. Over twenty surfactants were evaluated, only ve were selected for this assessment. The shortlisted surfactants are stable in high salinity water at a low pH (3.0–3.5) and at 100 °C for over a month. This section describes the procedure used to prepare solutions, measure the oil–water interfacial tension, conduct two-phase emulsication test, and conduct the dynamic foam tests in absence and pres - ence of crude oil. Aqueous phase preparation As received from manufacturers, ve surfactants listed in Table 1 were dissolved in the brine to produce 0.2 wt.% concentrations and tested for stability at 100 °C for over a month. Stability of surfactants was tested at neutral pH and pH (3.0–3.5) to represent conditions present during CO 2 ooding. Surfactant 4 and surfactant 5 are not soluble in brine as is and need to be protonated with acid. Solutions that remained clear, as shown in Fig. 1, without precipitates or phase separation were recorded as stable. There were no tests made for examining decomposition of surfactants. In addition, a bottle-shaking test was conducted after one month to observe if foam was generating. This indicates that surfactant molecules were still present in solutions. Interfacial tension measurements KRÜSS Spinning Drop Tensiometer was used to measure the oil–water interfacial tensions. Five 0.2 wt.% surfactant Journal of Petroleum Exploration and Production Technology 1 3 solutions in brine and with the crude oil as the top phase were rst aged at 90 °C over 24 h. Then corresponding phases were used for interfacial tension measurements. Measurements were conducted at 90 °C to avoid the formation of bubbles. The results were used to better understand the foam stabilization in the presence of the crude oil. Table 1 List of surfactants with depicted chemical structures used in this study Amphosol LB and Amphosol CG-50 have similar structures except that Amphosol LB is made using narrow cut methyl esters and Amphosol CG-50 from rened coconut oil SurfactantCommercial nameChemical structure Surfactant 1Amphosol CG-50 Surfactant 2Amphosol LB Surfactant 3Petrostep® SB Surfactant 4Ethoduomeen T/13 Surfactant 5Duomeen TTM Table 2 Brine composition IonsSymbolSynthetic brine (ppm) SodiumNa + 18,300 CalciumCa 2+ 650 MagnesiumMg 2+ 2,110 SulfateSO 42− 4,290 ChlorideCl − 32,200 BicarbonateHCO 3− 120 TDS57,670 Fig. 1 Example showing photograph of stable solutions in brine at 100 °C for longer than one month. Samples were shaken to show that surfactant molecules are still present and did not decompose com - pletely Journal of Petroleum Exploration and Production Technology 1 3 two-phase emulsication test During the oil eect measurements on foam test, the appar- ent viscosity change of the foam/oil could be caused by competing of foam, emulsion generation, and oil detrimen - tal eect. In eld test, the formation of emulsion during foam ooding is unfavorable as the relative permeability of water and oil could be signicantly reduced which can cause remarkable injectivity issues. Therefore, the emulsication test was conducted by a two-phase (surfactant solution-oil) ow and compared to the two-phase ow of brine-oil. This is part of the work was aimed to exclude the fact that oil-brine emulsion formation can cause high pressure as observed for foam. This assessment was conducted using an in-house developed microuidic device depicted in Fig.2. Uncoated hydrophilic borosilicate glass microuidic chips with uniform network and reported permeability of 2.55 Darcy were purchased from Micronit Microtechnologies (Enschede, The Nether- lands) and used as received. The matrix porosity for a uniform network chip is 52% and the pore volume is 2.1 µL. The dimensions of the chip used are 20 × 10 × 0.02mm. The back pressure of the system was set to 100 psi and experiments were conducted at 100°C. The total injection velocity was set to 640 ft/day. Three oil fractions were used for emulsi - cation tests: 10, 30, and 50%. Dynamic foam test The strength of the CO 2 foams produced using the ve listed surfactants in the absence and presence of crude oil was measured using the microuidic device. The main objec - tive of this test was to study the impact of crude oil on foam stability in the presence of a dierent amount of oil in porous media. The pressure drop across the microuidic chip was recorded for the ve surfactants in the absence and presence of crude oil. The 0.2 wt.% surfactant solutions in brine were prepared as described previously. The back pressure of the system was set to 100 psi and experiments were conducted at 100°C. For each test, the microuidic chip was ushed with several pore volumes of brine to ensure the removal of any trapped air or surfactant inside the system. The baseline experiment was rst conducted by co-injecting CO 2 and brine at the experimental conditions. In the absence of crude oil, one pore volume of surfactant solution in brine was rst injected followed by a co-injection of CO 2 and the surfactant solution. The pressure drop across the chip was measured at dierent foam qualities (volume of gas/total volume): 50, 70, 90, and 95%. The total injection supercial velocity was controlled at 640 ft/day. In the presence of crude oil, the oil fractional ow test was conducted to check the detrimental oil eect on the CO 2 foam stability and strength. The experiment was done with three-phase ow including oil, surfactant solution and CO 2 gas. The total supercial velocity was xed at 640 ft/day and the foam quality was xed at 80%. The oil fractional ow was changing from 2 to 20% and the pressure drop was measured across the microuidic chip. Results anddiscussion The interfacial tension measurements for ve surfactant solutions with the crude oil were conducted at 90°C. The results, as shown in Fig.3, demonstrated that surfactant 4 and surfactant 5 solutions had the lowest interfacial tension KigA ' 2 ' 'Schematic of the microuidic device Journal of Petroleum Exploration and Production Technology 1 3 values followed by surfactant 1 solution. Also, the results revealed that the surfactant 2 solution had the highest interfacial tension value. Compared to the other surfactant solutions, the surfactant 3 solution resulted in a moderate interfacial ten - sion reduction. Interfacial tension values for the brine in the absence of the surfactants was 26.9 mN/m. These values are considered relatively high since the surfactants typically used for oil–water interfacial tension reduction can reduce the interfacial tension values up to around 0.001 mN/m. The two-phase (surfactant solution and oil) ow in porous media was conducted for ve surfactant solutions in addition to the brine solution (SW) alone. For all surfactants used, the pressure drop of two-phase ow (surfactant in brine and crude oil) is lower than that of two-phase ow (brine-crude oil), as shown in Fig. 4. The results indicated that no viscous emulsion was formed with the ve surfactant solutions. This suggests that (surfactant solutions-oil) emulsions should not contribute to enhancement in foam stability or increase in foam viscosity when foam is tested in the presence of crude oil. The viscosity of the generated emulsion, as shown in Fig. 5, increases with oil fraction. According to the interfacial ten - sion measurements reported in Fig. 3, surfactant 5 solution had the lowest interfacial tension value, whereas surfactant 2 solution had the highest interfacial tension value. Amongst the ve tested surfactants, the highest pressure drops were observed when surfactant 5 solution was used. In contrast, the lowest pressure drop values were reported when the sur- factant 2 solution was tested. The CO 2 foam strength produced using ve surfactants was measured using a microuidic device. Steady state pres - sure drop values recorded across the microuidics chip as a result of the generated foam within the porous structure of microuidic chip at dierent qualities are presented in Fig. 6. Higher pressure drops correspond to higher resist- ance to gas ow and, hence, foams with higher viscosity. Compared to the baseline case (brine/CO 2 ), all surfactants were able to generate foam, and this is reected on the recorded pressure drops across the microuidic chip at dierent foam quality. Also, from the data presented in Fig. 6 it can be seen that surfactant 1, surfactant 3, sur- factant 4, and surfactant 5 solutions almost have the same foam strength, same pressure drops observed for dierent foam qualities. Surfactant 2 solution showed the lowest pressure drops compared to the other surfactant solutions. 0.50.70.91.11.31.5 1.7 Surfactant 1Surfactant 2Surfactant 3Surfactant 4Surfactant 5 IFT (mN/m) Fig. 3 Interfacial tension values for 0.2 wt.% surfactant solutions in brine with crude oil at 90 °C 03691215 0102030405 060 Pressure'Drop'(psi) Oil'Kraction'(%) SWSurfactant'1Surfactant'2 Surfactant' 3Surfactant'4Surfactant'5 Fig. 4 Emulsication test at 100 °C, and 100 psi 0123456 Viscosity (cP) 30P% Fig. 5 Emulsication Viscosity measured at 100 °C and at two dier- ent volumetric fractions of the crude oil 05101520 02040608 0100 Pressure Drop (psi) Foam Quality (%) Brine/CO2Surfactant 1Surfactant 2 Surfactant 3Surfactant 4Surfactant 5 Fig. 6 Pressure drops across the microuidic chip when CO 2 is ooded with brine and surfactant solutions at dierent foam qualities, and at 100 °C Journal of Petroleum Exploration and Production Technology 1 3 For most surfactant solutions, the foam strength increased with the foam quality up to 90% quality. Figure 6 also demonstrates that the highest foam strengths for most of the examined surfactants were observed when 90% foam quality was tested. The CO 2 MRF (pressure drop due to foam/pressure drop when brine/CO 2 was injected) for each quality was also cal - culated. Figure 7 reveals that the MRF increases with the foam quality. The highest MRFs for most surfactant solu- tions were reported when foam was tested at 95% foam qual - ity. Even though the pressure drops were a bit higher for the 90% foam quality than that for 95% quality, but since the MRFs were calculated separately for each quality and the pressure drop for the baseline (brine/CO2) was very low at 95% quality, the MRFs at 95% foam quality were show- ing the highest values. For most foam qualities, the highest MRFs were reported when surfactant 1, surfactant 3, sur- factant 4, and surfactant 5 solutions were used. The foam strength in the presence of crude oil was evalu - ated using the abovementioned surfactants at 100 psi and 100 °C. The total supercial velocity was xed at 640 ft/ day due to the limitations of the ow meter and the foam quality was xed at 80%. As shown in Fig. 8, the results of pressure drops across the porous media demonstrate that the presence of crude oil can signicantly impact the foam stability. The eect of crude oil on foam stability was conducted using ve dierent oil fractions: 5, 10, 15, and 20%. Surfactant 1 and surfactant 2 solutions were showing very poor foams in pres - ence of crude oil. The pressure drops across the microuidic chip were lower than that of the baseline experiment (brine/ CO2) at all tested oil fractions. The other three surfactants (surfactant 3, surfactant 4, and surfactant 5) showed bet- ter foam stability with higher pressure drops than that of the baseline experiment up to around 15% of oil fraction. However, very weak unstable foams were observed when the oil fraction exceeded 15%. These results indicate that the presence of crude oil is a very crucial parameter for foam stabilization and proper surfactants should be selected to generate stable foams in the presence of crude oil.Similar to those in the absence of crude oil, the CO 2 MRFs were also calculated in the presence of crude oil. Fig - ure 9 demonstrates that there was no reduction in CO 2 mobil - ity when surfactant 1 and surfactant 2 solutions were used. The results also showed that as the oil fraction increased, the CO 2 MRF decreased. Surfactant 3 and surfactant 4 solutions were showing the highest CO 2 MRF values at 5 and 10% oil fraction. However, the MRFs dropped when higher oil fractions were used. Compared to the other surfactant solutions, the surfactant 1 solution produced relatively stable foams at different foam qualities. However, its ability to stabilize the foam in the presence of crude oil is hindered. This is because of the ability of this solutions to generate an emulsion as it showed the second highest pressure drop for the two-phase ow emulsication test. Although the surfactant 2 solution has comparatively the highest interfacial tension value and the lowest pressure drop during the two-phase emulsication test, there was not much reduction in the CO 2 (MRF) in the presence of crude oil. This is mainly because this solution was not able to generate strong foams in the absence of crude oil. Surfactant 3 and surfactant 4 solutions were showing 0246850709095 MR F Foam Quality (%) Surfactant 5Surfactant 4Surfactant 3Surfactant 2Surfactant 1 Fig. 7 MRFs at dierent foam qualities, and at 100 °C 05101520 05101520 Pressure'Drop'(psi) Oil'Kraction'(%) Brine/FO2Surfactant'1Surfactant'2 Surfactant'3Surfactant'4Surfactant'5 Fig. 8 Pressure drops across microuidic chip when CO 2 is ooded with brine and surfactant solutions at dierent oil fractions, and at 100 °C 00.511.522.535101520 MR F Oil Fraction (%) Surfactant 5Surfactant 4Surfactant 3Surfactant 2Surfactant 1 Fig. 9 Calculated MRF at dierent oil fractions, and at 100 °C Journal of Petroleum Exploration and Production Technology 1 3 relatively stable foam in the absence and presence of crude oil with fractions of up to 15%. The results of the two-phase emulsication tests for these two surfactants showed moder- ate pressure drops across the microuidic chip compared to the other surfactant solutions. Surfactant 5 solution showed the lowest interfacial tension reduction amongst the other surfactants, and this was in agreement with the two-phase emulsication test where it showed the highest pressure drop compared to the other surfactants due to the formation of emulsion. Even though the surfactant 5 solution was able to reduce the CO 2 MRF in the absence of crude oil, the ability of this surfactant to create an emulsion resulted in weaker foam stabilization in the presence of crude oil. Conclusions In this study, a custom-made high pressure and high tem - perature microuidics system was used to rapidly evaluate the eect of crude oil on foam stability and strength. Two- phase ow emulsication test (surfactant solutions-oil) and dynamic foam tests (in the absence and presence of crude oil) were conducted. The results demonstrated that: • Four of the tested surfactants were able to generate foam using 0.2 wt.% surfactant in high salinity brine (57,670 ppm) and at high temperature (100 °C). • There is a good agreement between the results obtained from the two-phase emulsification tests with those obtained from the dynamic foam tests in presence of crude oil. • Depending on the surfactant type, the existence of crude oil in porous media, even at very small concentrations of 5%, can signicantly impact the foam stability and strength, and hinder the ability of the surfactant to reduce the CO 2 mobility. • None of the tested surfactants were able to stabilize the foam and reduce the CO 2 mobility when the amount of crude oil exceeded 10%. ions.

Antifoaming agents, Defoaming, AppliedChemistry, Polymers

"Antifoaming agents", International Journal of Emerging Technologies and Innovative Research (www.jetir.org), ISSN:2349-5162, Vol.10, Issue 2, page no.c241-c244, February-2023, Available :http://www.jetir.org/papers/JETIR2302235.pdf

"Antifoaming agents", International Journal of Emerging Technologies and Innovative Research (www.jetir.org | UGC and issn Approved), ISSN:2349-5162, Vol.10, Issue 2, page no. ppc241-c244, February-2023, Available at : http://www.jetir.org/papers/JETIR2302235.pdf