اثر شوری و نوع نمک بر زمان ادغام قطرات نفت در روش ازدیاد برداشت با آب کم‌شور

نوع مقاله : مقاله پژوهشی

نویسندگان

دانشکده مهندسی شیمی و نفت، دانشگاه صنعتی شریف، تهران، ایران

10.22078/pr.2023.5235.3321

چکیده

مکانیزم‌های دخیل در ازدیاد برداشت با آب کم شور به دو دسته کلی سیال-سیال و سنگ-سیال تقسیم‌بندی می‌شوند. از این میان، برهم‌کنش‌های سیال-سیال کمتر در مقالات مورد بررسی قرار گرفته اند. یکی از اثرات این برهم‌کنش‌ها حفظ و یا افزایش پیوستگی فاز نفت است که موجب بالارفتن تراوایی نسبی فاز نفت و تولید بهتر آن از مخزن می‌گردد. در این پژوهش برای فهم عمیق‌تر این اثرات و مقیاس زمانی اثر آنها، پدیده به‌هم‌آمیختگی دو قطره نفت در مجاورت شورآب بررسی شده است. برای مطالعه این پدیده دستگاه و روش جدید آزمایشگاهی توسعه داده شد. طبق این روش ابتدا دو قطره نفت (یکی از بالا و یکی از پایین) در مجاورت شورآب مورد نظر به‌حالت تعلیق درآمده و پس از پیرسازی، به‌هم نزدیک شده و در تماس با یکدیگر قرار می‌گیرند. پس از تماس مدتی طول می‌کشد تا قطرات ادغام شوند که به‌عنوان "زمان ادغام" ثبت می شود. براساس نتایج به‌دست آمده، مدت زمان به‌هم‌آمیختگی دو قطره نفت با افزایش زمان پیرسازی افزایش می‌یابد و پس از min 15 تقریبا ثابت می‌ماند. همچنین زمان ادغام دو قطره نفت رفتاری غیریکنوا با شوری از خود نشان می‌دهد و در یک شوری میانی به حداکثر میزان خود می‌رسد. حداکثر زمان ادغام در قدرت یونی کمتری در شورآب‌های شامل نمک‌های دو ظرفیتی مانند کلسیم، منیزیم و سولفات نسبت به نمک‌های تک ظرفیتی می‌رسد که این مقادیر برای شورآب‌های سدیم کلرید، منیزیم کلرید، کلسیم کلرید و سولفات سدیم به‌ترتیب در غلظت‌های 5/0، 05/0، 05/0، 01/0 مولار می‌باشند. نتایج این مطالعه پیش‌بینی می‌کند که مقدار بهینه شوری برای اثرات سیال-سیال در تزریق آب کم شور در افزایش برداشت نفت وجود خواهد داشت که نیازمند انجام تست‌های سیلاب‌زنی برای تایید می‌باشد.

کلیدواژه‌ها

موضوعات

عنوان مقاله [English]

The Effect of Salinity and Salt Type on the Coalescence Time of Oil Droplets in Low-salinity Enhanced Oil Recovery

نویسندگان [English]

  • Mehran Karimpour Khamaneh
  • Hassan Mahani
Department of Chemical and Petroleum Engineering, Sharif University of Technology, Tehran, Iran
چکیده [English]

The mechanisms that enhance oil recovery through low-salinity waterflooding can be categorized into two main groups: fluid-fluid interactions and rock-fluid interactions. Fluid-fluid interactions have been less explored in the existing literature. One significant effect of these interactions is the maintenance or increase of oil phase connectivity, which boosts the relative permeability and production rate of oil from the reservoir. This research aims to deepen the understanding of these effects and their time scales by examining the coalescence of two adjacent oil droplets in presence of saline water. A novel device and method were developed in this study. In this method, two oil droplets (one hanging from the top and one from the bottom) are placed near the desired brine. After an aging period, they are brought together to initiate contact. The time it takes for the droplets to merge, known as the “coalescence time,” is recorded. The results show that coalescence time increases with aging time, however starts to stabilize after about 15 minutes. Additionally, the coalescence time of two oil droplets exhibits a nonmonotonic relationship with salinity, peaking at an intermediate salinity level. The maximum coalescence time occurs at lower ionic strengths in brines with divalent salts like calcium, magnesium, and sulfate compared to monovalent salts. The specific values for sodium chloride, magnesium chloride, calcium chloride, and sodium sulfate brines are 0.5, 0.05, 0.05, and 0.01 M, respectively. Ultimatly, this study indicates that there is an optimal salinity for the fluid-fluid effects in low-salinity waterflooding, and understanding these effects on oil recovery necessitates further waterflooding experiments.

کلیدواژه‌ها [English]

  • Enhanced Oil Recovery
  • Low-salinity Water
  • Droplet Coalescence
  • Viscoelasticity
  • Oil-brine Interface

مراجع

[1]. Green, D.W. and G.P. Willhite (1998) Enhanced oil recovery, 1st. editrion, Henry L. Doherty Memorial Fund of AIME, Society of Petroleum Engineers, The USA, Texas, Richardson, 6, 1-545. ISBN: 9781555630775. ##
[2]. Mahani, H., & Thyne, G. (2023). Low-salinity (enhanced) waterflooding in carbonate reservoirs. In Recovery Improvement (pp. 39-107). Gulf Professional Publishing. doi.org/10.1016/B978-0-12-823363-4.00007-8. ##
[3]. Morrow, N., & Buckley, J. (2011). Improved oil recovery by low-salinity waterflooding. Journal of Petroleum Technology, 63(05), 106-112. doi.org/10.2118/129421-JPT. ##
[4]. Mahani, H., Keya, A. L., Berg, S., & Nasralla, R. (2017). Electrokinetics of carbonate/brine interface in low-salinity waterflooding: Effect of brine salinity, composition, rock type, and pH on?-potential and a surface-complexation model. SPE Journal, 22(01), 53-68. doi.org/10.2118/181745-PA. ##
[5]. RezaeiDoust, A., Puntervold, T., Strand, S., & Austad, T. (2009). Smart water as wettability modifier in carbonate and sandstone: A discussion of similarities/differences in the chemical mechanisms. Energy & Fuels, 23(9), 4479-4485. doi.org/10.1021/ef900185q. ##
[6]. Mohammadi, M., & Mahani, H. (2020). Direct insights into the pore-scale mechanism of low-salinity waterflooding in carbonates using a novel calcite microfluidic chip. Fuel, 260, 116374. doi.org/10.1016/j.fuel.2019.116374. ##
[7]. Yousef, A. A., Al-Saleh, S., Al-Kaabi, A., & Al-Jawfi, M. (2011). Laboratory investigation of the impact of injection-water salinity and ionic content on oil recovery from carbonate reservoirs. SPE Reservoir Evaluation & Engineering, 14(05), 578-593. doi.org/10.2118/137634-PA. ##
[8]. Xie, Q., Ma, D., Liu, Q., & Lv, W. (2015). Ion tuning waterflooding in low permeability sandstone: Coreflooding experiments and interpretation by thermodynamics and simulation. In Presentation at the International Symposium of the Society of Core Analysts Held in St. John’s Newfoundland and Labrador, Canada (pp. 16-21). ##
[9]. Song, W., & Kovscek, A. R. (2016). Direct visualization of pore-scale fines migration and formation damage during low-salinity waterflooding. Journal of Natural Gas Science and Engineering, 34, 1276-1283. doi.org/10.1016/j.jngse.2016.07.055. ##
[10]. Morrow, N. R., Tang, G. Q., Valat, M., & Xie, X. (1998). Prospects of improved oil recovery related to wettability and brine composition. Journal of Petroleum Science and Engineering, 20(3-4), 267-276. doi.org/10.1016/S0920-4105(98)00030-8. ##
[11]. Austad, T. (2013). Water-based EOR in carbonates and sandstones: new chemical understanding of the EOR potential using “smart water”. In Enhanced oil recovery Field case studies (pp. 301-335). Gulf Professional Publishing. doi.org/10.1016/B978-0-12-386545-8.00013-0. ##
[12]. Mahani, H., Keya, A. L., Berg, S., Bartels, W. B., Nasralla, R., & Rossen, W. R. (2015). Insights into the mechanism of wettability alteration by low-salinity flooding (LSF) in carbonates. Energy & Fuels, 29(3), 1352-1367. doi.org/10.1021/ef5023847. ##
[13]. Zhang, P., Tweheyo, M. T., & Austad, T. (2007). Wettability alteration and improved oil recovery by spontaneous imbibition of seawater into chalk: Impact of the potential determining ions Ca2+, Mg2+, and SO42−. Colloids and Surfaces A: Physicochemical and Engineering Aspects, 301(1-3), 199-208. doi.org/10.1016/j.colsurfa.2006.12.058. ##
[14]. Nasralla, R. A., & Nasr-El-Din, H. A. (2014). Double-layer expansion: is it a primary mechanism of improved oil recovery by low-salinity waterflooding?. SPE Reservoir Evaluation & Engineering, 17(01), 49-59. doi.org/10.2118/154334-PA. ##
[15]. Hiorth, A., Cathles, L. M., & Madland, M. V. (2010). The impact of pore water chemistry on carbonate surface charge and oil wettability. Transport in Porous Media, 85, 1-21. ##
[16]. Fredriksen, S. B., Rognmo, A. U., Sandengen, K., & Fernø, M. A. (2017). Wettability effects on osmosis as an oil-mobilization mechanism during low-salinity waterflooding. Petrophysics, 58(01), 28-35. ##
[17]. Bartels, W. B., Mahani, H., Berg, S., Menezes, R., van der Hoeven, J. A., & Fadili, A. (2017). Oil configuration under high-salinity and low-salinity conditions at pore scale: a parametric investigation by use of a single-channel micromodel. SPE Journal, 22(05), 1362-1373. doi.org/10.2118/181386-PA. ##
[18]. Lashkarbolooki, M., Ayatollahi, S., & Riazi, M. (2014). Effect of salinity, resin, and asphaltene on the surface properties of acidic crude oil/smart water/rock system. Energy & Fuels, 28(11), 6820-6829. doi.org/10.1021/ef5015692. ##
[19]. Karadimitriou, N. K., Mahani, H., Steeb, H., & Niasar, V. (2019). Nonmonotonic effects of salinity on wettability alteration and two-phase flow dynamics in PDMS micromodels. Water Resources Research, 55(11), 9826-9837. doi.org/10.1029/2018WR024252. ##
[20]. Bidhendi, M. M., Garcia-Olvera, G., Morin, B., Oakey, J. S., & Alvarado, V. (2018). Interfacial viscoelasticity of crude oil/brine: An alternative enhanced-oil-recovery mechanism in smart waterflooding. SPE Journal, 23(03), 803-818. doi.org/10.2118/169127-PA. ##
[21]. Chávez-Miyauchi, T. E., Firoozabadi, A., & Fuller, G. G. (2016). Nonmonotonic elasticity of the crude oil–brine interface in relation to improved oil recovery. Langmuir, 32(9), 2192-2198. doi.org/10.1021/acs.langmuir.5b04354. ##
[22]. Kar, T., Chávez-Miyauchi, T. E., Firoozabadi, A., & Pal, M. (2020). Improved oil recovery in carbonates by ultralow concentration of functional molecules in injection water through an increase in interfacial viscoelasticity. Langmuir, 36(41), 12160-12167. doi.org/10.1021/acs.langmuir.0c01752. ##
[23]. Khajepour, H., Amiri, H. A. A., & Ayatollahi, S. (2020). Effects of salinity, ion type, and aging time on the crude oil-brine interfacial properties under gravity condition. Journal of Petroleum Science and Engineering, 195, 107896. doi.org/10.1016/j.petrol.2020.107896. ##
[24]. Morin, B., Liu, Y., Alvarado, V., & Oakey, J. (2016). A microfluidic flow focusing platform to screen the evolution of crude oil–brine interfacial elasticity. Lab on a Chip, 16(16), 3074-3081. doi.org/10.1039/C6LC00287K. ##
[25]. Ayirala, S. C., Yousef, A. A., Li, Z., & Xu, Z. (2018). Coalescence of crude oil droplets in brine systems: effect of individual electrolytes. Energy & Fuels, 32(5), 5763-5771. doi.org/10.1021/acs.energyfuels.8b00309. ##
[26]. Golmohammadi, M., Mohammadi, S., Mahani, H., & Ayatollahi, S. (2022). The non-linear effect of oil polarity on the efficiency of low salinity waterflooding: A pore-level investigation. Journal of Molecular Liquids, 346, 117069. doi.org/10.1016/j.molliq.2021.117069. ##
[27]. Moeini, F., Hemmati-Sarapardeh, A., Ghazanfari, M. H., Masihi, M., & Ayatollahi, S. (2014). Toward mechanistic understanding of heavy crude oil/brine interfacial tension: The roles of salinity, temperature and pressure. Fluid Phase Equilibria, 375, 191-200. doi.org/10.1016/j.fluid.2014.04.017. ##
[28]. Namaee-Ghasemi, A., Ayatollahi, S., & Mahani, H. (2023). Insights into the Effects of pore structure, time scale, and injection scenarios on pore-filling sequence and oil recovery by low-salinity waterflooding using a mechanistic DLVO-based pore-scale model. SPE Journal, 28(04), 1760-1776. doi.org/10.2118/214320-PA.##
پژوهش نفت
دوره 34، 1403-4 - شماره پیاپی 137
مهر و آبان 1403
صفحه 172-182

فایل ها

هم رسانی

ارجاع به این مقاله

آمار