0
Research Papers: Petroleum Engineering

Preparation and Characterization of Chemical Agents for Augmenting Injectivity in Low Permeability Reservoirs

[+] Author and Article Information
Min Zhao

Petroleum Systems Engineering,
Faculty of Engineering and Applied Science,
University of Regina,
Regina, SK S4S 0A2, Canada;
College of Petroleum Engineering,
China University of Petroleum (East China),
Qingdao 266580, China

Xiutai Zhao

College of Petroleum Engineering,
China University of Petroleum (East China),
Qingdao 266580, China

Daoyong Yang

Petroleum Systems Engineering,
Faculty of Engineering and Applied Science,
University of Regina,
Regina, SK S4S 0A2, Canada
e-mail: tony.yang@uregina.ca

1Corresponding author.

Contributed by the Petroleum Division of ASME for publication in the JOURNAL OF ENERGY RESOURCES TECHNOLOGY. Manuscript received September 5, 2017; final manuscript received November 7, 2017; published online January 22, 2018. Editor: Hameed Metghalchi.

J. Energy Resour. Technol 140(3), 032914 (Jan 22, 2018) (9 pages) Paper No: JERT-17-1480; doi: 10.1115/1.4038784 History: Received September 05, 2017; Revised November 07, 2017

In this paper, experimental techniques have been developed to prepare and characterize chemical agents for augmenting injectivity in low permeability reservoirs. First, chemical agents are selected, formulated, and optimized on the basis of interfacial tension (IFT), scale inhibition ratio, and clay particle size distribution and specific surface area. The spinning drop method is utilized to measure the IFT between crude oil and the formulated solution, while contact angle between brine and rock surface is measured to examine effect of the chemical agents on the rock wettability. Also, scale inhibition ratio and antiswelling ratio are, respectively, measured by performing static-state scale inhibition experiments and centrifugation experiments. Then, displacement experiments are conducted to evaluate injectivity improvement after one pore volume (PV) of such formulated chemical agents has been injected into a core plug. It is found that the optimized solution consists of 0.15 wt % fluorocarbon surfactant FC-117, 4.00 wt % isopropanol, 1.20 × 10−3 wt % scale inhibitor 2-phosphonobutane-1,2,4-tricarboxylic acid (PBTCA), and 1.50 wt % clay stabilizer diallyl dimethyl ammonium chloride (DMDAAC). The IFT between crude oil and the optimized solution can be reduced to 5.36 × 10−3 mN/m within a short time, while the scale inhibition ratio and antiswelling ratio are measured to be 94.83% and 86.96%, respectively. It is found from comprehensive evaluation experiments that such a formulated and optimized solution can not only alter the rock surface from oil-wet to water-wet but also reduce the scale formation of the reservoir brine. In addition, it is shown from displacement experiments that the pressure is decreased by 34.67% after the injection of such formulated solution. When the formulated solution contains 0–300,000 mg/L sodium chloride (NaCl) and 0–5000 mg/L calcium chloride (CaCl2) at 50–90 °C, the IFT between crude oil and the formulated solution can be reduced to lower than 10−2 mN/m.

FIGURES IN THIS ARTICLE
<>
Copyright © 2018 by ASME
Your Session has timed out. Please sign back in to continue.

References

Hoffman, B. T. , and Shoaib, S. , 2013, “ CO2 Flooding to Increase Recovery for Unconventional Liquids-Rich Reservoirs,” ASME J. Energy Resour. Technol., 136(2), p. 022801. [CrossRef]
Song, C. , and Yang, D. , 2017, “ Experimental and Numerical Evaluation of CO2 Huff-n-Puff Processes in Bakken Formation,” Fuel, 190, pp. 145–162. [CrossRef]
Yang, D. , Song, C. , Zhang, J. , Zhang, G. , Ji, Y. , and Gao, J. , 2015, “ Performance Evaluation of Injectivity for Water-Alternating-CO2 Processes in Tight Oil Formations,” Fuel, 139(1), pp. 292–300. [CrossRef]
Seales, M. B. , Ertekin, T. , and Wang, J. Y. , 2017, “ Recovery Efficiency in Hydraulically Fractured Shale Gas Reservoirs,” ASME J. Energy Resour. Technol., 139(4), p. 042901. [CrossRef]
Nasr-El-Din, H. A. , 2005, “ Formation Damage Induced by Chemical Treatments: Case Histories,” ASME J. Energy Resour. Technol., 127(3), pp. 214–224. [CrossRef]
Stamatakis, E. , Haugan, A. , Chatzichristos, C. , Stubos, A. , Muller, J. , and Palyvos, I. , 2006, “ Study of Calcium Carbonate Precipitation in the Near-Well Region Using 47Ca as Tracer,” SPE Prod. Oper., 21(1), pp. 33–39. [CrossRef]
Bennion, D. B. , and Thomas, F. B. , 2005, “ Formation Damage Issues Impacting the Productivity of Low Permeability, Low Initial Water Saturation Gas Producing Formations,” ASME J. Energy Resour. Technol., 127(3), pp. 240–247. [CrossRef]
Yassin, M. R. , Ayatollahi, S. , Rostami, B. , Hassani, K. , and Taghikhani, V. , 2015, “ Micro-Emulsion Phase Behavior of a Cationic Surfactant at Intermediate Interfacial Tension in Sandstone and Carbonate Rocks,” ASME J. Energy Resour. Technol., 137(1), p. 012905. [CrossRef]
Hou, B. , Wang, Y. , Cao, X. , Zhang, J. , Song, X. , Ding, M. , and Chen, W. , 2016, “ Mechanisms of Enhanced Oil Recovery by Surfactant-Induced Wettability Alteration,” J. Dispersion Sci. Technol., 37(9), pp. 1259–1267. [CrossRef]
Pu, W. , Yuan, C. , Wang, X. , Sun, L. , Zhao, R. , Song, W. , and Li, X. , 2016, “ The Wettability Alteration and the Effect of Initial Rock Wettability on Oil Recovery in Surfactant-Based Enhanced Oil Recovery Processes,” J. Dispersion Sci. Technol., 37(4), pp. 602–611. [CrossRef]
Bera, A. , Mandal, A. , and Kumar, T. , 2015, “ The Effect of Rock-Crude Oil-Fluid Interactions on Wettability Alteration of Oil-Wet Sandstone in the Presence of Surfactants,” Pet. Sci. Technol., 33(5), pp. 542–549. [CrossRef]
Zlegler, V. M. , 1988, “ Laboratory Investigation of High-Temperature Surfactant Flooding,” SPE Reservoir Eng., 3(2), pp. 586–596. [CrossRef]
Li, G. , Xu, J. , Mu, J. , Zhai, L. , Shui, L. , Chen, W. , Jiang, J. , Chen, F. , Guo, D. , and Lin, W. , 2005, “ Design and Application of an Alkaline-Surfactant-Polymer Flooding System in Field Pilot Test,” J. Dispersion Sci. Technol., 26(6), pp. 709–717. [CrossRef]
Bryan, J. , and Kantzas, A. , 2009, “ Potential for Alkali-Surfactant Flooding in Heavy Oil Reservoirs Through Oil-in-Water Emulsification,” J. Can. Pet. Technol., 48(2), pp. 37–46. [CrossRef]
Mungan, N. , 1964, “ Role of Wettability and Interfacial Tension in Water Flooding,” SPE J., 4(2), pp. 115–123. [CrossRef]
Xu, N. , Liu, W. , and Li, H. , 2007, “ A Study on Quaternary Ammonium Salt Gemini Surfactant G-52 for Water Injection Well Stimulation in Low Permeability Reservoirs,” Oilfield Chem., 24(2), pp. 138–142.
Gong, H. , Li, Y. , Dong, M. , Zhu, T. , and Yu, L. , 2016, “ Enhanced Heavy Oil Recovery by Organic Alkali Combinational Flooding Solutions,” J. Dispersion Sci. Technol., 38(4), pp. 551–557. [CrossRef]
Zhang, T. , Cao, X. , Wang, X. , and Song, C. , 2017, “ Synthesis, Surface Activity and Thermodynamic Properties of Cationic Gemini Surfactants With Diester and Rigid Spacers,” J. Mol. Liq., 230, pp. 505–510. [CrossRef]
Lee, S. , Lee, J. , Yu, H. , and Lim, J. , 2016, “ Synthesis of Environment Friendly Nonionic Surfactants From Sugar Base and Characterization of Interfacial Properties for Detergent Application,” J. Ind. Eng. Chem., 38, pp. 157–166. [CrossRef]
Gao, B. , and Sharma, M. M. , 2013, “ A New Family of Anionic Surfactants for Enhanced- Oil-Recovery Applications,” SPE J., 18(5), pp. 829–840. [CrossRef]
Chang, H. , Cui, Y. , Wei, W. , Li, X. , Gao, W. , Zhao, X. , and Yin, S. , 2017, “ Adsorption Behavior and Wettability by Gemini Surfactants With Ester Bond at Polymer-Solution-Air Systems,” J. Mol. Liq., 230, pp. 429–436. [CrossRef]
Tavassoli, S. , Kazemi Nia Korrani, A. , Pope, G. A. , and Sepehrnoori, K. , 2016, “ Low-Salinity Surfactant Flooding—A Multimechanistic Enhanced-Oil-Recovery Method,” SPE J., 21(3), pp. 744–760. [CrossRef]
Jiang, P. , Li, N. , Ge, J. , Zhang, G. , Wang, Y. , Chen, L. , and Zhang, L. , 2014, “ Efficiency of a Sulfobetaine-Type Surfactant on Lowering IFT at Crude Oil–Formation Water Interface,” Colloids Surf. A, 443, pp. 141–148. [CrossRef]
Zhang, J. , Li, G. , Yang, F. , Xu, N. , Fan, H. , Yuan, T. , and Chen, L. , 2012, “ Hydrophobically Modified Sodium Humate Surfactant: Ultra-Low Interfacial Tension at the Oil/Water Interface,” Appl. Surf. Sci., 259, pp. 774–779. [CrossRef]
Babu, K. , Pal, N. , Bera, A. , Saxena, V. K. , and Mandal, A. , 2015, “ Studies on Interfacial Tension and Contact Angle of Synthesized Surfactant and Polymeric From Castor Oil for Enhanced Oil Recovery,” Appl. Surf. Sci., 353, pp. 1126–1136. [CrossRef]
Tabary, R. , Bazin, B. , Douarche, F. , Moreau, P. , and Oukhemanou-Destremaut, F. , 2013, “ Surfactant Flooding in Challenging Conditions: Towards Hard Brines and High Temperatures,” SPE Middle East Oil and Gas Show and Conference, Manama City, Bahrain, Mar. 10–13, SPE Paper No. SPE-164359-MS.
Sun, N. , Jing, J. , Jiang, H. , An, Y. , Wu, C. , Zheng, S. , and Qi, H. , 2017, “ Effects of Surfactants and Alkalis on the Stability of Heavy-Oil-in-Water Emulsions,” SPE J., 22(1), pp. 120–129. [CrossRef]
Kumar, S. , and Mandal, A. , 2016, “ Studies on Interfacial Behavior and Wettability Change Phenomena by Ionic and Nonionic Surfactants in Presence of Alkalis and Salt for Enhanced Oil Recovery,” Appl. Surf. Sci., 372, pp. 42–51. [CrossRef]
Li, Y. , Zhao, J. , Pu, W. , and Zhao, T. , 2014, “ Solutions of Long-Chain Alcohols and Surfactants for Enhanced Oil Recovery in High-Temperature Low-Permeability Reservoirs,” Chem. Technol. Fuels Oils, 50(4), pp. 327–336. [CrossRef]
Zhang, J. , Zhang, G. , Ge, J. , Feng, A. , Jiang, P. , Li, R. , Zhang, Y. , and Fu, X. , 2012, “ Laboratory Studies of Depressurization With a High Concentration of Surfactant in Low-Permeability Reservoirs,” J. Dispersion Sci. Technol., 33(11), pp. 1589–1595. [CrossRef]
Zhao, J. , Dai, C. , Fang, J. , Feng, X. , Yan, L. , and Zhao, M. , 2014, “ Surface Properties and Adsorption Behavior of Cocamidopropyl Dimethyl Amine Oxide Under High Temperature and High Salinity Conditions,” Colloids Surf. A, 450, pp. 93–98. [CrossRef]
Shehab, A. , Chang, D. , Vu, T. , Maša, P. , and Keith, P. J. , 2017, “ High Temperature Ultralow Water Content Carbon Dioxide-in-Water Foam Stabilized With Viscoelastic Zwitterionic Surfactants,” J. Colloid Interface Sci., 488, pp. 79–91. [CrossRef] [PubMed]
Wang, D. , Liu, C. , Wu, W. , and Wang, G. , 2008, “ Development of an Ultralow Interfacial Tension Surfactant in Systems With No-Alkali for Chemical Flooding,” SPE/DOE Improved Oil Recovery Symposium, Tulsa, OK, Apr. 19–23, SPE Paper No. SPE-109017-MS.
Tehrani-Bagha, A. R. , Nikkar, H. , Menger, F. M. , and Holmberg, K. , 2012, “ Degradation of Two Persistent Surfactants by UV-Enhanced Ozonation,” J. Surfactants Deterg., 15(1), pp. 59–66. [CrossRef]
Saeed, J. D. S. , Mohammad, S. , and Abdolhossein, H. S. , 2016, “ Toward Mechanistic Understanding of Natural Surfactant Flooding in Enhanced Oil Recovery Processes: The Role of Salinity, Surfactant Concentration and Rock Type,” J. Mol. Liq., 222, pp. 632–639. [CrossRef]
Adamson, A. W. , and Gast, A. P. , 1997, Physical Chemistry of Surfaces, Wiley, New York.
Li, D. , 2002, “The Effect of Biosurfactant on the Interfacial Tension and Adsorption Loss of Surfactant in ASP Flooding,” Ph.D. dissertation, Daqing Petroleum Institute, Heilongjiang, China.
Kumar, T. , Vishwanatham, S. , and Kundu, S. S. , 2010, “ A Laboratory Study on Pteroyl-L-Glutamic Acid as a Scale Prevention Inhibitor of Calcium Carbonate in Aqueous Solution of Synthetic Produced Water,” J. Pet. Sci. Eng., 71, pp. 1–7. [CrossRef]
Liu, P. , Zhou, L. , Yang, C. , Xia, H. , He, Y. , and Feng, M. A. , 2015, “ A Complex Based on Imidazole Ionic Liquid and Copolymer of Acrylamide and Phenoxyacetamide Modification for Clay Stabilizer,” J. Appl. Polym. Sci., 132(9), p. 41536.
Karnanda, W. , Benzagouta, M. S. , AlQuraishi, A. , and Amro, M. M. , 2013, “ Effect of Temperature, Pressure, Salinity, and Surfactant Concentration on IFT for Surfactant Flooding Optimization,” Arabian J. Geosci., 6(9), pp. 3535–3544. [CrossRef]
Mehranfar, A. , and Ghazanfari, M. H. , 2014, “ Investigation of the Microscopic Displacement Mechanisms and Macroscopic Behavior of Alkaline Flooding at Different Wettability Conditions in Shaly Glass Micromodels,” J. Pet. Sci. Eng., 122, pp. 595–615. [CrossRef]
Obied, M. A. , Alkhaldi, M. H. , Mubarak, T. A. , Yami, I. S. , and Sahman, F. M. , 2015, “ Polymer-Based Scale Inhibitors for Seawater Injection Operations in High-Salinity Formation Water Reservoirs,” Abu Dhabi International Petroleum Exhibition and Conference, Abu Dhabi, United Arab Emirates, Nov. 9–12, SPE Paper No. SPE-177417-MS.
Zhang, B. , Zhang, L. , Li, F. , Hu, W. , and Hannam, M. P. , 2010, “ Testing the Formation of Ca-Phosphonate Precipitates and Evaluating the Anionic Polymers as Ca-Phosphonate Precipitates and CaCO3 Scale Inhibitor in Simulated Cooling Water,” Corros. Sci., 52(12), pp. 3883–3890. [CrossRef]
Zhang, G. , Ge, J. , Sun, M. , Pan, B. , Mao, T. , and Song, Z. , 2007, “ Investigation of Scale Inhibitor Mechanisms Based on the Effect of Scale Inhibitor on Calcium Carbonate Crystal Forms,” Sci. China Ser. B: Chem., 50(1), pp. 114–120. [CrossRef]
Zhao, X. , Bai, Y. , Wang, Z. , Shang, X. , Qiu, G. , and Chen, L. , 2013, “ Low Interfacial Tension Behavior Between Organic Alkali/Surfactant/Polymer System and Crude Oil,” J. Dispersion Sci. Technol., 34(6), pp. 756–763. [CrossRef]
Barati-Harooni, A. , Soleymanzadeh, A. , Tatar, A. , Najafi-Marghmaleki, A. , Samadi, S. J. , Yari, A. , Roushani, B. , and Mohammadi, A. H. , 2016, “ Experimental and Modeling Studies on the Effects of Temperature, Pressure and Brine Salinity on Interfacial Tension in Live Oil-Brine Systems,” J. Mol. Liq., 219, pp. 985–993. [CrossRef]

Figures

Grahic Jump Location
Fig. 1

Schematic diagram of the maximum bubble pressure apparatus: (a) digital pressure gauge, (b) distilled water, (c) dropping funnel, (d) quartz beaker, (e) outer thimble, (f) capillary tube, and (g) solution

Grahic Jump Location
Fig. 2

Schematic diagram of the displacement experiment: (a) constant-flux pump, (b) transfer cylinder, (c) six-way valve, (d) digital pressure gauge, (e) coreholder, and (f) production fluid collector

Grahic Jump Location
Fig. 3

Relationship between surface tension and concentration of FC-117

Grahic Jump Location
Fig. 4

Relationship between IFT and time with different concentration of FC-117 and isopropanol: (a) 0.05 wt %, (b) 0.10 wt %, (c) 0.15 wt %, and (d) 0.20 wt %

Grahic Jump Location
Fig. 5

Schematic diagram of effect to residual oil by chemical agents

Grahic Jump Location
Fig. 6

The chemical structure of PBTCA

Grahic Jump Location
Fig. 7

The relationship between scale inhibition ratio and concentration of PBTCA

Grahic Jump Location
Fig. 8

The chemical structure of DMDAAC

Grahic Jump Location
Fig. 9

The particle size distribution of kaolin in (a) water and (b) 1.50 wt % DMDAAC solution

Grahic Jump Location
Fig. 10

Wettability alteration of rock surface after being treated by chemical solution

Grahic Jump Location
Fig. 11

Sequential digital images of a sessile brine drop on the rock slide with different treated time: (a) t = 0 h, θ= 104 deg, (b) t = 1 h, θ= 54 deg, and (c) t = 24 h, θ= 35 deg

Grahic Jump Location
Fig. 12

Effect of NaCl and CaCl2 on the minimum IFT

Grahic Jump Location
Fig. 13

Effect of temperature on the dynamic IFT

Grahic Jump Location
Fig. 14

The relationship between injection pressure and injection brine volume

Tables

Errata

Discussions

Some tools below are only available to our subscribers or users with an online account.

Related Content

Customize your page view by dragging and repositioning the boxes below.

Related Journal Articles
Related eBook Content
Topic Collections

Sorry! You do not have access to this content. For assistance or to subscribe, please contact us:

  • TELEPHONE: 1-800-843-2763 (Toll-free in the USA)
  • EMAIL: asmedigitalcollection@asme.org
Sign In