Injection Damage in Tight Oil Reservoirs: Coupled Scaling and Fouling Mechanisms
Yong Wang1,2, Qingqing Cao3, Changhao Yan2, Xinyu Tang2,3, Dingxue Zhang1,*, Jingyi Zhu3,*
1 Petroleum Engineering College, Yangtze University, Jingzhou, China
2 Oil and Gas Technology Research Institute, PetroChina Changqing Oilfield Company, Xi’an, China
3 National Key Laboratory of Oil and Gas Reservoirs Geology and Exploitation, Southwest Petroleum University, Chengdu, China
* Corresponding Author: Dingxue Zhang. Email: 
; Jingyi Zhu. Email: 
(This article belongs to the Special Issue: Fluid Dynamics and Multiphysical Coupling in Rock and Porous Media: Advances in Experimental and Computational Modeling)
Fluid Dynamics & Materials Processing https://doi.org/10.32604/fdmp.2026.075131
Received 25 October 2025; Accepted 19 March 2026; Published online 02 June 2026
Abstract
Injection damage in the M tight oil reservoir is controlled by the coupled effects of inorganic scaling and organic fouling at the pore scale. To clarify the governing mechanisms, this study combines long-duration core flooding, water-chemistry compatibility analysis, and thermodynamic scale prediction with NMR
T2 spectroscopy, mercury intrusion capillary pressure, SEM-EDS characterization, and factor-controlled microfluidic visualization that reproduces reservoir pore geometry and wettability. Core flooding tests reveal permeability reductions of 61 to 73 percent after 12 to 24 hours of injection, indicating progressive contraction of effective flow channels. NMR
T2 spectra demonstrate strong pore-size selectivity: small pores largely retain their porosity, 99.43 and 89.48 percent, whereas medium and large pores experience substantial losses. SEM imaging and elemental mapping show Ca and Ba co-located with carbon within pore spaces, consistent with CaCO
3 and BaSO
4 precipitation induced by mixing sulfate-rich injection water with formation brine. Microfluidic experiments further decouple the roles of oil presence, hydrocarbon type, wettability, and asphaltene content. In the presence of oil, injection pressure increases from 20.4 to 93.6 kPa, compared with 1.3 to 13.4 kPa without oil, while pore-space retention decreases to 73 percent versus 92 percent. Inorganic scale alone causes only moderate injectivity impairment, whereas oil-mediated deposition raises total pore blockage to approximately 27 percent, accounting for nearly two-thirds of the overall injectivity decline. Heavier n-tetradecane generates larger aggregates and higher pressures than n-hexane. Oil-wet surfaces promote more continuous deposits, faster pressure escalation, and greater loss of open flow area than hydrophilic substrates. Increasing the asphaltene surrogate concentration from 2 to 6 percent accelerates inlet bank formation and early throat occlusion, reducing pore-space retention from 98.0 to 67.9 percent and increasing pressure from 59.09 to 78.23 kPa.
Keywords
Tight oil reservoir; microfluidic visualization; formation damage; permeability reduction; asphaltene deposition; carbonate and sulfate scaling
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