TY  - EJOU
AU  - Wang, Yong 
AU  - Cao, Qingqing 
AU  - Yan, Changhao 
AU  - Tang, Xinyu 
AU  - Zhang, Dingxue 
AU  - Zhu, Jingyi 

TI  - Injection Damage in Tight Oil Reservoirs: Coupled Scaling and Fouling Mechanisms
T2  - Fluid Dynamics \& Materials Processing

PY  - 
VL  - 
IS  - 
SN  - 1555-2578

AB  - 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 <i>T</i><sub>2</sub> 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 <i>T</i><sub>2</sub> 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<sub>3</sub> and BaSO<sub>4</sub> 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.
KW  - Tight oil reservoir; microfluidic visualization; formation damage; permeability reduction; asphaltene deposition; carbonate and sulfate scaling

DO  - 10.32604/fdmp.2026.075131