###### Abstract  
Enhanced oil recovery using nanoparticles is a promising method. However, when injected into a reservoir, nanoparticles can block pores and cause permeability damage. Therefore, enhancing their performance to lower the permeability damage effect is crucial. This study investigated the effect of pH alteration through carbon dioxide (CO\({}_{2}\)) injection on the permeability damage of limestone caused by an aluminum oxide (\(\alpha\)-Al\({}_{2}\)O\({}_{3}\)) nanofluid. The methodology involved nanofluid alternating CO\({}_{2}\) core flooding experiments by using nanofluids with a pH of 4.5 and 2.8. After core flooding, the permeability damage was calculated as a percentage of the reduction in the original permeability. The results revealed that the permeability damage in the case of nanofluid alternating CO\({}_{2}\) injection was 23.23%. In the nanofluid with a pH of 4.5 injection case, the permeability damage was 47.53%. In the 2.8 pH nanofluid injection case, the permeability damage was 31.01%. The retention of nanoparticles was confirmed through scanning electron microscopy and energy dispersive X-ray analysis. Permeability damage could be attributed to the large nanoparticles' agglomeration size, roughness of pore surfaces, and nanoparticle sedimentation. The results of the study revealed that altering pH through the \(\alpha\)-Al\({}_{2}\)O\({}_{3}\) nanofluid alternating CO\({}_{2}\) injection can effectively reduce the permeability damage of limestone. nanoparticle enhanced oil recovery; pH control; alumina nanoparticles; permeability damage; retention of nanoparticles +
Footnote †: journal: Applied Physics Letters  
1
Footnote †: journal: Applied Physics Letters  
1
Footnote 1: email: _Applied Physics Letters_  
20231  
oil recovery methods, the environmental effects of this method, and performance uncertainty in large-scale reservoirs [16]. Improving the performance uncertainty issue requires maximizing the performance of nanoparticles for enhanced oil recovery. Several factors, such as nanofluid stability [14], nanoparticle type, and its compatibility with the reservoir's type and conditions, affect the performance of nanoparticles during enhanced oil recovery [16; 17]. After nanofluid injection in the reservoir, nanoparticles can retain in the rock's pore space, close pore channels, and cause permeability damage [10; 11; 14; 15; 17; 18]. Permeability damage is typically expressed as a percentage of reduction from the rock's original permeability (before nanofluid injection). Permeability damage indicates poor performance for the nanoparticle enhanced oil recovery, and pH control is typically used to enhance nanofluid performance [16]. Nanoparticle retention typically occurs through the following three mechanisms during the nanofluid injection process [19]: first, the sedimentation of nanoparticles resulting from instability [2; 19]; second, physical entrapment (filtration), which occurs when nanoparticles are larger than some of the pore throats or when the surface of the pores exhibits a rough geometry [2; 10; 19]; third, the adsorption of nanoparticles onto the rock surface when the total potential energy between the nanoparticles and the rock surface is attractive [2; 19]. Some retention of nanoparticles can be beneficial for diverting the flow of injected fluids toward unproduced oil and for altering the wettability of the rock surface. However, too much retention can be counterintuitive, detrimental to the efficiency of nanofluids, and could impede the oil recovery process [14; 15]. Altering the pH of both the nanofluid and the medium it is injected into changes stability and total interaction energy between the nanoparticles and the rock surface [2; 20]. The stability of the nanofluid refers to the nanofluid's resistance to agglomeration and sedimentation. Therefore, more stable nanofluids exhibit superior performance. Stability can be explained using the Derjaguin, Landau, Verwey, and Overbeek (DLVO) theory.