Carbonate reservoirs are heterogeneous; therefore, proper acid placement/diversion is required to make matrix acid treatments effective. Viscoelastic surfactants (VES) are used as diverting agents in carbonate matrix acidizing. However, these surfactants can adversely affect wettability around the wellbore area. Lab and field studies show that significant amounts of VES are retained in the reservoir, even after an EGMBE postflush. Optimizing acid treatments requires a study of the effect of VES on wettability. In a previous study using contact angle experiments, it was reported that spent acid solutions with VES only, and with VES and EGMBE are water-wetting. In this thesis, we studied the effect of two amphoteric amine-oxide VES', designated as "A" and "B" on the wettability of Austin cream chalk using contact angle experiments. We extended the previous study by using outcrop rocks prepared to simulate reservoir conditions, by demonstrating that VES adsorbs on the rock using two-phase titration experiments, by studying the effect of temperature on wettability and adsorption, and by developing a detailed procedure for contact angle experiments. We found that for initially oil-wet rocks, simulated acid treatments with VES "A" and "B" diversion stages and an EGMBE preflush and postflush made rocks water-wet at 25, 80, and 110 degrees C. Simulated acid treatments with a VES "A" diversion stage only made rocks water-wet at 25 degrees C. Our results suggest that both VES formulations cause a favorable wettability change for producing oil. The two-phase titration experiments show that both VES "A" and "B" adsorb on the rock surface. From our literature review, many surfactant wettability studies use contact angle measurements that represent advancing contact angles. However, wettability during stimulation is represented by receding contact angles. Results of static receding contact angles may be misinterpreted if low oil-acid IFT's cause oil droplets to spread. Spreading could be a reflection of the effect of the surfactants on the fluid-fluid interface rather than the rock-fluid interface. The new procedure shows the effect of VES and EGMBE on the rock-fluid interface only, and so represents the actual wettability.

Viscoelastic surfactant have found numerous application in the oil fields as fracturing and matrix acidizing fluid additives in the recent years. They have the ability to form long worm-like micelles with the increase in pH and calcium concentration, which results in increasing the viscosity and elasticity of partially spent acids. On one hand, concentration of surfactant in the fluids has profound effects on their performance downhole. Additionally, there is continuous debate in the industry on whether the gel generated by these surfactants causes formation damage, especially in dry gas wells. Therefore, being able to analyze the concentration of these surfactants in both live and spent acids is of great importance for production engineers who apply surfactant-based fluids in the oil fields. In the present work, a two-phase titration method was optimized for quantitative analysis of a carboxybetaine viscoelastic surfactant, and surfactant retention in calcite cores was quantitatively determined by two phase titration method and the benefits of using mutual solvents to break the surfactant gel formed inside the cores was assessed. On the other hand, high temperatures and low pH are usually involved in surfactant applications. Surfactants are subjected to hydrolysis under such conditions due to the existence of a peptide bond (-CO-NH-) in their molecules, leading to alteration in the rheological properties of the acid. The impact of hydrolysis at high temperatures on the apparent viscosity of carboxybetaine viscoelastic surfactant-based acids was evaluated in the present study, and the mechanism of viscosity changes was determine by molecular dynamics (MD) simulations. Our results indicate that, first, significant amount of surfactant has been retained in the carbonate matrix after acidizing treatment and there is a need to use internal breakers when surfactant-based acids are used in dry gas wells or water injectors. Second, hydrolysis at high temperatures has great impact on surfactant-acid rheological properties. Short time viscosity build-up and effective gel break-down can be achieved if surfactant-acid treatments are carefully designed; otherwise, unexpected viscosity reduction and phase separation may occur, which will affect the outcome of acid treatments.