Polymer-free viscoelastic surfactant-based (VES) fluid systems have been used to eliminate polymer-based damage and to efficiently transport proppants into the fracture. Current models and correlations neglect the important influence of fracture walls and fluid elasticity on proppant settling. This report presents an experimental study that investigates the impact of fluid elasticity and fracture width on proppant settling in VES fluid systems. Proppant settling experiments are performed in shear-thinning VES fluids. Experimental data is presented to show that fluid elasticity plays an important role in controlling the settling rate of the proppants. It is shown that elastic effects can increase as well as reduce the settling velocities depending upon the rheological properties of the fluid and properties of the proppants. Data is presented to show that the settling velocity reduces significantly as the proppant size becomes comparable to the fracture width. The reduction in settling velocity due to the presence of the fracture walls depends on the rheological properties of the fluid, ratio of particle diameter to fracture width as well as the diameter of the particle. / text

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 surfactants (VES) have been widely used in acidizing and acid fracturing. They are used as diversion agents during matrix acid treatments and leakoff control agents during acid fracturing. At high temperatures, viscoelastic surfactants hydrolyze, resulting in phase separation after a certain time. Their viscosities significantly decrease and it is much easier for them to flow back causing much less damage to the formation. In this study, 4 to 8 wt% of a new VES-acid system was tested at temperatures of up to 250°F over hydrolysis times of 0 to 6 hours. Then, the solutions were neutralized by calcium carbonate until the pH reached 4.5. An HP/HT rheometer was used to measure the viscosity of the spent acids. Mass spectrometry (MS) was conducted to analyze the hydrolysis products of the VES. Coreflood tests were also conducted on Indiana limestone to determine the effects of the hydrolysis products on the permeability of these cores. The temperature was set at 250°F and the flow rate at 2.5 cm^(3)/s. The viscosities of all VES-acid systems remained high at the beginning of hydrolysis, which was good for acid diversion. After that, the VES acid systems experienced a significant viscosity reduction due to phase separation; it became much easier for the spent acid to flow back. Coreflood experiments caused little damage to the Indiana limestone. MS results indicated hydrolysis of peptide bonds. Fatty acids formed the top oil layer, and amine-based molecules formed the aqueous phase. This study will summarize and discuss the details of viscosity changes of the acid systems of this kind of viscoelastic surfactant, the damage caused by hydrolysis products, and how this kind of viscoelastic surfactant can be used to improve treatments.

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.

Recently there has been a great deal of attention in the oilfield industry focused on the phenomenal properties of viscoelastic surfactants (VES). The interest is motivated by their applications as switchable smart fluids, their surface tension, and their thickening and rheology enhancement in aqueous solution. Surfactant molecules in solution are known for their ability to assemble spontaneously into complex structures. Under certain thermodynamic conditions, temperature and electrolyte concentrations, wormlike micelles are formed. These micelles share similar equilibrium and dynamic properties with polymer solutions, However, micellar chains can break and recombine spontaneously which make them part of the more general class of living polymers. It is vital to understand the properties of viscoelastic wormlike micelles with regard to their flow in porous media. The overall objective of this study is to establish a better understanding of counterion effect on behavior of VES. The dependence of macroscopic properties on intermolecular interactions of complex fluid systems such as VES is an enormous challenge. To achieve our objective, we use first-principle calculations and molecular dynamics (MD) simulations to resolve the full chemical details in order to study how the structure of the micellar and solution properties depends on the chemical structure of the surfactant head group (HG) and type of counterion. In particular, we run simulations for different structures in gas-phase and aqueous solutions together with their salt counterions at room temperature and atmospheric pressure. For this purpose, we consider four types of surfactant HG (anionic, cationic, betaine and amidoamine oxide) together with the most common ions present in the acidizing fluid of a carbonate reservoir such as Ca2+, Mg2+, Fe2+, Fe3+, Mn2+ and Zn2+, Cl-, OH- and HS-. Hydration of ions as well as interactions with surfactant the HG are studied using density functional theory (DFT). The results give important insight into the links between molecular details of VES HG structure and observed solution properties. This study proposes for the first time the possible mechanisms that explain the exotic behavior of VES at high Fe(III) concentration. Also, our MD simulation suggests that distribution of chloride ion around surfactant molecules is responsible for their viscosity behavior in HCl solution. We believe that our results are an important step to develop more systematic procedures for the molecular design and formulation of more effective and efficient VES systems.