Comparison of Flowback Aids: Understanding Their Capillary Pressure and Wetting Properties

Abstract

Summary Flowback aids are usually surfactants or cosolvents added to stimulation treatments to reduce capillary pressure and water blocks. As the stimulated gas reservoirs become tighter, the perceived value of these additives has grown. This value must be balanced with the cost of the additives, which can be significant in slickwater fracturing treatments. There is a range of different flowback additives containing water-wetting nonionic to amphoteric, microemulsion (ME), and oil-wetting components. Determining the best additive for a specific reservoir is not a simple matter for the end user, and the existing literature is full of conflicting claims as to which one is most appropriate. This paper compares four different flowback aids: ME, two waterwetting flowback additives, and an oil-wetting additive. Careful laboratory testing was conducted to evaluate surface tension and contact angle for each flowback aid, using the recommended concentrations. Imbibition and drainage tests were performed that allowed calculation of the capillary pressures for the three additives. Drainage tests were performed on 1- to 3-md and 0.1-md cores. Capillary-tube-rise testing was also conducted as a check of the coreflood testing capillary pressures. This provided several different methods to determine capillary forces for the flowback aids. In addition, fluid-loss testing was conducted to determine if the flowback additives could improve fluid loss. All the flowback aids demonstrated low surface tension (approximately 30 mN/m), but each was different in terms of surface wettability and adsorption in the rock. In all cases, the flowback aids reduced capillary pressure to similar levels 70% lower than water alone. One of the water-wetting additives had much stronger adsorption in the core material than the other additives. The ME and the oil-wetting additive had improved fluid loss in a fully formulated fracturing fluid. In spite of the low capillary pressures, the additives had little effect on cleanup or return permeability on cores greater than 1 md. There are several implications of these results for the operator. Different flowback additives have a tradeoff of properties, and depending on the reservoir, selecting one that leaves the formation with certain wettability may be advantageous. Our testing indicated that understanding the reservoir is important in selecting the appropriate flowback aid.

Post-Fracturing Fluid-Recovery Enhancement With Microemulsion

“…Gdanski (2007) agrees with this, though he states that some of the negative effects of water saturation, specifically high capillary pressures, often become negligible in permeabilities of 1 mD or more. This is validated in work conducted by Howard et al (2009) where retained permeability of cores greater than 1mD showed no benefit from surfactant or microemulsion usage. While laboratory testing can provide a basis for flowback aid selection, the case histories presented in our paper show that flowback aids giving comparable results in the laboratory may give significantly different results under field application.…”

Surface Energy of North American Shales and its Role in Interaction of Shale with Surfactants and Microemulsions

“…Values of γ S d are consistently lower than the value of γ S LW , which is expected according to eqs. (4) and (8). Furthermore, the analysis clearly shows that shale surface is a weak electron donor and that the tendency to formation of hydrogen bonding is very low, as evidenced by low γ S AB component.…”

“…At the same time, γ S AB and γcomponents are much lower than those of quartz, indicating that electron-donor and hydrogen bonding properties of shale surface are much weaker than those of quartz. This suggests that glass or quartz slides may not be completely realistic model substrates for studies of fracturing fluids additives with intended application in shales [8]. In fact, the determined values of surface free energy components of shales are very similar to the surface energy components of some low-rank coals [19], indicating that studies on surfactant interaction with coals should be relevant to shales to a larger extent than studies on glass and quartz.…”

“…Also, one can state that ( 8 ) In the present work the components of surface free energy based on LW-AB approach were evaluated based on three probe liquids. Diiodomethane, capable of interacting with the solid surface only via Lifshitz-van der Waals interactions (γ L =γ LW ) was used to evaluate γ S LW from the following expression:…”

“…Up to this point, studies discussing surfactant and microemulsion technologies [8][9][10] have failed to address the importance of shale surface free energy and its relevance to the performance of such chemical additives. In fact, the development of long-sought shale-specific chemical treatments requires one to be able to compare different shales with respect to their surface properties relevant to the interaction between them and chemical additives.…”