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.

Formation damage caused by water-in-crude oil emulsions can have a big impact on oil production. Chemical treatment is often applied by injecting surfactants known as demulsifiers to break the water-in-crude oil emulsions. Common demulsifiers used in the oilfield industry often contain chemicals that are deemed environmentally unacceptable. With the increasingly stringent environmental and safety measures for oilfield chemicals, there is a significant drive to develop more environmentally friendly formulations for oilfield applications that are as efficient as existing chemicals. In this work, more environmentally friendly demulsifiers have been developed by systematically upgrading existing components in a conventional demulsifier with more environmentally acceptable components. The environmental impact of existing and upgraded formulations was evaluated using industry developed product rating systems. Demulsification tests were then carried out to assess the performance of the newly developed formulations on several problematic oils.

In the petroleum industry, water and oil emulsion formation presents an on-going production issue receiving considerable technical attention. Crude oil/water demulsification effectiveness has been tested using a new microemulsion-based demulsifier (ME-DeM) with an environmentally improved formulation. This ME-based product, tested on a range of crude oils, has been shown to be more effective than comparable commercially available non-ME based demulsifiers (DeM). Results using ME based products for demulsification have demonstrated significant improvements in field tests. Additional field studies are in preparation. Introduction Emulsion Generation and Stabilization Water and oil emulsions have been the subject of numerous studies in the petroleum industry because of associated operational issues requiring intervention and expense in production, recovery, transfer, transportation and refining processes. A very good summary regarding "a state of the art review" of crude oil emulsions was presented by Sunil Kokai (Kokai 2002). Emulsions, defined as a combination of two or more immiscible fluids that will not easily separate into individual components, which exist as droplets of colloidal sizes or larger, can lead to high pumping cost. In the case that water is dispersed in an oil continuous phase, the emulsion is termed water-in-oil (w/o) emulsion and in the case that oil is dispersed in a water phase, an oil-in-water (o/w) emulsion. If there is no stabilizer between the oil and water interface, the emulsion is not thermodynamically stable. Coalescence of droplets can lead to destabilization of the emulsion (Holmberg, et al. 2007). However components can accumulate at the oil and water interface which stabilize the interface hindering droplet coalescence and the destabilization (demulsification) process. Materials, such as naturally occurring or injected surfactants, polymers, inorganic solids, or wax, can lead to stabilization of the interface. Emulsification formation processes are also influenced by fluid mixing, shear, turbulence, diffusion, surfactant aggregation (Miller 1988), steric stabilization (non-ionic surfactants), temperature and pressure. Surfactants can form lamellar liquid crystals by the growth of multiple layers around the dispersed droplets. Emulsions can form when fluid filtrates or injected fluids and reservoir fluids mix, or when the pH of the producing fluid changes. Asphaltene, resin and wax composition and concentration (Lissant 1988, Auflem 2002, Sifferman 1976, Sifferman 1980) are factors affecting emulsion creating and stabilization. In oils which contain significant amounts of asphaltene, the asphaltene acts as a surfactant, creating emulsions that can be very difficult to destabilize. Interfacial tension can be reduced using surfactants which enhance the thermodynamic stability of an emulsion and allowing creation of small droplets. Studies have concluded that emulsion stability is not totally dependent on the interfacial tension value but on the interfacial film properties (Berger, et al. 1988, Posano, et al. 1982) and have shown that lowering the interfacial tension is conducive to emulsion stabilization, but if too low, can lead to destabilization. Surfactants, polymers and adsorbed particles can create strong interfacial films. Increased interfacial film stability also results from greater surface and bulk viscosity. These factors can limit film thinning and rupture by affecting the properties of interfacial viscosity and elasticity.

Flowback aids are usually surfactants or cosolvents added to stimulation treatments to reduce capillary pressure and water blocks. As the gas reservoirs being stimulated 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, 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 may be most appropriate. This paper compares four different flowback aids: microemulsion, two water-wetting flowback additives, and an oil-wetting additive. Careful laboratory testing was done to look at surface tension and contact angle for each flowback aid using the recommended concentrations. Imbibition and drainage tests were done, which allowed calculating the capillary pressures for the three additives. Drainage tests were performed on 1-3 and 0.1 mD cores. Capillary tube rise testing was also done as a check of the core flood testing capillary pressures. This provided several different methods to determine capillary forces for the flowback aids. In addition, fluid loss testing was done to determine if the flowback additives could improve fluid loss. All the flowback aids demonstrated low surface tension (~30 dyne/cm), 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 microemulsion 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 clean-up or return permeability on cores above 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. Introduction: Flowback aids should in theory be critically important in either moderate permeability reservoirs for oil or low permeability reservoirs for gas (tight gas or shale). It is conceptually intuitive to argue that reducing the capillary pressure of the fluid in the near fracture region should improve flowback of the fracturing fluid, and reduce the drawdown to produce. In practice it is understood that oil and gas reservoirs are very complicated in their wettability. Almost never are formations pure sandstone. Clays line the pores of most reservoir rock, and in the case of shale, an added complication is the hydrophobic kerogen partially lining the pore surface. Further, the presence of liquid hydrocarbons may adsorb and alter the wettability of the reservoir. These factors make it difficult without direct measurement to determine the inherent wettability of reservoir. The fact that the composition and surface of the reservoir are heterogeneous in three dimensions further complicates the analysis.