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.

As new reservoirs are developed and formations are exposed to various fluids, clay swelling and fines migration can cause serious damage. Clay stabilizers are generally added to mitigate these problems. However, the performance of formation stabilizers is not always properly assessed in the traditional analyses of formation samples. In general, laboratory testing with formation material is performed to define the best additive and concentration. Incorrect choice of stabilizer additives can result in severe damage from swelling and mobile formation clays. There appears to be no standard method for conducting formation stabilizer evaluations, therefore, it is difficult to make meaningful comparisons. Test methods based on the capillary suction time (CST) test or hot rolling lack any theoretical basis and may not show subtle effects.A new test protocol incorporates several significant improvements over the traditional core flow methods. It considers important factors such as the critical salt concentration and the critical flow velocity. A key improvement is that the proposed method closely mimics pumping and cleanup operations actually encountered in field operations. The new test method is able to distinguish performance differences based upon both stabilizer chemistry and concentration.Testing results from a moderately sensitive Berea core yielded a surprising finding: well-known organic stabilizers were only slightly more effective than de-ionized water, whereas inorganic salts were quite effective, even at low concentrations. Further, confirming findings by others, our results showed that the Berea core used in this study required no stabilization at 270°F.

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.