Comparison of Flowback Aids: Understanding Their Capillary Pressure and Wetting Properties
- Paul Howard (Schlumberger) | Sumitra Mukhopadhyay (Schlumberger) | Nita Moniaga (Schlumberger) | Laura Anne Schafer (Schlumberger) | Glenn S. Penny (CESI Chemical) | Keith I. Dismuke (CESI Chemical)
- Document ID
- Society of Petroleum Engineers
- SPE Production & Operations
- Publication Date
- August 2010
- Document Type
- Journal Paper
- 376 - 387
- 2010. Society of Petroleum Engineers
- 4.1.2 Separation and Treating, 2.5.2 Fracturing Materials (Fluids, Proppant), 3.2.3 Hydraulic Fracturing Design, Implementation and Optimisation, 1.6.9 Coring, Fishing, 1.8 Formation Damage
- flowback aids, capillary pressure
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- 831 since 2007
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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 water-wetting 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.
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