Comparison of Flowback Aids: Understanding Their Capillary Pressure and Wetting Properties
- Paul R. Howard (Schlumberger) | Sumitra Mukhopadhyay (Schlumberger) | Nita Moniaga (Schlumberger) | Laura Schafer (Schlumberger) | Glenn S. Penny (CESI Chemical) | Keith I. Dismuke (CESI Chemical)
- Document ID
- Society of Petroleum Engineers
- 8th European Formation Damage Conference, 27-29 May, Scheveningen, The Netherlands
- Publication Date
- Document Type
- Conference Paper
- 2009. Society of Petroleum Engineers
- 2.7.1 Completion Fluids, 5.8.1 Tight Gas, 5.1 Reservoir Characterisation, 4.1.2 Separation and Treating, 5.1.1 Exploration, Development, Structural Geology, 2.5.2 Fracturing Materials (Fluids, Proppant), 2.4.3 Sand/Solids Control, 4.3.4 Scale, 1.6.9 Coring, Fishing, 1.8 Formation Damage
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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 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.
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