New methods to evaluate impacts of osmotic pressure and surfactant on fracturing fluid loss and effect of contact angle on spontaneous imbibition data scaling in unconventional reservoirs. (15th November 2022)

• Record Type: Journal Article
• Authors: Pan, Bin; Clarkson, Christopher R.; Younis, Adnan; Song, Chengyao; Debuhr, Chris; Ghanizadeh, Amin; Birss, Viola I.
• Is Part Of: Fuel. Volume 328(2022)
• Publication Date: 2022-11-15
• Subjects: Fracturing fluid loss -- Unconventional reservoirs -- Osmotic pressure -- Surfactant -- Pore- contact angle -- Spontaneous imbibition data scaling; Fuel -- Periodicals; Coal -- Periodicals; Coal; Fuel; Periodicals; 662.6
• DOI: 10.1016/j.fuel.2022.125328
• Languages: English
• ISSNs: 0016-2361

Abstract

Highlights: A new method is presented to study osmotic pressure impact on fracturing fluid loss. A new approach is proposed to examine surfactant impact on fracturing fluid loss. θ pore results in better spontaneous imbibition data scaling than θ macro and θ micro . Abstract: Osmotic pressure ( P osmotic ) is an important mechanism for fracturing fluid loss in clay-rich unconventional reservoirs. Surfactant is often added to the fracturing fluid to control this loss. While laboratory-based methods can be used to evaluate the impacts of P osmotic and surfactant on fracturing fluid loss, two important challenges exist in the commonly-used methods: 1) a pair of sister core plugs have to be used; and 2) the petrophysical properties of the sister core need to be very similar for meaningful comparisons, which may be impossible in many cases. In addition, for the scaling of laboratory spontaneous imbibition data, wettability (i.e., contact angle, θ ) should be incorporated into the scaling model. However, θ is a scale-dependent parameter, e.g., macro- ( θ macro ), micro- ( θ micro ) and pore- ( θ pore ) contact angles can vary significantly. It is currently uncertain which θ should be used in the scaling model. Therefore, the objectives of this work are: 1) to develop two new methods, which address the aforementioned limitations, to study the impacts of P osmotic and surfactant on fracturing fluid loss in unconventional reservoir samples; and 2) to evaluate the impact of θ macro, θ micro, and θ pore on laboratory spontaneous imbibition data scaling. The primary findings of this study include: 1) the impact of P osmotic on fracturing fluid loss is significant and rapid for the studied clay-rich Duvernay shale samples; 2) cationic dodecyltrimethylammonium bromide increases fracturing fluid loss by 46% for the studied Montney sample; and 3) θ pore results in more confident scaling of laboratory spontaneous imbibition data for the studied Montney samples compared to θ macro and θ micro . This work provides effective methods to evaluate the impacts of P osmotic and surfactant on fracturing fluid loss in unconventional reservoirs and demonstrates the importance of using θ pore for the scaling of laboratory spontaneous imbibition data. Moreover, this study adds to the fundamental understanding of fracturing fluid loss mechanisms and controls in unconventional reservoirs.