Quantification of Fracturing Fluid Migration due to Spontaneous Imbibition in Fractured Tight Formations

Abstract

During hydraulic fracturing operations in low permeability formations, spontaneous imbibition of fracturing fluid into the rock matrix may be responsible for having a significant impact on the retention of water-based fracturing fluids in the neighborhood of the induced fracture. This may consequently affect the post-frac productivity of the well. However, there is lack of direct quantitative and visual evidence of the extent of retention, evolution of the resulting imbibing fluid front, and how they relate to potential productivity hindrance. In this paper, laboratory experiments have been carefully designed to represent the vicinity of a hydraulic fracture. The evolution of fracturing fluid leak-off is monitored as a function of space and time using X-ray computed tomography (CT). The X-ray CT imaging technique allows us to map saturations at controlled time intervals to monitor the migration of fracturing fluid into the reservoir formation. It is generally expected for low permeability formations to show strong capillary forces due to their small characteristic pore radii, but this driving mechanism is in competition with the low permeability and spatial heterogeneities found in tight gas sands. The relevance of capillarity as a driver of fluid migration and retention in a tight gas sand sample is interpreted visually, quantified and compared with high permeability Berea sandstone in our experiments. It is seen that although these formations demonstrate strong capillarity, the effect can be suppressed by the low permeability of the formation and the heterogeneous nature of the sample. However, saturation values attained during imbibition experiments are comparable to those previously obtained for high permeability samples, which can have significant implications in terms of phase mobilities in the neighborhood of induced fractures. Results from this investigation are expected to provide fundamental insight regarding critical variables affecting the retention and migration of water-based fracturing fluids in the neighborhood of hydraulic fractures, and consequently on the post-frac productivity of the well.

Mechanisms and capacity of high-pressure soaking after hydraulic fracturing in tight/shale oil reservoirs

“…Imbibition is significantly important in tight oil reservoir since capillary force is more dominant in such Formation (Yang et al 2018). Most studies suggest that oil can be driven out by imbibition even in mixed-wet samples (Cai et al 2014;Dutta et al Edited by Yan-Hua Sun 2012; Habibi et al 2015). Dutta et al (2012) reported that although the permeability of tight rock is very low, the small characteristic radius suppresses a stronger effect of capillarity; the impacts of permeability and porosity on imbibition should be taken into account.…”

“…Most studies suggest that oil can be driven out by imbibition even in mixed-wet samples (Cai et al 2014;Dutta et al Edited by Yan-Hua Sun 2012; Habibi et al 2015). Dutta et al (2012) reported that although the permeability of tight rock is very low, the small characteristic radius suppresses a stronger effect of capillarity; the impacts of permeability and porosity on imbibition should be taken into account. Habibi et al (2015) proposed that pore surface usually contains both oil-wet and waterwet minerals in tight rock, so the remaining oil might be trapped in small oil-wet pores.…”

Where Does Water Go During Hydraulic Fracturing?

“…Beyond mere curiosity, the fate of this fracking water, whether it remains in the matrix or the fractures, raises both production and environmental concerns. From a production standpoint, because water is immiscible with hydrocarbon there may be the potential for flow reduction if the water resides in small pores within the matrix and physically separates hydrocarbons in the matrix from the fracture network (Dutta et al ; Bostrom et al ). From an environmental view, if this water with anthropogenic additives is primarily in the fractures that act as the principal pathways for the transport through the medium, it raises environmental concerns as the injected water mixes with salt, metals and radionuclides in the shale system, and then could migrate to the groundwater and lead to the contamination of drinking water (Myers ; Jackson et al ).…”

When Less Flowback Is More: A Mechanism of Permeability Damage and its Implications on the Application of EOR Techniques

“…Although unconventional reservoirs are characterized by low or ultra-low permeabilities, several recent studies have shown that imbibition of water-based fluids, while slow, can be significant (Bostrom et al, 2014;Dutta et al, 2012) and thus, at least part of the lost fracturing fluid is believed to invade the formation via spontaneous imbibition. Loss of fracturing fluids can affect the reservoir in several ways.…”

“…Due to the small pore size characteristic of unconventional reservoirs, high capillary pressures are expected when both water and hydrocarbon are present, and thus, loss of fracturing fluid via spontaneous imbibition can be significant, especially during long periods of shut-in. Several studies suggest than such shut-ins can help regain permeability after fluid invasion by redistributing the imbibed fracturing fluid further into the reservoir (Bertoncello et al, 2014;Bostrom et al, 2014;Dutta et al, 2012;Le et al, 2012). How this practice relates to long-term fluid recovery as flowback has not been investigated, although the expectation in such cases is to have little to no produced water.…”