Experimental Investigation of Fracturing-Fluid Migration Caused by Spontaneous Imbibition in Fractured Low-Permeability Sands

Abstract

During hydraulic-fracturing operations in low-permeability formations, spontaneous imbibition of fracturing fluid into the rock matrix is believed to have a significant impact on the retention of water-based fracturing fluids in the neighborhood of the induced fracture. This may affect the post-fracturing productivity of the well. However, there is lack of direct experimental and visual evidence of the extent of fluid 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 leakoff is monitored as a function of space and time by use of 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 (5 to 10 md) to show strong capillary forces because of their small characteristic pore radii, but this driving mechanism is in competition with the low permeability and spatial heterogeneities found in low-permeability sands. The relevance of capillarity as a driver of fluid migration and retention in a low-permeability sand sample is interpreted visually and quantified and compared with high-permeability Berea sandstone in our experiments. It is seen that although low-permeability sands are subject to strong capillary forces, the effect can be suppressed by the low permeability of the formation and the heterogeneous nature of the sample. Nevertheless, saturation values attained as a result of spontaneous imbibition are comparable with those obtained for high-permeability samples. Leakoff of fracturing fluids during the shut-in period of a well can result in delayed gas flowback and can hinder gas production. 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 affecting the post-fracturing productivity of the well.

Water imbibition of shale and its potential influence on shale gas recovery—a comparative study of marine and continental shale formations

“…Ghanbari et al (2013) investigated the relationship between flow-back rate and production rate and found that there were quite a portion of wells with low flow-back rate had high production rate. A soak-back technique is then proposed to enhance production after hydraulic fracturing which refers to a period of well shut-in (soaking time) to soak the fracture fluids to improve productivity (Ali Habibi et al, 2015;Dutta et al, 2014).…”

Impact of Petrophysical Properties on Hydraulic Fracturing and Development in Tight Volcanic Gas Reservoirs

“…Nuclear magnetic resonance technique was used in the experiments to clearly distinguish the distribution of the imbibed liquid with the soaking time in volcanic rocks. X-ray CT imaging technique has been previously used to research the spontaneous imbibition of low permeability sandstones [38]. However, this method cannot distinguish the exact distribution of the imbibed liquid, that is, the liquid distribution in the different pore sizes.…”

Enhancing Hydrocarbon Permeability After Hydraulic Fracturing: Laboratory Evaluations of Shut-ins and Surfactant Additives

“…Water-based fracturing fluids are commonly used to fracture tight reservoirs in North America (Wasylishen and Fulton, 2012), and it has been reported that only 5% to 50% of the injected fluid is typically recovered as "flowback" (Zelenev and Ellena, 2009). Water loss to the formation can have detrimental effects on the hydrocarbon flow from chemical and mechanical damage, for example clay swelling or rock softening (Alramahi and Sundberg, 2012;Das et al, 2014;Zhang et al, 2015), to relative permeability damage due to capillary trapping of the water phase and water blocking (Abrams and Vinegar, 1985;Bennion et al, 2000;Dutta et al, 2014;Kamath and Laroche, 2003;Mahadevan and Sharma, 2005;Liang et al, Submitted).…”

“…Although hydraulically fractured reservoirs are normally characterized by permeabilities on the order of microDarcies down to nanoDarcies (Nelson, 2009), several studies have shown that the imbibition of water-based fluids can be significant (Bostrom et al, 2014;Dutta et al, 2014;Pagels et al, 2013). Spontaneous imbibition of water-based fluids can be responsible for the initial fracturing fluid loss to the formation and the creation of a water block.…”