GSA Annual Meeting in Denver, Colorado, USA - 2016

Paper No. 33-5
Presentation Time: 2:35 PM


DAS, Saikat1, DHIMAN, Indu2, BILHEUX, Hassina Z.2 and ELLIS, Brian R.1, (1)Civil & Environmental Engineering, University of Michigan, 2350 Hayward Street, 2340 GG Brown Building, Ann Arbor, MI 48109-2125, (2)Chemical and Engineering Materials Division, Oak Ridge National Laboratory, Oak Ridge, TN 37831,

Hydraulic fracturing of shale reservoirs often requires millions of gallons of freshwater but only a fraction of the injected water returns to the surface. The majority of this water is imbibed into the shale. Such water loss in low permeability reservoirs usually results in reduced reservoir gas production, however, shale gas production has been demonstrated to be positively correlated with the amount of water imbibed by the shale. Little is known about the controlling mechanisms that result in enhanced gas production corresponding with a higher amount of water imbibition. Here we study the effect of two commonly used surfactants in hydraulic fracturing on the rate of water uptake within Marcellus shale micro-fractures using an in-situ neutron imaging technique. The rate of capillary rise for fluids containing a 1:1 mixture of two commonly used surfactants in hydraulic fracturing fluids (cationic n-octadecyl trimethyl ammonium chloride (OTAC) and anionic surfactant ammonium dodecyl sulfete (ADS)) was studied within shale micro-fractures through use of neutron imaging at the Oak Ridge National Laboratory High Flux Isotope Reactor. Boltzman analysis was use to fit the water imbibition front along shale micro-fractures to quantify the rate of water uptake and determine the sorptivity constant for each experiment. Initial results suggest a 29% reduction in the rate of water imbibition due to an increase in concentration of the 1:1 ADS/OTAC mixture from 0.1 mM to 0.9 mM. The correlation between the mineral spatial distribution along shale surfaces and initial fracture geometry with the rate of water uptake were also examined. This was accomplished by also examining water imbibition rates along fractures of pure calcite and quartz sample and by systematically varying the fracture aperture of the tested samples. Full 3D CT scans of shales before and after the surfactant exposure were also carried out to reconstruct and characterize the location of water within the rock (e.g., microfractures vs. micropores). Results from this study provide additional insight into the role of surface-active agents in promoting greater water loss and higher gas production in hydraulically fractured shale reservoirs.