Spontaneous Imbibition of Fracturing Fluid and Oil in Mudrock

Abstract

Spontaneous imbibition of treatment fluids into rock matrix during hydraulic fracturing is believed to be one of the major reasons for the early high productions from shale oil reservoirs. In this study, we integrated Focused Ion Beam-Scanning Electron Microscope (FIB-SEM) tomography and non-destructive X-ray nanotomography techniques to study the spontaneous imbibition of oil and brine solutions in shale nanopores. First, a piece of argon-polished reservoir mudrock sample was imaged at high resolution by SEM to find areas of interest. Then, small cylindrical rock sample (20 m diameter) was cut carefully using FIB. The cylindrical core sample was then cut free from the bulk rock sample and attached to the tip of a needle. The miniature core were transferred into an X-ray CT scanner and imaged prior to exposure to any fluids (dry state). Then spontaneous imbibition tests were performed using an in-situ flooding apparatus. In order to represent fluid invasion by hydraulic fracturing in shale oil reservoirs, first, crude oil doped with 2 wt.% iodooctane was introduced to the core followed by brine (15 wt.% NaI) spontaneous imbibition. In the next step, a solution of nonionic surfactant (0.1 wt.%) was added to the core sample and extra brine imbibition was observed. The sample was scanned (voxel resolutions of 64 nm) and the pore-fluid occupancy was explored at the end of each imbibition step. The results showed that both brine and oil imbibed into the core. Nonionic surfactant increased the recovery by about 15%. This might be as a result of lower IFT and contact angle, which also has been reported in the literature. Moreover, during the last test, oil also imbibed into the pore space, due to the fact that the surface became less water wet as a result of surfactant injection prior to this test.

The Influence of Oil Composition, Rock Mineralogy, Aging Time, and Brine Pre-soak on Shale Wettability

“…The oil-wetness is believed to cause a greater effect in a tighter reservoir, i.e., shale oil reservoirs, due to the stronger boundary effect from the pore wall to the pore throat. To solve this problem, several authors have investigated the application of surfactants as an EOR (enhanced oil recovery) technique by altering the shale wettability from oil-wet to water-wet. − To design a surfactant system with strong wettability alteration performance, we must first understand the surface oil-wetting mechanism. This is important because minerals commonly found in the reservoir, i.e., quartz, calcite, dolomite, and clay, are actually water-wet after deposition.…”

“…A look through the available literature indicates that the duration of the aging process that was employed for surfactant studies in shale varied from zero time up to a year (Figure ). ,,,,,,− This is worrying because several authors have presented the effect of the aging process on flow behavior. Jia et al investigated the effect of the aging time on the rock wettability measured on the Amott–Harvey index.…”