Recent experiments show the strong water uptake of gas shales which are strongly oil-wet based on contact angle measurements. 1,2 Clay hydration, microfracture induction, lamination, and osmotic effect are collectively responsible for the excess water uptake. However, the previous measurements are not sufficient to isolate the above factors nor to explain why the bulk of shale samples can hardly imbibe the oil which completely spreads on their surface. To answer the remaining questions, we measure and compare spontaneous imbibition of oil and water into the crushed packs of the similar shales. In contrast to the intact samples, the crushed samples consistently imbibe more oil than water. The comparative study suggests that the connected pore network of the intact samples is water wet while the majority of rock including poorly connected pores is oil-wet. This argument is backed by complete spreading of oil on fresh surfaces of the rock. In contrast to the artificial pores of crushed rock, the existing pores of intact rock are already wetted by a film of water and/or covered by precipitated salt, which gives the pores a preference for water over oil. Furthermore, the presence of salt in the pore space provides an additional force for water uptake through an osmotic effect. This argument is backed by the observed reduction in shale alteration and water imbibition through increasing the salt concentration.

A shotgun proteome analysis method and its performance for protein identification from 500 to 5000 cells are described. Sample preparation, which was done in one tube, involved the use of a surfactant (NP-40) for cell lysis, followed by acetone precipitation of the proteins. The resulting protein pellet was washed with cold acetone to remove remaining surfactant, and the pellet was then solubilized in NH(4)HCO(3). After trypsin digestion of the proteins, the digest was analyzed by the use of nanoflow liquid chromatography (LC) quadrupole time-of-flight mass spectrometry (QTOF MS). Sample injection and gradient speed in running LC QTOF MS were optimized. It was shown that this method could identify an average (n = 3) of 167 +/- 21, 237 +/- 30, 491 +/- 63, and 619 +/- 59 proteins from 500, 1000, 2500, and 5000 MCF-7 breast cancer cells, respectively. To demonstrate the potential use of this method for generating proteome profile from circulating tumor cells (CTCs) isolated from human blood, a healthy human blood sample was spiked with MCF-7 cells, and this mixture was processed and then subjected to antibody tagging of the MCF-7 cells. The tagged cells were sorted and collected using flow cytometry. The proteome profiles of small numbers of cells isolated in this way were found to be similar to those of the original MCF-7 cells, suggesting the possibility of the use of this method for cell typing of CTCs.

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We conduct spontaneous imbibition experiments using different fluids (deionized, DI, water and brines) and different media (unwashed and washed shale powder) to study the wetting behavior of the shale samples from the Horn River Basin (HRB), a massive unconventional gas play in the Western Canadian Sedimentary Basin. As expected, unwashed shale powder imbibes DI water faster than brine. Surprisingly, washing the powders results in faster imbibition of DI water. The imbibition of DI water into washed shale powders, which have a reduced soluble/leachable ion content, cannot be fully explained by osmotic effects. We explain the observed imbibition profiles using the electrostatic interaction theory. We measure the ion concentration of the brines by ICP-MS analysis and determine the ionic strength, I, of the in situ formed brine. We also calculate the characteristic thickness of electrostatic double layer, κ–1, formed around the surface of charged shale powders. The results indicate that the imbibition rate depends on the κ–1value of the in situ formed brine. Electrostatic interaction is part of the disjoining pressure which is not considered in the Young–Laplace equation. A higher κ–1 value enlarges the electrostatic interaction range, which results in formation of a thicker hydration shell around the surface of the shale powder and increases the imbibition rate.