Shales have become one of the leading unconventional gas resources in the world today, but a detailed understanding of their petrophysical properties still eludes most researchers. Wettability is an important rock property as it affects the recovery and stimulation methods and the quantity of hydrocarbon recovered. We present a study of shale wettability using Nuclear Magnetic Resonance (NMR) to monitor sequential imbibition of brine and oil (dodecane). Mineralogical variations, low permeability and porosity, complex pore structure, and the presence of organics complicate the interpretation of wettability in shale reservoirs and renders conventional approaches useless. The presence of organics has been reported to affect shales by reducing density, altering wettability, increasing porosity, amongst other effects. NMR, a non-destructive technique, has been applied to study wettability in other lithologies; we have applied it to study shale formations. A total of 50 samples were analyzed; 21 core plugs from the Eagle Ford shale, 12 from the Barnett, 11 from the Floyd shale, and 10 from the Woodford shale. Berea sandstone, known to be water-wet was analyzed and provides a calibration standard. Our NMR study confirms that Berea sandstone exhibits water-wet behavior. The shales studied imbibed both brine and oil, and the volume of oil imbibed is influenced by a combination of Total Organic Carbon (TOC), thermal maturity, and organic pore volume. The Woodford shale showed more affinity for dodecane compared to the other shales. The T2 NMR signature of the imbibed dodecane occurs mostly at relaxation times ranging from 2–20ms, much faster than its measured bulk relaxation of 1 second, suggesting that surface relaxation dominates the oil response in the shales. The observed brine T2 relaxation peak is predominantly below 1ms range, compared to its measured bulk value of 3 seconds. The shales display mixed wettability, with the organics contributing mainly to the oil-wetness. Exposure to drilling fluids could affect the "as received" wettability state of the cores; this effect needs to be investigated further. We extend our observations to explain the loss of hydraulic fracturing fluid in shale formations. Our study shows that imbibition of fracturing fluid by the formation is a possible cause of high fluid losses during hydraulic fracturing. Additionally, the possibility of estimating microfracture widths from T2 spectra was explored. Fracture widths ranging from 1–10 microns were estimated from the NMR T2 spectra, and this compared favorably with estimates from Micro-CT x-ray images.

Summary The application of nuclear-magnetic-resonance (NMR) methods to evaluate the fluid content in hydrocarbon reservoirs requires the understanding of the NMR response of the fluids present in the rock. The presence of multiple fluids such as liquid, gaseous, or adsorbed phases in nanometer-sized pores (associated with various minerals and organic matter) adds another degree of complexity to the interpretation of NMR data in shales. We present a laboratory study on the NMR responses of brine, oil, and methane in shales at 2 MHz. NMR transverse relaxation time (T2) distributions were acquired on core plugs from the Haynesville, Barnett, and Woodford shale formations. The NMR T2 distributions were acquired after brine (2.5% potassium chloride) and oil (dodecane) imbibition and saturation. After brine imbibition, we observed an increase in porosity at T2 ≤ 1 ms. However, after saturation at increasing pressures we observe a porosity increase at T2 ≈ 6–20 ms. Dodecane imbibition and saturation induced a porosity increase at T2 ≈ 10 ms. The measurements with methane were conducted on Haynesville core plugs at a methane pressure of 4,000 psi. The NMR T2 signal of methane in shales appears to be at approximately 10 ms. These results show that the NMR response of methane and oil is very similar in shales. Monitoring the saturation increase with NMR shows that brine can enter the entire pore spectrum, whereas oil and methane have access only to a fraction of the pore space.

The application of NMR methods to evaluate the fluid content in hydrocarbon reservoirs requires the understanding of the NMR response of the fluids present in the rock. The presence of multiple fluids which can be in liquid, gaseous or adsorbed phase in nanometer size pores (associated with various minerals and organic matter) add another degree of complexity to the interpretation of NMR data in shales. This report presents the findings of a laboratory study on the NMR responses of brine, oil and methane in shales. The acquisition of the NMR data was made at 2MHz. NMR T2 distributions were acquired at TE = 0.2ms on companion core plugs from the Haynesville shale and at TE = 0.3ms for Barnett and Woodford shale samples. The NMR T 2 distributions acquisitions were conducted on samples saturated with brine (2.5% KCl) and oil (dodecane). The NMR T 2 data acquired on the native state samples (as received) showed a bimodal distribution with the dominant peak at T 2 less or equal to 1ms. After saturation in parallel with oil and brine with increasing saturation pressures we observed in the case of brine an increase in amplitude of the NMR peak located at T 2 less or equal to 1ms. At higher saturation pressures we observed a shift in the T 2 time of this peak toward longer T 2 times. When the samples were saturated with oil and the saturation pressure increased we observed the development of second NMR T 2 peaks around 6-20 ms with no substantial increase of the peaks at T 2 less than 1ms; the observed distributions are bimodal. The measurements with methane were conducted at TE = 0.3ms on 2 Haynesville core plugs at a methane pressure of 4000 psi and a confining pressure of 5000psi. The NMR T 2 distributions that were essentially unimodal in the as received state with a peak at 0.35-0.4ms, evolved into a bimodal distribution in response to the injection of methane. The first peak was observed at the same T 2 time as in the as received state with no substantial change in amplitude and second peak was located at 10-20ms ms. This results show that the NMR response of methane and oil is similar. Monitoring the saturations increase with NMR show that brine can enter the entire pores spectrum while oil and methane have access only to a fraction of the pore space.

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