An NMR Study on Shale Wettability

Abstract 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.