, , , , , Jilin Zhang, Daniel T. Georgi, Jordan R. Kone, Jin-hong Chen
Hydrocarbon production from shales using horizontal drilling and hydraulic fracturing has been the key development in the US energy industry in the past decade and has now become more important globally. Nevertheless, many fundamental problems related to the storage and flow of light hydrocarbons in shales are still unknown. It has been reported that the hydrocarbons in the shale rocks are predominantly stored within the kerogen pores with characteristic length scale between 1 nm to 100 nm. In addition, the 3D connectivity of these kerogen pores and possibly with fractures from the micrometer to centimeter scale form the flow path for light hydrocarbons. Therefore, to better model the gas-in-place and permeability in shales, it is necessary to quantify the structural distribution of organic and inorganic components and fractures over a large breadth of length scales. Simultaneous neutron and X-ray tomography offers a core-scale non-destructive method that can distinguish the organic matter, inorganic minerals, and open and healed fractures in 2.5 cm diameter shales with resolution of about 30 υm and field of view of about 3 cm. In the reconstructed neutron volume, the hydrogen-rich areas, i.e. organic matter, are brighter because hydrogen has a larger attenuation coefficient and attenuates neutron intensity more significantly. For the X-ray volume, the attenuation coefficient of an element is related to its atomic number Z and the brighter areas indicate the region containing more high-Z elements such as some heavy minerals. Open fractures do not attenuate either neutrons or X-rays and therefore look dark in both reconstructed neutron and X-ray volumes. In this study, two shale samples from different locations were investigated using simultaneous neutron and X-ray tomography for the first time. We were able to construct 3D images of shales and isolate 3D maps of organic matter and minerals including high-Z element. The distribution of kerogen and fractures can be used in the modeling of hydrocarbon flow in core scale, a 109 upscaling from current methods that model the flow based on SEM images.