Dynamic 3D Imaging of Fluid Mobility in Natural Fractures Using High-resolution Positron Emission Tomography
Authors: Maucec Marko , Dusterhoft Ron , Rickman Richard , Gibson Ron , Buffler Andy , Stankiewicz Maciek , van Heerden Michael 
Published: May 2016

Abstract
Positron emission tomography (PET) continues to have wide-ranging medical application and is based on the detection of gamma radiation emitted from the decay of certain types of radionuclides. Modern PET scanners produce three-dimensional (3D) images of the radiation source, in discrete time steps, using tomography analysis. This paper presents an application of PET for studying fluid mobility in pressurized low-permeability rocks in the presence of natural fractures. This technique uses a high-resolution PET scanner and image reconstruction based on filtered back-projection. Traditional techniques have been limited to pressure measurement of fracture conductivity and effective permeability, but little is understood about the dynamic flow and velocity profiles within the fracture.
The objective of this work was to investigate if it is possible to measure the dynamic (e.g., time-lapse and continuous) distribution of the fluid flow as a function of the overburden stress. PET imaging was applied to the flow of a brine solution, which was tagged with 18F-fluorodeoxyglucose (FDG) positron emitting radionuclide, through nonfractured sandstone and naturally fractured shale cores. A special composite container was manufactured to sustain high-pressure conditions and minimize the absorption of emitted gamma rays. The experimental apparatus is described, and it is demonstrated that the 3D images obtained with a grid resolution of 2 ´ 2 ´ 2 mm3 allow clear determination of the fluid flow rate through the core as a function of overburden pressure and time. PET images are direct observations of the radiation source and allow an unambiguous determination of the fluid distribution in the core. The results of this research can be used to validate the numerical modeling of fluid flow through fractured rock matrices, to enable more accurate estimates on the directionality of fractures from the fluid distribution as a function of time, and to obtain more quantitatively sound estimates of fracture connectivity.

Introduction
One of the key issues the oil and gas industry is facing today is that fracturing (King 2012) to achieve economic production from unconventional plays (e.g., shale) is significantly different from the fracturing practiced during the previous 60 years (Soliman 1986; Soliman et al. 1990). Traditionally, fracturing treatments were designed to achieve long, effective fracture half-lengths and conductivity in millidarcy (md) and microdarcy (md) rocks. However, ultralow-matrix permeability is now being considered in formations such as shale that geologists used to consider seals. Under these conditions, the ultimate challenge is to design treatments to expose the maximum possible surface area to provide a path for the fluids to propagate back to the wellbore. Conventional bi-wing fractures in vertical wells cannot achieve and maintain economic production under these conditions, and multiple transverse fractures in horizontal wells are used to create complex fracture networks. While, in the past, the goal was to maximize the fracture length and width, the objectives now are to maximize the stimulated reservoir volume (SRV), optimize the fracture complexity within the SRV, identify the associated uncertainties, and help minimize the risk for economical application (King 2012; Edwards et al. 2007). The complexity of the problem requires a better understanding of fracture conductivity and its influence in low-permeability rocks, such as shale. Moreover, what really must be understood is how these unsupported and partly supported fractures will behave under production conditions.