Nuclear magnetic resonance (NMR) can be used to determine properties of a substance. An NMR measurement includes applying a static magnetic field to the substance. The static magnetic field generates an initial magnetization of atomic nuclei within the substance. Then, an oscillating magnetic field is applied at a particular frequency to the substance. The oscillating field is composed of a sequence of radio frequency (RF) pulses that tip the magnetization of the atomic nuclei away from the initial magnetization. The sequence of pulses can be arranged so that the pulses and the static field interact with the nuclei to produce a NMR signal composed of “echoes” within at least a portion of the substance. The NMR signal is detected and can be used to determine properties of the substance.
In the oilfield industry, NMR measurements are one of the main petrophysical tools for formation evaluation. In addition to evaluating formation porosity, NMR measurements can be used to identify fluids and to determine fluid mobility within confining reservoir rock geometries. More specifically, NMR response of the fluid in the reservoir rock carries information about (i) fluid properties, such as viscosity, composition, (ii) characteristics of the confining geometries, such as pore size distribution, tortuosity, and permeability, and (iii) fluid-rock interaction, such as wettability.
NMR has a long history of successful deployment in conventional reservoirs. However, the ability to produce unconventional reservoirs, such as shale oil and shale gas formations, has resulted in re-assessment of logging methods and data interpretation. New parameters that are used for log interpretation of unconventional reservoirs include kerogen content, bitumen, content, oil content, gas content, and total organic content (TOC). The new parameters also include the state/location of hydrocarbons in the complex geometries of pore space within reservoir rock, which includes oil-wet organic matter porosity and water or mix-wet inter/intra-granular porosity. In conventional reservoirs, the amount of bitumen and kerogen are typically very small, whereas, in unconventional reservoirs, porosity is low (e.g., 5%) and the relative amount of kerogen and bitumen is much greater. The content of these kerogen and bitumen constituents is indicative of reservoir maturity. Furthermore, TOC is highly correlated with the producibility of a shale reservoir and, because of this correlation, TOC is a valuable measure in the evaluation of unconventional reservoirs.
Conventional oilfield NMR techniques are not able to determine many of these new parameters because unconventional reservoirs, such as shale formations, have short T2 relaxation times. For example, shale formations are characterized by T2 relaxation times below 0.03 seconds. Conventional oil field NMR techniques do not detect T2 relaxation times below 0.03 seconds. Thus, conventional techniques do not provide for efficient and accurate characterization of parameters, such as kerogen content, bitumen content, and TOC.
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