Most core analysts know that NMR can determine porosity and pore size distributions easily and quickly, but what about fluid mobility such as Bound Volume Irreducible (BVI), Free Fluid Index (FFI), Clay Bound Water (CBW), and effective porosity?
Furthermore, what about permeability, capillary pressure, and oil/water or gas/water contents? NMR core analysis can measure all of these parameters quickly and accurately. Let’s start with a little background!
Technical Background
Essentially, NMR signals are generated from liquids (oil or brine) when the sample is placed in a magnetic field and then excited with a brief pulse of radio frequency (RF) energy. Immediately after the pulse, an NMR signal appears, which then dies away with a characteristic relaxation time or decay rate known as T2. The amplitude of the signal immediately after the pulse is an indication of the total amount of fluid present, while the T2 of the signal gives valuable information about the physical environment of the liquids.
In pores filled with a single fluid, there are two main components to the NMR signal – one coming from the fluid far from the pore walls, and the other from fluid close to the pore walls. Fluids far from the pore walls give NMR signals similar to those from bulk fluids, with relatively long relaxation times, while fluids close to the pore walls undergo a process of adsorption and desorption with the pore walls which has the effect of dramatically reducing their NMR relaxation times.
In large pores, the dominant effect is from the bulk fluids, so larger pores tend to have longer NMR relaxation times. In smaller pores, the surface-to-volume ratio is much higher, so the fluids close to the pore walls tend to dominate the NMR signal, and smaller pores show overall shorter NMR relaxation times. This process is illustrated in the figures below.
Of course, in a real measurement it is not possible to take NMR measurements from individual pores. The whole core must be measured at once, so the resulting NMR signal is a composite of all the NMR signals from different pore sizes in the core.
The next step is to use a mathematical procedure known as an inversion to process the composite NMR signal and separate it out into its component parts. In theory, there is one T2 component for each different pore size in the core. But in practice, the analysis is usually restricted to a maximum of about 256 individual T2 components, which is more than adequate for most practical purposes. The result of the inversion process is a T2 distribution showing the relative population of the individual T2 decay times that make up the composite NMR signal from the core. Because long T2s come from large pores, and short T2s from small pores, this T2 distribution is in effect a model of the pore size distribution in the core.
Our NMR instruments are calibrated so that the Y axis is volume of water observed and hence the sum under the T2 distribution is the pore volume of the rock sample being investigated. Once the pore volume is known it is easy to get the porosity if the bulk volume of the sample is known.
Furthermore, with the basic pore size distribution, a number of useful parameters can be quickly and easily inferred. Check out our Well Log Calibration page to learn more.