Well log calibration involves comparing data from the down hole NMR logging tools with lab collected NMR data from well characterized core plugs taken from the same well. Calibrating the “dirty” downhole data with the “clean” lab data allows for more accurate interpretation of the well log.
The variability of certain factors in the natural environment can lead to errors in interpreting the logging information collected during the exploration process. In the laboratory, most of these additional factors can be eliminated or at least controlled by making measurements on fully saturated core samples and on samples that are at irreducible water saturation. These measurements help to distinguish between fluid and pore size effects.
What factors can be calibrated
The two NMR log measurements most often calibrated using core plugs are the T2 cut-off dividing the bound and free fluid, and permeability modelling coefficients.
The so-called “T2 cut-off” in a T2 distribution is the T2 value that divides the small pores that are unlikely to be producible from the larger pores that are likely to contain free fluid. The integral of the distribution above the T2 cut-off is a measure of the free fluid (mobile fluid) in the rock and is clearly influenced by the position of the T2 cut-off point, as shown in the figure below. The portion of the curve below the cut-off is known as bound fluid and is made up of the clay bound fluid and the capillary bound fluid.
An accurate determination of the T2 cut-off point is essential for an accurate determination of recoverable reserves (mobile fluid). T2 cut-off can be easily determined in the laboratory by using two NMR measurements; one on a cleaned and re-saturated plug, the other on the same plug after is has been spun in a centrifuge to irreducible water saturation. T2 distributions are plotted for both data sets, along with the cumulative values of the distributions. The T2 cut-off is taken to be the point at which the cumulative value of the saturated distribution equals the final cumulative value of the irreducible distribution as shown at right.
This measurement should be done on core plugs taken from various zones in the well, with the resulting T2 cut-off values applied retrospectively to the log data from each depth. This will result in a more accurate prediction of Bound Volume Index (BVI) and Free Fluid Index (FFI) than those obtained by applying a single default value of the T2 cut-off to the entire log.
The example at left illustrates how reserve estimates can be seriously under-reported if a standard cut-off value is used without laboratory well log calibration. The samples used in this study were from a tight sandstone play.
In this particular example, laboratory measurements correct the standard cut-off estimate of free fluid index by an average of 260%. This means that this reserve could produce 2.6 times more oil than would have been estimated if well log calibration had not been completed.
Permeability can be calculated from the T2 distribution data using one of two commonly accepted mathematical models: the free-fluid or Coates model can be applied in formations containing water and/or hydrocarbons, while the average T2 or Schlumberger model can be applied to pore systems containing only water and gas. In either case, measurements on core samples are necessary to refine these models by determining the correct values of the coefficients, and produce a model customized for local use. Customization of these models is done by inserting values of the log mean T2, FFI and BVI obtained from core plug NMR measurements, and then varying the coefficients until the best linear fit is obtained against permeability measurements determined by other techniques.
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