Page 196 - Machine Learning for Subsurface Characterization

Dimensionality reduction and clustering techniques Chapter 6 169

4.2.2 Step 2: Determination of pore volumes of various fluid
phases represented by the decomposed factors
The decomposed factors are converted to factor volumes using Interactive
Petrophysics to associate each factor with a fluid phase. Various
combinations of factor volumes are then compared with the bound- and free-
fluid volumes estimated from NMR T2 distribution using a specific T2
cutoff [33]. For the formation of interest, the T2 cutoffs for clay-bound
water and free fluid are reported to be around 0.411 and 0.958 ms,
respectively. With these cutoffs, fluid volume for T2 0.411 ms represents
clay-bound fluid, fluid volume for 0.411 ms T2 0.958 ms represents
capillary-bound fluid, and fluid volume for T2 0.958 ms represents free
fluid. As shown in Fig. 6.5A, track 1 is the original T2 signal for the middle
shale. The next set of tracks is the decomposed factors of the original T2
signal computed using factor analysis. Total bound fluid-filled porosity, free
fluid-filled porosity, total water-filled porosity, and hydrocarbon-filled
porosity were obtained using petrophysical interpretation. Bound- and free-
fluid porosities can be directly calculated from NMR T2 and cutoffs. Total
water saturation is calculated using dual-water equation with resistivity log
and then can be transformed into total water porosity. The process is built in
the NMR interpretation module in Interactive Petrophysics software.
Following that, porosities obtained using various T2 cutoffs are compared
with the porosities of factor volumes in Fig. 6.5A. Factor 4 is identified as
the signature of bound fluid (both clay-bound and capillary-bound) for the
upper and lower shales (Fig. 6.5B and C). For that case, the factors 1, 2, 3,
and 5 are identified as the signatures of free fluid. By further comparing the
porosity of free-fluid factor volume with free water and free hydrocarbon pore
volumes, factors 1, 2, and 3 are identified as the signatures of free
hydrocarbon, and factor 5 is identified as the signature of free water
(Fig. 6.5B and C). The sum of factors shows good agreement with different
fluid porosities acquired from T2 cutoffs, as shown in the last four tracks of
Fig. 6.5A–C, which is the best for upper and lower shales.

4.2.3 Step 3: Correction of miscible, free-oil volume for pore
confinement effect
MD-index is the relative volume of the positive and the negative petrophysical
components influencing oil displacement by a light hydrocarbon (Eq. 6.5).
Calculation of MD-index requires fluid type porosities, which are derived
from the decomposed factors and corresponding fluid types. However, the
free oil-filled porosity calculated using factor analysis cannot be directly
used in Eq. (6.5), because not all free oil can achieve miscibility. Under
certain conditions, only the free oil in smaller pores can achieve miscibility
due to the pore-confinement effects. MMP of the injected light hydrocarbon
and the pore-filling in situ hydrocarbon mixture is reduced in nanopores.