The log derived total water saturation (Swt) is lower than a surface (laboratory) measurement of total water saturation remaining in the core, Core_Swt. Hydrocarbon fluids leak as the core is brought to the surface. Previous interpreters have noted this fact and either used preserved core or ignored the differences. Now we have a solution to reconcile both measurements. The maximum lost fluids are equivalent to the hydrocarbon-filled portion of the free porosity measured by a nuclear magnetic resonance log (NMR). The method for calculating the log-derived surface saturation, Sw_surface is to first determine the hydrocarbon pore volume, (HCPV). Then subtract the free hydrocarbon volume. Convert the net hydrocarbon volume to saturation using the total porosity. Why is this method important? There are very few preserved core measurements of Sw. This method provides a comparison of core and log Sw that does not require a preserved core. However, the method is not exact because the free hydrocarbon-filled porosity within the core pore space is not the same volume as the portion of that free hydrocarbon volume that bleeds from the core as the core is retrieved to surface. The measurements that we used are resistivity, spontaneous potential (SP), elements from nuclear spectroscopy, bulk density, neutron, NMR and, of course, Core_Swt to compare to.

The plot at the end of the abstract shows our goal: compare core Sw to log derived Sw_surface so that one compares both log and core at the same surface conditions.

Core Sw can be used to confirm log Sw when there is a free fluid measurement to assist and complete mineral-based log interpretation is used.

We show several examples: Bitumen sands, as well as conventional and unconventional (Montney).

An example is presented from a low porosity zone with high permeability. Core_Sw is higher than the log derived in situ Sw.

Another example is very high free porosity so the core Sw initially looks like it is mis-scaled.

In Bitumen oil sands, the NMR clearly shows there is free porosity in situ even though at the surface the bitumen is not mobile. In addition, our method to obtain Rw from the SP is innovative and provides a good variable Rw value to use in the Water Saturation Equation (Ref. 1) for the bitumen sands and shales. The Cation Exchange Capacity (CEC) is obtained by identifying the clay families and their associated CEC. The same methodology is followed for the all examples.

An example is shown in the Unconventional Montney formation where the permeability is very low. As the permeability decreases, the fluid loss from the retrieved core also decreases.

The method shown is empirical, designed for the Petrophysicist who does not have a research laboratory available. There is some adjustment required when the NMR is unable to "see" certain hydrocarbons due to the nature of the measurement (such as dry gas). However, the results certainly show whether the log interpretation is validated by core, despite not having preserved core.

Figure Abstract-1. The two data points for Core_Sw correspond almost exactly to Sw corrected to surface.

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