Client FAQ's

Typically I use the original gamma ray logs, along with shale and clean endpoints defined for each zone, within each well. I then calculate volume shale using the appropriate equation (linear or non-linear). This approach creates a volume shale result which can be compared well to well, because individual clean and shale lines have been selected for each zone, within each well, eliminating the differences between the gamma ray logs.

The other way that this can be done is to first normalize the GR logs, based on a high reading zone and a low reading zone, and then use the normalized GR logs, along with constant shale and clean endpoint values to calculate volume shale. I have used both approaches over the years and prefer the former to the latter to create a consistent volume shale output.

This porosity model usually works well because results are relatively independent of mineralogy and are compensated for gas effects. Porosity calculated this way includes connected porosity as well as isolated micro porosity (if any), but excludes clay bound water and apparent porosity associated with organic matter.

NMR provides two useful porosity values, generally considered to be total porosity (including clay bound water) and effective porosity (excluding clay bound water). We have found that sometimes the effective porosity from NMR also excludes porosity in very fine grained silt. Since there is often not sufficient clay to account for this anomalously low porosity, the only reasonable conclusion is that the fluids in the tiny pores are not “moveable” in the NMR magnetic field. We have found instead that the NMR total porosity is close to the effective porosity from conventional methods in these reservoir types. This also seems to be tool specific.

No, we do not try to distinguish fracture porosity from matrix porosity. Our calculated porosity will include a small contribution from fractures, but the contribution from fractures is extremely low. The log response you see over fractured intervals is markedly exaggerated due to bad log data (sonic spikes, etc.). To remedy, we run multiple porosity models to ensure our outputs are reasonable over intervals where the log data is questionable.

Yes, because this model reverts to the Archie equation in the clean zones (when volume shale goes to zero).

In our petrophysical analysis procedure, we utilize the core water saturation as a guide to the irreducible water saturation in a reservoir above the transition zone. In a core, the difference between residual oil and water saturation is usually the moveable oil fraction of the reservoir fluids, when the reservoir is at initial conditions. In older reservoirs, no longer at initial conditions, there may be some moveable water as well as the moveable oil. This can often be seen on the log analysis results depth plots where log analysis saturation is higher than core SW. The excess water saturation is a measure of potential water production.

In order to employ the Pickett plot, a clean (no clay) water zone must be present. No such zone exists in the subject well.

Buckle’s number, along with porosity can be used to determine a theoretical irreducible water saturation (SWBKL). The SWBKL curve is then presented in the water saturation track of the answer depth plot and can be used qualitatively to highlight intervals which may produce water.  Moreover, when SW is greater than SWBKL, there is a chance that water will be produced, with or without hydrocarbon.

Buckle’s number equals the product of porosity and water saturation (BUCKL=PHIE*SW). The relationship is based on the observation that the product of porosity and water saturation remains relatively constant for a specific zone, provided rock texture remains unchanged. Once Buckle’s number is known, the equation can be rearranged to solve for water saturation, independent of resistivity.

Another way to identify moveable fluid is with NMR data, but these data are often not available.

We like Lucia’s work based on rock fabric number to calculate matrix permeability in carbonate reservoirs.

We don’t calculate fracture permeability, we only calculate matrix permeabiliy. To quantify fracture permeability, a pressure transient test is required.

Generally, core measured water saturation values contain plus or minus five saturation units in error. However, these values are tied to what we would call good quality data. If your core data set is lower quality, the error may be significantly higher.

XRD and EDS are both quantitative methods of determining rock composition. The main difference between the two methods is that EDS determines the elemental composition near the surface of the sample, while the XRD method quantifies the specific compounds present throughout the sample.

The solvent used to remove hydrocarbon for Dean-Stark porosity measurement will not dissolve organics; This means Dean-Stark porosity measurement will not be affected by the presence of organics.

Generally, core measured porosity values contain plus or minus one porosity unit in error at higher porosities and plus or minus half a porosity unit at lower porosities. However, these values are tied to what we would call good quality data. If your core data set is lower quality, the error may be significantly higher.

We can provide mechanical rock properties for wells absent a shear slowness log. Both compressional and shear slowness logs, along with the bulk density log are reconstructed using results from the petrophysical analysis, using the response equation. The model is calibrated against a type well with both sonics available. The type well does not need to be the subject well.

Reconstructed sonic and density logs are generated to remove bad hole, light hydrocarbon, and organic matter effects from the logs so that accurate water-filled rock mechanical properties can be calculated.

This is the standard approach with the AIT tool. Rm is not constant within the borehole and the tool is able to measure Rm during the logging process.

Shale volume is defined as clay bound water plus dry clay matrix.

Typically I use the original gamma ray logs, along with shale and clean endpoints defined for each zone, within each well. I then calculate volume shale using the appropriate equation (linear or non-linear). This approach creates a volume shale result which can be compared well to well, because individual clean and shale lines have been selected for each zone, within each well, eliminating the differences between the gamma ray logs.

The other way that this can be done is to first normalize the GR logs, based on a high reading zone and a low reading zone, and then use the normalized GR logs, along with constant shale and clean endpoint values to calculate volume shale. I have used both approaches over the years and prefer the former to the latter.

When available, the uranium corrected gamma ray log should be used for shale volume calculations.