Comparing Permeability from Core and Well Test

Absolute Permeability is the measure of the ease of flow of a fluid through the reservoir rock. It is a rock property that is independent of the fluid type as long as that fluid occupies 100% of the conductive pore space.

Rock permeability is an important property as it governs oil and gas production rate. It is of great economic significance in reservoir management and development for determining the number of wells and their location in a field, optimizing production rates, selecting completion and perforation strategies, as well as devising injection and production patterns.

There are three main sources of permeability values

1. Correlation with wireline logging measurements (not discussed here)

2. Laboratory analysis of core samples

3. Analysis of data from pressure-transient tests

Measurements of permeability at the various scales of interest are often compared. Usually those values are different and this difference must be explained. The most common comparison is between core permeability and well-test permeability.

Laboratory core permeability is measured on core plug samples or full diameter core. Gas or liquid flow through a core that is contained in a core holder to prevent fluid bypass. Permeability determined from core analysis is dependent on the specific laboratory conditions under which it was measured. Core permeability does not reflect the permeability experienced in the reservoir.

After correcting for in-situ conditions, permeability from one-foot lengths of core or 1.5-inch long core plugs are usually aggregated and averaged to represent a hydraulic unit or flow section of the reservoir.

A transient well test is the only method that allows estimates of permeability-thickness, kh, or flow capacity at a truly in-situ condition. kh from a well test is an average over a volume thousand times larger than core permeability.

Permeability thickness has an error associated with it because of uncertainty in all of the input parameters

• Rate - well test separators can be subject to gas entrainment, liquid carryover, poor meter calibration, foamy crudes, and other operational problems that affect the accuracy of measurements used to calculated flow rate

• Formation Volume Factor and Viscosity - If PVT analysis is unavailable, fluid properties have a large uncertainty

• Pressure - Pressure sensors are subject to poor calibration, creep, temperature effects, and hysteresis

• Reservoir Thickness - If permeability is to be extracted from permeability thickness, an estimate of reservoir thickness contributing to flow must be available. This is not always easy of straightforward, especially if production logs were not run during the test.

Reasons for differences between core and well-test permeability

Scale of measurement

Well-test permeability represents an average of the vertical and horizontal permeability in the region of the reservoir investigated by the well test. Routine core permeability typically has a length scale of inches. The presence of flow barriers, karsts, fractures, vugs, pinchouts, and changes in reservoir quality on a slightly larger dimension will not be reflected in the core permeability.

Reservoir thickness contributing to flow

Analysis of well-test data gives permeability thickness. Routine core analysis gives permeability at the plug or core level. Either the contributing thickness must be estimated from petrophysics or based on production logging results or the pressure transient analysis or the core permeability must be aggregated and averaged to obtain a consistent basis for comparison.

Absolute versus Effective Permeability

Routine core permeability represents the absolute single-phase permeability of the sample to air or a gas. Well-test permeability is impacted by the presence of multiple phases in the reservoir and is thus an effective permeability. Effective permeability may be 70 to 95% of the absolute value.

Stress Conditions

When core is taken from the reservoir, there is a change in stress conditions that may change the nature of the interactions in a rock. Net overburden stress is often re-applied to the core before making permeability measurements. The stress magnitude and orientation may not reproduce the in-situ stress. In general, it is difficult to preserve the exact in-situ conditions when obtaining and conducting measurements on core samples. On the other hand, well-test permeability is an in-situ measurement.

Conclusions

1. Well tests dynamically measure flow rate and pressure from which permeability thickness at reservoir conditions are estimated.

2. Average core permeability should be conditioned with appropriate well-test permeability to predict or match accurately well, reservoir, and field production performance.

3. Integration of all petrophysical, production, and build-up data is important to identify correctly the producing characteristics of a reservoir.

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