In the early days of formation evaluation, two types of tools existed – a resistivity tool and a porosity tool. Neither tool independently was able to provide what operators really wanted – water saturation. If they knew the water volume, subtraction would lead them to oil volume.

In 1952, G.E. Archie set out to master this problem by formulating a relationship between resistivity and porosity to derive fluid saturation. In clean reservoirs with consistently saline formation water, this formula worked well.

But freshwater is less resistive than saline water, and even within a single reservoir layer there can be variations in formation water resistivity. Additionally, Archie’s equation did not take clay or shale effects into account. Over the years, the equation has had to be continually tweaked and modified to be representative of actual downhole conditions.

The Dielectric Scanner is the newest member of the Schlumberger Scanner family of wireline tools and is fully combinable. (Images courtesy of Schlumberger)

Currently, different saturation equations exist to represent different oilfield environments, but assumptions about the rock texture, formation water salinity, clay volume, and saturation exponent are required. “It’s all of these assumptions that cause the shortcomings of standard saturation equations,” said Tarek Rizk, Dielectric Scanner product champion, Schlumberger Wireline. The water resistivity, for instance, often is unknown not only in exploration wells, but also in producing fields, where injection water might have a different resistivity than formation water. And since neither freshwater nor oil conduct electricity very well, there will be little or no resistivity contrast in formations with freshwater.

What has been needed was a logging tool that can replicate fluid volume measurements that have been conducted in core laboratories for years. These measurements do not rely on water resistivity measurements at all, making assumptions unnecessary. The Schlumberger Dielectric Scanner multifrequency dielectric dispersion service is the first such service to be introduced to the market.

How it works
Dielectric logging tools are not new – they were first introduced more than 30 years ago. Their limitation has been their single frequency. Interpretation of this information cannot account for textural effects, invasion, mudcake correction, and unknown or variable water saturations.

So what is dispersion? It is the variation of one parameter with respect to another. Rizk compared this to measuring the length of a section of railroad track. It can be measured very accurately, but if the ambient temperature rises, the metal expands, and the track will no longer measure the same, even though it is the same piece of metal. It needs to be measured at several different temperatures to characterize its true length.

“In this case, dispersion is the variation of the measurements with respect to frequency,” he said.

The Dielectric Scanner takes four frequency measurements ranging from 20 MHz to 1 GHz. The dispersion is plotted, which gives an accurate measurement of the dielectric conductivity and permittivity, or the ratio of the flux density produced by an electric field in a given dielectric to the flux density produced by that field in a vacuum. “Without this, operators have to make the assumptions that were made with the previous generation of tools,” he said. The plot constructs an accurate radial profile of the close-borehole region, providing new and unique information on rock properties and fluid distribution for advanced petrophysical interpretation. The tool has multiple applications, including solving for:

-Residual hydrocarbon volume in produced reservoirs;

-Low-resistivity or low-contrast evaluation in shaly and laminated sand formations;

-Hydrocarbon volume and mobility in heavy oil reservoirs;

-Invaded zone water salinity;

-Continuous Archie rock texture/cementation (nm) log in carbonates for determining saturations beyond the invaded zone; and

-The cation exchange capacity to account for the effect of clay volume in siliciclastics.

It also provides a high-resolution water-filled porosity for thin-bed analysis.

In this example, movable heavy oil has been confirmed by sidewall cores. Although the resistivity in Track 5 and nuclear magnetic resonance in Track 7 cannot readily distinguish between oil and formation freshwater below the oil-bearing interval from X,430 to X,500 ft, Dielectric Scanner measurements of fluid volumes (Track 6) and the resulting saturations (Track 2) clearly reveal significant movable heavy oil down to X,720 ft, as confirmed by sidewall core analysis.

The software provides quality control (QC) and interpretation for the service. After preprocessing and applying QC to raw data, it performs a radial interpretation of the different spacing and polarization measurements to provide dielectric dispersion data. Lithology and porosity analysis integrates measurements from different tools and is performed in the same application to determine total porosity and formation matrix permittivity. This information is used with the dispersion in a final interpretation step in which models determine water-filled porosity, water salinity, and textural parameters.

The tool can log 3,600 ft/hr (1,097 m/hr) and provides a vertical resolution of 1 in. It has a depth of investigation of 1 to 4 in. and can withstand temperatures of 302ºF (150ºC) and pressures up to 25,000 psi. Measurements can be taken in both water- and oil-based muds.

Case studies
In an application in the Middle East, the operating company wanted to improve understanding of fluid saturationsin a high-porosity carbonate reservoir where variability in Archie n and m components increased uncertainty in conventional log interpretation. The measurements also were ambiguous because of the mud and filtrate salinity.

The carbonate textural information provided by the scanner provided accurate nm determination without relying on assumptions or sending samples to the laboratory. Having these accurate values helped in calculating saturation values from resistivity. The operator discovered a large volume of residual hydrocarbon in the formation.

Another operator in the Orinoco heavy oil belt in Venezuela realized an additional 150 ft (46 m) of pay using the scanner. The production potential of the laminated reservoir could not be determined accurately with conventional logs because thinly bedded sand and shale layers decreased resistivity measurements and masked pay zones. The result was a pessimistic interpretation of the hydrocarbon volume.

The scanner provided important information about the reservoir quality of the lower interval, revealing movable oil over a 150-ft section. Sidewall samples confirmed the measurements.

On a project in Canada’s oil sands, an operator had to wait several months for core analysis because the reservoir had varying water salinity and thus resistivity. The core results indicated that estimates of resistivity in the uncored sections were inaccurate.

With water-filled porosity calculated from the dispersion measurements, the weight percent of the bitumen could be determined accurately without the need for core analysis, saving considerable time and money.

With access to these types of measurements, operators can stop making assumptions about the fluid in their wells.

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