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Layer thickness evaluation
By convention, reservoir (layer) thickness is expressed in feet and is rounded to the nearest foot, even though most modern wireline logs are recorded digitally every 6 in. Many of the world’s reservoirs are logged in metric units, and thickness is expressed in meters. In this regime, thickness is rounded to the nearest 0.1 m.
Bed boundaries are usually the easiest of all reservoir properties to measure; however, there are some fatal traps that await the unwary. The geologist’s knowledge of the rock types in the play, in general (and in the well of interest, in particular) can be used.
Sands and shales
The term sand is used generically and can also refer to sandstone or other siliciclastic formations. The term shale is used generically and can also refer to mudrock or claystone. When the reservoir beds are mostly sand [typically low gamma ray (GR)] and shale (typically high GR), then the GR log can usually be used to select bed boundaries. The inflection point of the GR count rate expressed in American Petroleum Institute (API) units is selected as the bed boundary. (See examples in the article on nuclear logging) The choice of which bed thickness is to be determined is usually made by the geologist largely on the basis of pattern recognition skills developed during the play definition. Not all sand beds have low GR levels. If the sand bed contains sizable amounts of potassium feldspar, mica, or volcanic debris, the sands may be as radioactive as the shales and difficult to tell apart. In this case, the spontaneous potentials (SP) log is often used if the well is drilled in water-based mud. Again, the inflection point of the log is used to denote the bed boundary. (See examples in resistivity and SP logging) However, in low-porosity and high-resistivity environments, the SP is suppressed and cannot be relied on as a bed boundary indicator.
Another tool that can be used to mark bed boundaries is the electric (resistivity or conductivity) log. This log is most useful when the shales are water-bearing and the sands are shale-free and hydrocarbon bearing. However, the bed boundary is no longer at the inflection point on the log, but is offset by one-half of the electrode spacing of the tool used to measure resistivity. Each service company has charts to aid the petrophysicist in determining the correct offset, while many wellsite computer products take this offset into account automatically. The finest resolution of all is afforded by electric or acoustic borehole image logs, but these logs are not routinely run because of their expensive acquisition and processing costs. The pages on specialized well-logging topics shows examples of borehole image logs. If the well is drilled in oil-based mud, then the SP log is not available and the density/neutron log can be used to define sand from shale. If the density/neutron log is a modern digitally sampled tool, then the inflection point can be used as the bed boundary. If, however, the density/neutron log is an older analog tool, the bed boundary can be offset because of drag settings. Vendor publications are available to aid the user in determining the offset. Acoustic borehole image logs are an option in small boreholes and lightweight oil-based muds. Nuclear magnetic resonance (NMR) logs are also useful in distinguishing zones that have movable fluids from those containing bound fluids (see nuclear magnetic resonance (NMR) logging for examples).
When the reservoir beds are generally composed of carbonates (i.e., limestones and/or dolomites), bed definition becomes more complex. In this case, the presence and absence of porosity defines the reservoir from the seal; thus, the GR log may not be useful in demarking bed boundaries. Likewise, carbonates are generally in a higher resistivity regime, and the SP log is of little use. Thus, in this environment, one relies on a tool sensitive to porosity to delineate the bed boundaries, such as the density, neutron, or acoustic log. Borehole image logs are also useful when the borehole is relatively smooth. Large vugs and washouts invalidate readings from these tools. (The page on specialized logging topics includes an example of a borehole image log in a carbonate formation.)
What to count
Determining gross bed thickness is straightforward; however, determining what part of a given bed contains producible hydrocarbons is tricky. At present, there is no single standard sanctioned by SPE or API as to the definition of, or the method for determining, net pay. One of the more common complications is a result of the small thickness of layers containing hydrocarbons. Some common depositional environments can result in sands and shales being laid down into zones thinner than the resolving power of almost all wireline logs. One cannot count directly what one cannot see. In this case, we settle for thicker averages that mathematically equate to correct fluid volumes (i.e., calculate that from depth X to depth X+30 ft, the ratio of sand to shale is 0.5; thus, it contains 15 ft of reservoir-quality rock in layers too thin to individually resolve). Finally, one can cut a continuous core from the top through the bottom of the reservoir in question and, given the good fortune to recover 100% of the core at the surface, one can use sophisticated core-analysis techniques to determine the thickness of the layers with a precision and accuracy better than any other part of the reservoir remaining in the Earth. Because of the high cost of cutting and analyzing whole core, this method is seldom used, unless no other method can be proven to work.
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