fractured reservoir basics
Naturally fractured reservoirs contain secondary or induced porosity in addition to their original primary porosity. Induced porosity is formed by tension or shear stresses causing fractures in a competent or brittle formation. Fracture porosity is usually very small. Values between 0.0001 and 0.001 of rock volume are typical (0.01% to 0.1%) Fracture-related porosity, such as solution porosity in granite or carbonate reservoirs, may attain much larger values, but the porosity in the actual fracture is still very small.
There are, of course, exceptions to all rules of thumb. In rare cases, such as the cooling of intrusives or surface lava flows, in which natural fracture porosity may exceed 10%. When buried and later filled with hydrocarbons, they form very interesting reservoirs.
Fracture analysis literature in the 1970’s suggested that fractures might contribute as much as a few to several percent porosity. More modern work using fracture aperture calculated from resistivity micro-scanner logs indicates much lower numbers. To appreciate this, consider fractures with 1 millimeter aperture spaced 1 meter apart. This gives a porosity of 0.001 fractional (0.1%). This is a very large open fracture. Most are only microns in width, so even 10 fractures of 10 microns each only give 0.0001 fractional porosity (0.01%).
The term “secondary porosity” also includes rock-volume shrinkage due to dolomitization, porosity increase due to solution or recrystalization, and other geological processes. “Secondary porosity” should not be confused with “fracture porosity”. Porosity formed in this way can be determined from modern log suites without difficulty, except for porosity formed by fractures, which is too small to detect with conventional logs.
Fracture porosity is found accurately only by processing the formation micro-scanner curves for fracture aperture and fracture frequency (fracture intensity). All other methods, including the well known “dual-porosity” model, are extremely inaccurate. These models either over-estimate fracture porosity by several orders of magnitude, or cannot be applied because the log data does not fit the model. All published models are described in this Handbook and the student or practitioner can decide whether or not to use them.
The effect of fracture porosity on reservoir performance, however, is very large due to its enormous contribution to permeability. As a result, naturally fractured reservoirs behave differently than un-fractured reservoirs with similar porosity, due to the relative high flow capacity of the secondary porosity system. This provides high initial production rates, which can lead to extremely optimistic production forecasts and sometimes, economic failures when the small reservoir volume is not properly taken into account.
Reservoir simulation software that accounts for the fracture system is often termed a “dual porosity” model. While this is strictly true, it would be better to think of them as “dual permeability” models, since the fracture permeability fed by the matrix or reservoir permeability is far more important than the relative storage capacity of the fractures and matrix porosity. A reservoir with only fracture porosity is quickly depleted; a decent reservoir in the matrix rock feeding into fractures will last much longer.
In order to understand the behavior of naturally fractured reservoirs, estimates must be made of hydrocarbons-in-place within both the primary (matrix rock) and secondary (fracture-only) porosity systems. To do this, we must first be able to detect the existence of fractures. Therefore, this chapter covers fracture detection from the usually available conventional logs, as well as the method used to partition porosity into primary and fracture components. The effect of this partitioning on the Archie water saturation equation is also described. Modern methods for quantifying fracture porosity directly from micro-scanner logs are also discussed.
Fractures are caused by stress in the formation, which in turn usually derives from tectonic forces such as folds and faults. These are termed natural fractures, as opposed to induced fractures. Induced fractures are created by drilling stress or by purposely fracturing a reservoir by hydraulic pressure from surface equipment. Both kinds of fractures are economically important. Induced fractures may connect the wellbore to natural fractures that would otherwise not contribute to flow capacity.
Natural fractures are more common in carbonate rocks than in sandstones. Some of the best fractured reservoirs are in granite - often referred to as unconventional reservoirs. Fractures occur in preferential directions, determined by the direction of regional stress. This is usually parallel to the direction of nearby faults or folds, but in the case of overthrust faults, they may be perpendicular to the fault or there may be two orthogonal directions. Induced fractures usually have a preferential direction, often perpendicular to the natural fractures. A schematic diagram of these relationships is shown above, bottom right.
A fracture is often a high permeability path in a low permeability rock, or it may be filled with a cementing material, such as calcite, leaving the fracture with no permeability. Thus it is important to distinguish between open and healed fractures. The total volume of fractures is often small compared to the total pore volume of the reservoir.
Most natural fractures are more or less vertical. Horizontal fracture may exist for a short distance, propped open by bridging of the irregular surfaces. Most horizontal fractures, however, are sealed by overburden pressure. Both horizontal and semi-vertical fractures can be detected by various logging tools.
The vertical extent of fractures is often controlled by thin layers of plastic material, such as shale beds or laminations, or by weak layers of rock, such as stylolites in carbonate sequences. The thickness of these beds may be too small to be seen on logs, so fractures may seem to start and stop for no apparent reason.
To be an aid in production, fractures must be connected to a reasonable hydrocarbon bearing reservoir with sufficient volume to warrant exploitation. If there is no reservoir volume, a lot of fractures won’t help much unless there is sufficient fracture related solution porosity to hold an economic reserve. This can be determined by normal log analysis techniques. In reasonable non-fractured reservoirs, it is usually possible to estimate permeability, and hence productivity, but this is not always possible in fractured reservoirs. Although both the presence of fractures and the presence of a reservoir can be determined from logs, a production test will be needed to determine whether economic production is possible. The test must be analyzed carefully to avoid over optimistic predictions based on the flush production rates associated with the fracture system. Local correlations between fracture intensity observed on logs and production rate are also used to predict well quality.
Sometimes the primary reservoir and the fracture system may be so poorly connected that they are saturated with different fluids. Production from fractures full of hydrocarbons in a water bearing formation may initially be very good but very short lived. A more desirable scenario is a primary reservoir with appreciable hydrocarbon saturation and a fracture system that is full of water close to the borehole, showing invasion and hence good permeability, but full of hydrocarbon in the uninvaded formation.
Usung Logs to Locate Fractures
Of course, it would be preferable to run the right logs in the first place. These would include the resistivity or acoustic image log and the dipole shera sonic log. A preview of these modern logs is given below, with more detail in Section 3. Case histories aree in Section 4.
With some skill and daring, the image logs can be interpreted for open, healed, and induced fractures, and the stress regime for each can be worked out seoarately.
The newest dipole shear sonic log is also an azimuthal tool with dipole sources set at 90 degrees to each other. The example below shows the shear images for the X and Y directions. This log can be run in open or cased hole.
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