fractured reservoir basics
Natural fractures in reservoir rocks contribute significantly to productivity. Therefore, it is important to glean every scrap of information from open hole logs to locate the presence and intensity of fracturing. Even though some modern logs, such as the formation micro-scanner and televiewer, are the tools of choice for fracture indicators, many wells lack this data. Thus all known fracture location techniques are described.

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.

Definition of Fractures
A fracture is a surface along which a loss of cohesion in the rock texture has taken place. A fracture is sometimes called a joint and, at the surface, are expressed as cracks or fissures in the rocks. The orientation of the fracture can be anywhere from horizontal to vertical. The rough surface separates the two faces, giving rise to fracture porosity. The surfaces touch at points called asperities. Altered rock surrounds each surface and infilling minerals may cover part or all of each surface. Minerals may fill the entire fracture, converting an open fracture to a healed or sealed fracture.

Fracture Porosity Definitions

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
Fracture location from well logs can be divided into two categories, namely wells with image logs and wells without image logs. Using conventional open hole logs is mandatory in older wells before the era of image logs, and still widely needed today because image logs are not always run where they are need. As a result we are forced to ise what we have. Using conventional logs is covered in the next Section.

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.

Acoustic Image log with travel time (detailed borehole radius) at left and amplitude (acoustic impedance) on the right. Fractures show up as black sinusoid shapes on both images. The strike direction (azimuth) of the fracture can be picked at the trough on the sinusoid and converted to a compass orientation using the scale at the top of the log. Dip angle of the fracture can be found by comparing the peak to peak amplitude of the sine wave (in borehole depth units) to the borehole diameter (measued in the same units).
DIP = arctan (Y/D) where Y = peak to peak distance and D = borehole diameter.

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.

Resistivity image log in fractured reservoir: gamma ray (left track, shaded red), image track (middle) with open fractures (red sine waves and healed fractures (yellow sine waves), dip track (right) shows red amd yellow dip angle and azimuth. There are no induced fractures in this short interval. Bedding planes are near horizontal. Imagine trying to locate these steep dips without the aid of a computer.


Induced fractures (top left) show current stress direction. Open fractures (top right) show stress direction when fractures were created, healed fractures (lower left) show different direction at an earlier phase in geological time, and micro faults (lower right) shows another stress regime was present when the faults occurred.

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.

Dipole shear image log shows directional stress - the Fast Direction is centered on
90 degrees (east - west) which is also the maximum stress direction.


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