1. Researchers have classified fractured carbonate reservoirs into four types based on their intergranular porosity, permeability, and role of fractures in providing storage and fluid flow pathways. 2. Type 1 reservoirs have little natural porosity or permeability and rely entirely on fractures for storage and flow. Type 2 have some natural porosity and permeability enhanced by fractures. Type 3 have moderate natural porosity but rely on fractures for flow. Type 4 have good natural porosity and permeability but are still enhanced by fractures. 3. The intensity of fracturing depends on factors like bed thickness, lithology, and structural deformation, with thinner and more brittle beds tending to be more fractured. Fractures can be open

1. 1
CLASSIFICATION OF FRACTURED CARBONATE RESERVOIRS
Some researchers classified the fractured carbonate reservoirs as one of four types (Hubert
and Willis (1955) and MacNaughton and Garb (1975); modified by Nelson, 1985; Allen and Sun,
2003, 2004). Their argument based on intergranular porosity and permeability and the role of
fractures which has play role in providing space and fluid flow. Depending of rock type, local
tectonic regime and thickness of sediment the fracture pattern can be change.
Fractured oil reservoirs type 1 have little intergranular porosity and permeability. The pore
spaces are water wet. The fractures provide the storage capacity and all of the fluid-flow
pathways for oil. Average intergranular porosities is less than 5% and average permeability
is less than1 mD. If there are no fractures, this type of reservoirs would not be
commercial producers.
Type 2 fractured carbonate oil reservoirs have macro porous. This type of fracture has
low to moderate intergranular porosity, and low permeability. The intergranular pore spaces
in fracture provide the storage capacity of the reservoirs. Accordingly the fractures provide the
fluid-flow pathways for the oil movement. In these reservoirs, intergranular porosities can be
more than 10-15% and average permeability more than 10 mD. Without fractures, most
Type 2 reservoirs would be incapable of producing at commercial flow rates.
Fracture oil reservoirs Type 3 are microporous and have moderate to high matrix
porosity, low intergranular porosity, and low permeability. The matrix pore spaces provide
the storage capacity of the reservoirs and the fractures provide the fluid-flow pathways for the oil
movement. Without fractures, most type 3 reservoirs would be incapable of producing at
commercial flow rates.
Type 4 fractured carbonate oil reservoirs have at least moderate intergranular porosity
and ‘good’ permeability. The pore spaces provide storage capacity and fluid-flow pathways.
Such fractures enhance bulk permeability and increase reservoir heterogeneity. Reservoir
heterogeneity is controlled by 3 factors: 1.Reservoir architecture, 2.Fracture distribution, and
3. Diagenetic overprint. Reservoir architecture is primarily controlled by depositional facies
patterns and early diagenetic overprint, including early post-depositional cementation and
dolomitization. Fracture distribution differs from one tectonic regime to the next (e.g.,
extensional, compressional, wrench, and vertical tectonic fracturing). Later diagenetic overprint
can include alteration and karstification during uplift, or leaching and cementation during burial.
Karstification is generally accompanied by tectonic fracturing, which it may predate or postdate.

2. 2
In rare instances, karstification (or evaporite solution/collapse) may create fractured reservoirs
without the aid of tectonic . Without fractures, type 4 reservoirs would still be commercially
productive.
The given values are approximate and assume a pure lithology. Some rocks like argillaceous or
limestones will have much higher matrix porosity, but this porosity is not effective. Often
researches or geologist use term “matrix” porosity, which they are clearly referring to
intergranular porosity. The term intergranular porosity refers to pore spaces between
grains generally larger than 0.031 mm (Leighton and Pentdexter, 1962). If the pore spaces
are interconnected (i.e., good permeability) to allow fluid flow, this is termed effective porosity.
If the rock contains variable grain sizes, the term matrix refers to the smaller individual particles
by filling the interstices between the larger grains (Krynine, 1948; Leighton and Pentdexter,
1962). The matrix may be porous (i.e., shale) but lack of permeability means that fluid cannot
flow from one pore space to another. It is possible for a rock to have hydrocarbons in the
intergranular pore spaces and water in the matrix pore spaces.
The intensity of fracturing within a reservoir is dependent upon three variables: (A) bed
thickness, (B) lithology (which controls ductility), and (C) structural deformation. Fracture
density is greater in thin beds than in thick ones (Horn, 1990) and greater in brittle
lithologies than in ductile ones (Garfield et al., 1992) . To make it more complicated, ductility
can change with temperature and pressure (Handin et al., 1963). Thus, a thin-bedded
dolomite will display a greater fracture density than a thick-bedded limestone. Fractures may be
open or filled with diagenetic cement.
Open fractures are most common in tectonically deformed reservoirs that have not been
subjected to karstification or burial diagenesis (Longman, 1985). When weathering and
karstification follow tectonic fracturing, dissolution along fractures creates solution-enlarged
conduits. Such conduits enhance reservoir properties. If the dissolved carbonate re precipitates
as cement, it can destroy much of the fracture network (Lomando et al., 1993). Subsequent
diagenetic alteration can create leached, vuggy, porosity and collapse breccias, which have
excellent reservoir quality (Hurley and Budros, 1990). Particularly if this alteration is associated
with cross-formational flow of formation water along fault zones.
Four tectonic processes control the areal distribution of fractures in most reservoirs: (A)
extensional faulting and folding; (B) compressional faulting and folding; (C) wrench
faulting and folding; and (D) regional fracturing and jointing. In some of these settings,
fracture density is controlled by the faults; in others it is controlled by the location on structure.
In extensional settings, faults provide the primary control on fracture density and distribution.
Fractures are generally parallel the strike of major fault systems. Fracture density tends to
increase toward the boundary faults to horsts, grabens, and tilted basement blocks. When
fracture dips are immediately adjacent to the bounding faults, the fracture dips reflect those of
the fault planes. Farther away from the faults, azimuths are similar, but dips may differ
significantly. Long episodes of uplift and weathering are common. They often result in deeply
penetrating alteration zones, which enhance reservoir properties (Tong and Huang, 1991; El
Wazeer et al., 1990).
Wrench settings are similar to extensional settings in that fracture density also increases toward
faults. Fractures form from stress caused by tectonic forces, such as compression, may result in
a fracture pattern unrelated to the shape of the geologic feature or structure

3. 3
Type 1 fractures extend deeper and thus have better chance of allowing hydrocarbon
migration from a deeply buried source rock. Type 2 fractures tend to provide more
storage capacity.
In compressional settings, fracture distribution and density are more likely to be
controlled by structural position on folds than by proximity to faults. Fracture density is
greatest in areas of maximum flexure, such as fold crests (Dunnington, 1958), axial planes,
and structural noses. Fracture azimuths generally parallel the trends of fold axes and in some
cases may connect thousands of feet of reservoir section into a single pool that is in hydraulic
and pressure communication. In regional settings, where fracturing is caused by large-scale
tectonic processes, such as epirogenic uplift or deep movement of crustal blocks,
fractures at the reservoir scale often parallel regional lineaments and can be traced for
hundreds of miles (Greer and Ellis, 1991).
Interbedding of differentlithologiescan resultin abrupt changes in fractureand joint spacing across bedding planes
(Hodgson, 1961).

4. 4
Schematic diagramshowing relationship between maximum (σ1), intermediate (σ2), and minimum (σ3) principal
stresses and shear and extensional fracture planes when all three principal stresses are compressional (Nelson,
1985).
The two most common fracture types encountered in nature. (A) Type 1 fracturing creates shortening in the dip
direction and generates extension fractures perpendicular to the fold axis. (B) Type 2 fracturing results in
shortening in the strike direction and creates extension fractures parallel to the fold axis. S = shear fractures, E =
extension fractures (Stearns and Friedman, 1972; Garrett and Snyder, 1985). Stearns’ (1967; 1968) genetic
classification identifies five fracture patterns associated with folds produced predominantly by compressive
stress. Only two of these are common in nature

5. 5
Most faults almostbedding parallel

6. 6
Associated fracturesdip in opposite direction and are mostly calcite
cemented
Local fault macroporosity where irregular,
but mostly virtually closed/cemented
Well developed slickensides with reverse (thrust) movementmostcommonly indicated,locally with oblique -slip
Fault partly open
and partly filled with
sheared country rock
Fault part
cemented by
calcite
Dip Slip

7. 7
Well developed slickensides with reverse
(thrust) movement mostcommonly
indicated,locally with oblique-slip
Oblique slip
Intensely fractured fine grained limestones and marls.
Fracture frequency increasestowardsfault in competent
layers
fracture frequency increases
towards fault in competent layers

8. 8
Fracture model
Fault related fracture.Repeated phasesof tensional opening and
cementation,possibly related to pulses in related fault movement
Main direction of thrusting

9. 9
Well bedded, fractured, Kometan Formation limestones, Kurdistan, Iraq