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. In rare instances, karstification (or evaporite solution/collapse) may create fractured reservoirs

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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

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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 different lithologies can result in abrupt changes in fracture and joint spacing across bedding planes (Hodgson, 1961).

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Schematic diagram showing 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

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Most faults almost bedding parallel

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Associated fractures dip in opposite direction and are mostly calcite cemented

Local fault macroporosity where irregular,

but mostly virtually closed/cemented

Well developed slickensides with reverse (thrust) movement most commonly indicated, locally with oblique-slip

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Fault partly open and partly filled with sheared country rock

Fault part cemented by calcite

Dip Slip

Well developed slickensides with reverse

(thrust) movement most commonly indicated, locally with oblique-slip

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Oblique slip

Intensely fractured fine grained limestones and marls. Fracture frequency increases towards fault in competent layers

fracture frequency increases towards fault in competent layers

Fracture model

Fault related fracture. Repeated phases of tensional opening and cementation, possibly related to pulses in related fault movement

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

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