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Pink Granite

Sample description: Hard, medium to high density rock of interlocking coarse crystalline minerals, predominantly light pink and translucent grey coarse 4-6mm size maximum grain size of 9mm, minor white, brown and black mineral species.

a) Average grain size 6mm;

b) Composition of minerals:

• 1:Pink, Well formed euhedral, reflective vitreous, hard crystals to 9mm– Orthoclase – 50-55% of the sample.

• 2:Grey, translucent,well formed euhedral,late interlocking interstitial crystals to 6mm,  irregular, conchoidal fracture – Quartz – 30-35% of the rock.

• 3: Well formed, white 2:1 elongate oblong, 90˚ intersection to 3mm slightly embayed (early formed),vitreous lustre – Plagioclase – 10% of the rock

• 4:Irregular, black, low to medium strength,variable dull to vitreous lustre, irregular shapes to 3mm,associated with deep black  <1mm grains – Biotite – less than 5% of the rock.

• 5: Well formed, black rare,less than 1mm in size, evidence of cleavage – hornblende – less than 1% (minor)

• 6: Small glints of highly reflective vitreous or metallic lustre – Muscovite – minor occurrence.

c) Formation;

• This is a plutonic rock. It was crystallized by slow cooling in an underground magma chamber, allowing the growth of the coarse, well defined crystals which characterize this rock.
• The source of the magma is partially melted or re-melted continental crust.
• Its mineral assemblage is dominant in elements such as potassium and silica which, through partitioning, are preferentially concentrated within continental crust.
• It is formed in large, often laterally extensive bodies known as plutons, and can measure hundreds or even thousands of meters in vertical thickness as a consequence of convergent subduction zone - plate boundary volcanism.

• Country rocks into which a granite has intruded show heat and stress related deformation.
• Granites, when extremely weathered, are a potential source of clay minerals, chlorites, trace metals as well as quartz. It also contains fluid mobile elements such as Phosphorus in the mineral Apatite.  Lead (P_b )_, Thorium (T_h) and Uranium (U) elements also occur in trace amounts and these are generally associated with the mineral Zircon. These are also fluid mobile and through weathering by water will leach out into the surrounding formation.

R2: BASALT; Dense, hard, black, aphanitic groundmass with fine white crystals forming a porphyritic texture, as in figure 2.

Figure 2: Sample R2 – basalt with a porphyritic texture

 Description;  Elongate, euhedral white phenocrysts to less than 1mm occur throughout and are consistent with early formed plagioclase.

Very small,  white crystals which are visible might be formed from a late release of volatile fluids.

a) Grain size:

• Basalt is formed from the rapid cooling of magma either erupted at the surface (submarine or terrestrial) or within dykes amongst country rock. The cooling is so rapid that most of the minerals do not have time to nucleate into crystals, and so set as a groundmass of volcanic glass.
• Those early formed minerals which have nucleated exist as very small, rapidly cooled crystals. Granite, which has large grains, is the product of very slow cooling of magma.

b) Dark colour

• The dark colour of basalt is due to its higher content of darker(mafic) minerals containing iron and magnesium.

      c) Other Minerals

• Small white crystals to 1/5mm but mostly 1/20mm may be early formed plagioclase phenocrysts which existed in the magma as early crystallizing components.
• Basalt is known to consist principally of pyroxene, and plagioclase with subordinate quantities (up to 10%) of magnetite and possibly olivine, however they are visible only in thin section with a microscope.

d) Formation;

Basalt is an igneous, plutonic intrusive flow into country rock and forms as a dyke or a laterally extensive sill. The magma source generally has a mantle component and has a higher temperature, and is less silicic that granite.

It also forms from surface eruptions of lava as a volcanic flow if terrestrial, or a pillow basalt if flowing into a sub-marine setting.

Sample R3: Pumice.

 Description: Earthy grey - brown, dull, crypto-crystalline, hard, very low density rounded, igneous rock with a highly vesicular texture as seen in figure 3.

a) Low density:

• The vesicles increase the porosity of the rock, resulting in its low density and “froth like” appearance.

b)Porosity and d) Formation:

•  This rock, likely in an explosive manner, formed at the moment that a siliceous, highly viscous magma erupted. This caused a rapid depressurization resulting in the instantaneous degassing of volatiles. The loss of the volatiles resulted in a sudden increase in viscosity, which instantly solidified the pumice, trapping the large number of gas bubbles within it.
• Thus, while porous, pumice is impermeable due to the unconnected nature of its pores.

Figure 3 – Pumice – vesicular porosity is visible, as are minor mineral grains.

c) Mineral recognition:

• The light colour of the crypto-crystalline groundmass suggests that it is of a highly siliceous composition, however no minerals are observed in this groundmass.
• Small, randomly distributed white and dark vitreous crystals suggest that some crystallizing minerals existed in the siliceous magma/lava prior to eruption, and that these became entrained within the pumice. These accessory minerals have the appearance of quartz and mica.

d) Formation; (see also answer to b) – above)

Igneous rock formed from highly silicic lavas erupting explosively in volcanic arcs adjacent to tectonic plate boundaries.

Samples R4: Sandstone.

Description; Clastic yellowish, medium density, angular to sub-angular grains.

The size fraction as shown in figure 4 is  grains in the 1/4mm to 1/2mm size.

This is a medium sandstone.

b) Framework particles:

• The angularity of the grains suggests that deposition of the original sediment was close to the source of the grains.
• The uniform colour suggests that the grains are all from the same source, and are likely composed of quartz grains.
• It can thus be described as a moderately to well sorted, sub-angular, medium quartz sandstone, or arenite.
• The rock structure is dominantly clast supported, although weak, yellowed cement occurs as a coating between grains, suggesting an autogenic chemical process and the presence of a mild oxide coating.

c) Porosity and Permeability

• The sandstone was tested for calcium content by adding droplets of vinegar. This produced no reaction, suggesting an absence of carbonates.

• To test for effective porosity, that is permeability and porosity, water when added to a dry surface, soaked into the rock. This suggests that the rock has a permeable porosity and is therefore a potential reservoir rock.

• Hand lens observation reveals that the rock has a high number of inter - granular pores spaces. Grain contacts show little deformation, and the grain orientation is random. As such the preserved porosity is likely of the primary type.

Figure 4: Medium Sandstone. Grain size, colour and packing arrangement are evident in photo.

R5 Lithic Sandstone:

Description; Hard, medium density, fine sand grained brown groundmass of grains, each of which appears to itself be composed of diverse minerals making it a polymitic sandstone.

Grain size: 

• This is a fine sandstone with a grain size of 1/10mm to 1/4mm( see scale figure 5)

Framework particles; 

• Silicic brown, yellow and black lithic and mineral grains. Evidence of oxide minerals and clay cement. Possible volcanic origin.

Porosity and permeability

Water drop testing is inconclusive as there is minimal absorption. In contrast to sample R4 sandstone, above, it is not easy to dislodge individual grains when abraded. This suggests a well cemented structure.

Photos shows the sample against a 10mm scale, on 1mm grid paper for scale.

Figure 5 – Lithic Sandstone – fine textured assortment of grains.

R6 – Conglomerate;

a) Size and sorting:

• Well rounded, randomly orientated silicic pebbles to 40mm supported within a  blackish clay matrix with abundant poorly sorted fine  1/10mm to 1/5mm angular grains.

Framework particles

• Angular micaceous as well as lithic fragments, including quartz and felsic minerals which are of a volcanic origin.

c) Matrix material and porosity.

• Matrix formed of clay cement. The difference between the matrix materials and the large pebbles strongly infer mixing of different depositional conditions as the cement is of a different source to the pebbles. A possible explanation is that this may be as a result of an abrupt event such as a mass movement.
• The surface of the cement is very hard, does not absorb water, and is inert against acetic acid (vinegar).
• As shown in figure 6, the clay cement is closely moulded to the larger pebbles, suggesting that the matrix has no natural fluid pathways, and water testing shows nil permeability. Porosity is inferred to be absent, or if present, exists as isolated pores.

Figure 6: Pebble Conglomerate – note moulding of matrix to pebble surfaces

R7 – Shale;

 Very fine grained medium to dark-grey banded clastic rock, with sub millimetre scale to sub centimetre scale laminar texture. Hard, sandy textured surface, although individual grains cannot be visually distinguished. Of medium density.

Grain size and formation:

Grain size is very fine, and individual grains cannot be discerned without magnification, which means that it is a siltstone with possible finer clay particles.

The depositional environment for this sedimentary rock is low energy shallow marine or lacustrine environment with a suggestion of ripple bedding.

The dark laminar bands have a brown streak and this is indicative of carbonaceous sediments.

The alternating dark – light bands represent episodic changes in depositional energy, the coarser light grey zones appearing to be composed of transported silt sized felsic and quartz grains.

This indicates that while low energy, there was still some flow transport of grains occurring, and the water energy was not completely still. 

Figure 7: Shale or siltstone – note the fine scale of bedding and grain texture.

Geotechnical Note:

• The rock shows no parting planes and is very competent. It is not of the fissile type of shale that commonly occurs.
• Bedding shows sub millimetre wavy bedding, to sub-centimetre carbonaceous banding.
• This rock can also be categorized as a siltstone.

Porosity and permeability

When tested with water the sample displayed nil permeability, but it may have a porous micro-texture. The close packing of fine grains reduces permeability. The fine texture may mean that clay minerals are present, and these will reduce the pore volume and inhibit permeability.

R8 – Claystone;

 Grain size

Aphanitic (very fine grained) dark red brown, medium density rock, of medium strength, exhibiting conchoidal fracture surfaces. Surface is smooth, and without the coarseness of shale and therefore has a finer texture.

  Red Brown mineral?

The rock colour suggests a clay mineral composition which contains an iron oxide.

Small white grains are attached to the rock and may be re-crystallised carbonates or salt.

• Distinctive clay formations are useful marker beds for exploration of outcrops and exploration boreholes because they are commonly the result of regional events (example; dust storms, distal flood deposits and volcanic outfall deposits and so on) and hence are in many cases known to be laterally extensive. This will allow a correlation with the known stratigraphy of the area to be made at different locations.
• In borehole exploration the change in colour of the drilling mud as well as the drill cuttings would alert the operators that this rock had been intersected during drilling.
• The primary condition for a useful stratigraphical marker bed is that is possesses sufficient lateral continuity to cover the geological domain being investigated.
• A further condition is that it has a stratigraphical relevance to the depositional sequence of the area. That is, it must be formed of a depositional process that occupies a specific place in the historical depositional record. This precludes for example, late intrusive rocks which cut across the geological record.
• If this claystone meets these conditions, then it would be a useful marker bed.

Figure 8 – Claystone – small white minerals indicate depositional conditions.

R9 – Limestone;

Description:

 White, medium strength rock showing evidence of crystallized fusing of grains. It has a coarse surface, and irregular fracture. It is of medium density.

Texture and Grain:

• Limestone has a coarse crystalline texture even though it is formed from sedimentary processes. Being all white is an indication that it is mono-minerallic and in this case of the mineral Calcium Carbonate.

Porosity and permeability:

• The water test has produced nil permeability and no evidence of any porosity. This is consistent with its re-crystallized texture.

Acid reactivity:

• Testing with vinegar produced a positive result. An observed reaction with vinegar by the bubbles that appear is evidence a Calcium Carbonate composition (CaCo₃).

R10 Coal:

Description:

 Black, low density, low strength brittle rock with alternating dull and vitreous bands, and a blocky fracture.

Density

Coal is of a much lower density than most rock types other than pumice,

This is due partly to its very high porosity and the absence of heavy elements.

Figure 10 – Coal, showing bright and dull bands, and blocky fracture

Bright and dull bands:

The bright and dull bands in the coal represent different types of Macerals. Macerals are the coal equivalent of petro-facies and is term that describes the original vegetation that was deposited, and then diagenetically turned into coal.

Coal with a high reflectance, that is, bright, vitreous bands is formed from woody plant remains, such as branches, leaves and tree trunks. Its very high micro-porosity means that is has a low density, it is also low in impurities, (described as ash content).

The dull coal is derived of other types of macerals, such as algal spores, and if of a higher density will also contain a higher amount of non- combustible, mineral impurities.

Fracture network;

• The blocky fractures are called cleat, and this is a type of jointing unique to coal.
• Bright, vitreous coal has a higher frequency of cleat joints, up to one every millimetre.
• Cleats represents the macro-permeability, where Darcy fluids flows can occur but it is the network of micro-pores in coal which represent the significant fraction of the pore volume.
• The permeable character of a coal seam is therefore not measured by the connectivity of its pores, but is determined by its cleat spacing and aperture.

2.1. What is good porosity? 

Porosity is the volume of a liquid that can be held by a rock, or a sediment and is expressed mathematically as the fraction of the total rock volume (Felix and Munoz 2005),(UNSW – SPE course notes 2012)

Good porosity is that which is useful for the storage and extraction of hydrocarbons from a reservoir. Effective porosity is a separate but related term that combines the properties of porosity and permeability.

Characteristics of good porosity are;

• Sufficient volume fraction of net pore volume, typically 15% of the total formation.
• Low amount of fine particles which can fill up pores, or prevent fluid flow at pore throats thereby also limiting permeability.
• Pore geometry

Porosity is expressed as the fraction of the net available pore space to the total volume of the rock. As such porosity in terms of petroleum reservoir capacity is the net volume fraction of hydrocarbons that can be stored within the formation.

Net Porosity = Gross pore volume – pore volume occupied by bound water / reservoir volume

Good porosity implies that not only is there a significant volume of pore space in a rock, but that this space does not include the volume which is already occupied by bound water or fine particles.

Bound water is water that is chemically bound to the inner pore surfaces, and cannot be displaced by migrating hydrocarbons. Thus the amount pore volume occupied by bound water cannot be considered “available” pore volume, and must be subtracted from the total pore volume.

2.1 What characteristics of a sandstone reservoir would you look to find a good reservoir rock? 

Physical attributes:

 A reservoir sandstone must have porosity and permeability properties. Characteristics which are favourable for the development of these properties are;

Good grain size sorting: Sandstone is preferentially selected as a reservoir rock because it is the coarsest textured category of sedimentary rock that is composed of grains of similar size. This condition is important for the formation of good primary porosity as it means that there are no finer particles present which can infill framework void spaces during its initial deposition.

Grain shape: High grain sphericity allows a higher volume of primary pore spaces, and it also helps to preserve more of the primary pore volume under pressure .

High pore volumes are also possible in the case of an irregular assortment of grain shapes, however in this case porosity will be less resistant to compaction.

Bedding type and depositional environment; Bedding planes will indicate the depositional environment, and may give clues about the permeability of  strata occurring within the formation. Also the bedding plane contact faces tend to be zones of contrasting grain packing which will result in variability of porosity and permeability.

Examples; Cross bedding indicates swash zone beach or delta-front deposition of well sorted grains, and continuity of the sandstone.  In contrast, lenticular or flaser bedding will indicates ripple currents, and the high probability of silts and clay horizons within the formation interrupting reservoir continuity.

Random grain orientation allows a higher primary pore volume. In the case of discoid , tabular or elongate grains, these develop a preferential alignment through imbrication and will tend to develop narrow pores. This framework of preferentially aligned grains will inhibit fluid flows perpendicular to the direction of imbrication.

Sandstone that is composed of an inert mineral such as quartz is favourable. Quartz grains are capable of forming a strong clast supported structure, while resisting chemical breakdown which can then precipitate into pore spaces.

In some cases, sandstones that contain carbonate grains (ie sand sized sea shell fragments) can actually develop secondary porosity through leaching processes caused by low pH, meteoric water.

Low clay content. Clay minerals and other chemical precipitates will reduce net porosity and reduce permeability at pore throats.

 Low rate of deformation. Deformation will narrow pores,. Another effect of high pressure is that pressure solution at grain to grain contact boundaries can occur. This results in the formation of quartz cement in pore spaces, although it will create strong grain to grain sutures. Very high pressures can results in the partial re-crystallization of grains, resulting in a closure of pores, for example – quartzite, dolomite.

The absence of intra-formational clay bedding. Clay is a source of pore – filling authogenic cement and is associated with a loss of effective porosity. Clay beds also restrict vertical permeability.

(Chehrazi and Rezaee 2012), (Esbensen and Martens 1987),(Felix and Munoz 2005), (Jung et al 2012), (Molenaar et al 2007) (UNSW – SPE notes2011 -2012)

Exploration and / or bore-hole attributes.

During exploration,  potential reservoir sandstone will have the following geo-physical and down-hole testing attributes.  (UNSW – SPE 2012 notes)

• Low natural gamma – indicator of low potassium, which is generally associated with  lithology that is low in clay minerals. This can also apply to carbonate reservoirs.
• Neutron porosity log, which measure the Hydrogen content is a key parameter as it directly measures the formation porosity around a borehole.This can also apply to carbonate reservoirs.
• A density intermediate between coal and shale
• Self potential, indicating porous sandstone versus shales.
• A high pore pressure gradient sandstone formation. This is indicative for both porosity and permeability because pore pressure demonstrates that the sandstone is in communication with the natural water column, or if over-pressured, is connected to a potential reservoir system and therefore is a permeable reservoir rock ( Dake 1978).
• Reservoir sandstones will have a contrasting seismic velocity compared to aquitards such as a shale cap.
• Porous, fluid filled formations such as a sandstone will give a contrasting surface magnetic, and deep resistivity signal compared with that of an aquitard(Musset and Khan 2000).

2.2 Describe various diagenetic processes that generally affect sandstone and carbonate reservoirs along with their impact on the reservoir properties. 

Diagenesis or the process of converting unconsolidated sediments into rocks occurs as a function of compaction and cementation .

When initially deposited, unconsolidated sediments will initially have a high primary porosity. In the case of sand, this porosity can be around   50% of total volume.  Carbonate deposits that form wackstone , packstone  and  grainstone will also have a very high initial porosity.

• Compaction: Burial of the initial deposit by overlying sediments will result in a gradual rise in pressure.
• The pressure causes an initial compaction, which, through slippage, re-arranges the orientation of loose grains such that it will allow them to increase their resistance to further compaction. This mild – pressure compaction will reduce the primary porosity of the sediment, but it will still preserve some of its original pore volume and shape.
• Depending on the properties of the original assemblage of sediment grains, the granular framework will either be resistive to normal burial, or will it will lose much of its original porosity. Well sorted sands tend to preserve much more of their primary porosity if the grains form a strong clast-supported framework around open pore voids.
• Deep burial, and under sufficiently high pressures, calcium carbonate type rocks will undergo re-crystallization if the pressure is sufficiently, and loose much of their original porosity.

Cementation: Fluid flows through the sedimentary formation during diagenesis will transport materials which are in solution through the network of pores.  

• These fluid flows are normally driven by thermal convection currents. As the flows cool, the fluids reach their solution saturation points, at which point they precipitate as authogenic minerals within the pores. These minerals form a cement which in time will reduce the overall porosity of the formation.

Types of cements;

• Syntaxial Quartz, and/or feldspars which forms a crystal over-growth on grain surfaces.
• Carbonates; Calcite can fill and block pores, and can have an extra-formational source, or be a transfer of materials to a less soluble part of the formation.
• Clay minerals - authogenic. These can be authogenic products of the breakdown f clay forming minerals already in the formation. These minerals include mainly feldspars and micas. The abundance of these minerals in a sandstone will increase the cementation of pores with clays. An abundance of feldspars and mica grains occurs in less mature sediments which are close to the weathering source of the mineral grains.
• Clay minerals – detrital. Clay particles already present at the time of deposition, can be cemented in by chemical precipitation of clays in solution. The clay type will determine the influence that detrital clays have on porosity and pore-throat aperture.

Secondary porosity;

• Carbonate reservoir porosity can be formed through secondary porosity processes.
• These processes are leaching and dolomitization an are controlled by fluid flows.
• Leaching occurs when low pH meteoric water leaches out carbonates, developing a secondary porosity and limestone permeability.
• Dolomitization occurs when calcium carbonate is replaced with magnesium carbonate ( dolomite), a chemical change which results in shrinkage of the original rock, opening up interconnected voids with a resulting porosity and permeability.

In summary, carbonates reservoir formation is influenced to a large degree by diagenetic processes such as compaction and pressure dissolution, leaching and dolomite replacement, while sandstone reservoirs are formed of material that is more resistive to diagenetic changes and so preserve more of their primary porosity and permeability.

• (Gray et al 1981),(Johnston 1952), ( Jung et al 2012),(Sarkisyan 1972) (UNSW – SPE notes 2012)

2.3. Permeability is the key parameter in determining reservoir quality. What is good permeability? What are the main geological controls on permeability in:

(a) sandstone;

(b) carbonate, and

(c) coal seams?

Permeability is a measure to describe the ability for fluid to flow through a porous medium (Felix and Munoz 2005), (UNSW SPE PTRL5013 course notes 2012).

The unit of permeability is the Darcy and is described by the expression for Darcy’s Law which states;

Where Q = units of volume per time m³/s¹, -k is the rock permeability, (P_b – P_a) is the pressure drop, µ is the fluid viscosity and L is the length over which the pressure drop is occurring.

• Permeability in petroleum reservoirs ranges across three orders of magnitude, from the millidarcy (md) to several darcies (d) (Felix and Munoz 2005). A rough guide to permeability is

Fair: 1-10md, 

Good: 10-100md

Very Good: 100-1000md

• The property of effective porosity is hence the combined properties of porosity and permeability. This is especially useful in reservoir terms, since a reservoir formation must have both properties in order to allow the extraction of hydrocarbons. 
• Sandstones show a great variability in porosity and permeability, even within the same geological province. Petro-facies, diagenetic depositional process, post diagenetic processes are all variable and suggest complexity in modelling the effective porosity of sandstone.
• Grain size, grain packing, pore connectivity, cementation and cement composition, authogenic processes, pore and grain deformational processes, including the types and volumes of primary and secondary porosity, the aperture of pore throats and capillary tortuosity will influence permeability Chehrazi and Rezaee 2012), (Molenaar et al 2007),(Felix and Munoz 2005). 
• Permeability is also an anisotropic property in most reservoirs , and results in the difference between vertical and horizontal permeability. 

While many of these variables are difficult to determine during initial exploration, the expression for Darcy’s Law mathematically states that permeability is a function of porosity and therefore, determining the porosity is a viable starting point for further investigation of sandstone reservoirs.

(a) sandstone;

The primary controls on sandstone permeability are linked to the depositional environment of the original sediment. Diagenesis has a lesser influence on permeability of sandstone than the original depositional conditions which directly relate to primary porosity and primary  permeability.

Grain Size and depositional environment energy:Pore throat aperture directly influences the permeability  an is a function of average grain size. Very fine sandstones, while porous, may have a low permeability due to increase of fluid flow friction through very narrow pore throat apertures.

Depositional environment, grain sphericity and the packing arrangement of the grains – Highly imbricated grains will restrict fluid flow by narrowing pores and pore-throat apertures. It may also increase capillary tortuosity. The preferential grain alignment will also restrict the direction of fluid flow. Higher grain sphericity tends to avoid aligned grain packing, and preserves permeability.

Depositional environment and the presence of fine particles.  Detrital clays and silts can fill pore spaces and form bridges which block pore throats.  A high energy depositional environment  such as a beach front removes fine particles, however an alternating high – low energy environment such as a tidal flow will allow many more fine particles to be present in the original sediment. Additionally the depositional environment will dictate the type of bedding, and as such will create the lateral and vertical variations in permeability and porosity.

Mineralogy of  grain assemblage  - Fluid flow can be impeded if the sandstone contains grains that dissolve and then re-form as cement bridges

Diagenesis; Deeply buried sediments are subject to higher compaction pressures , may have deformed grains and will have a lower porosity. Deep burial also infers a greater age. Over time, pores will become more infilled with cementation products of dissolved materials transported by convective water flows.

2.3 - (b) carbonate ( controls on permeability continued)

Diagenesis is a primary control on the permeability of carbonate reservoir rocks. In this aspect carbonate reservoirs differ from siliciclastic sedimentary reservoirs. For example, porous grainstone can be transformed through diagenesis into a low porosity, impermeable rock. Therefore age of the rock, burial and fluid flows all contribute to the departure of the rock from the original texture of the carbonate deposit.

 However the type of porosity may still be controlled by the original facies, independently of  diagenetic controls on permeability(Chehrazi and Rezaee 2012). This indicates a more complex relationship between facies controlled porosity , diagenesis and permeability than is evident for sandstone.

• Diagenetic  process of burial is a primary control on permeability through the process of compaction. The limestone can undergo a high degree of compaction, eliminating permeable pathways.
• Diagenetic burial pressure solution within pore spaces in the carbonate will also crystallize inside available pore spaces.
• Age; Limestones are made of a meta-stable material. Burial pressure, and fluid flows can dissolve the calcium carbonate, and re-crystallization within the same rock will result in a new crystal structure. As such it is an authogenic process that where the final permeability is not controlled by the rocks original texture. Older limestones will tend to have lost most, or all of their primary porosity.
• A carbonate formation is most likely to remain permeable if it is not deeply buried and if migrating hydrocarbons infiltrate it soon after  it has been formed.
• Fluid environment and Leaching:  Carbonates are soluble in water which have a low pH. If the fluid environment consists of meteoric surface water, then leaching occurs. The process of leaching where new voids are creating in the rock. Often the fluid flow pathways are through secondary porosity which is unrelated to the original pathways.
• Fluid environment and dolomitization. Dolomite is formed when water rich in Mg, (magnesium) flows through limestone, replacing it with dolomite. Because dolomite occupies a smaller volume this process opens up new fluid pathways along the crystal faces.
• Dolomite tends to preferentially replace more of the original carbonate mud. This means that limestones that were originally impermeable can end up being petroleum reservoirs.
• (Felix and Munoz 2012), ( UNSW SPE PTRL 5013 course notes 2012)

In summary, carbonate rock permeability is controlled by diagenetic and post-diagenetic processes, primarily related to the replacement of the original materials with fluid alteration products.

2.3 (continued)

(c) coal seams?

Coals can categorized into facies related to a variety of vegetation types which are deposited as peat accumulates. Because it contains no clastic grains, the porosity and permeability factors for a coal are different to all other sedimentary types.

• Coal permeability is the result of the combination of a micro-scale pore structure and a macro scale joint system.
• High rank coal once formed, will develop macro joints scales in a cleat pattern. This is a pattern of principal planar joints, face cleats, intersected orthogonally  by shorter “butt”cleats and this provides the principal Darcy flow permeability from a coal(Connell 2009).
• At the micro scale, the coal porosity provides the principal hydrocarbon gas storage capacity, and very small darcy flows (Connell 2009).
• Cleat spacing is critical control on permeability. Bright, high rank bituminous coals have closer cleat spacing of the order of 1mm than higher ash coals, where cleat spacings can be 30cm(Ward 1984).
• Cleat aperture is also a critical determinant for the permeability of a coal. Permeability ranges widely in coal, from 0.1md to several darcies and is a function of cleat aperture.

• Cleat orientation is determined by regional joints (Ward 1984). However field observation indicates that this relationship is variable. Cleat surfaces can remain geo mechanically shut as a function of formation stresses.

• If the face cleat direction is orthogonal to the main horizontal (H1)stress direction, then the cleat aperture will be less than if it was at an oblique angle to the H1 direction. Therefore the face cleat orientation relative to the  main regional stress direction is also a control on permeability.

• Artificial fracturing of the coal and preserving the aperture by the injection of proppant ( fine sand) can help to overcome regional stresses.

• Cleat joints are often filled with clay and calcite, which reduces permeability.
• Gas desorption and flow out of pore spaces and into the cleat network is determined by pore pressure. A lowering of pore pressure, which is equal to hydrostatic pressure, enhances the permeability of the micro-pores.

In summary, coal permeability as it related to gas production is controlled by regional stresses and pore pressure.

REFERENCES;

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(http://www.sciencedirect.com/science/article/pii/S0920410511002816)

Connell, LD, 2009: Coupled flow and geomechanical processes during gas production from coal seams. International Journal of Coal Geology 79 (2009) 18-28: Elsevier B.V.

Esbensen K.H., Martens H., (1987): Predicting oil-well permeability and porosity from wire-line petrophysical logs — a feasibility study using partial least squares regression, Chemometrics and Intelligent Laboratory Systems, Volume 2, Issues 1–3, August 1987, Pages 221-232, ISSN 0169-7439, 10.1016/0169-7439(87)80099-0.

(http://www.sciencedirect.com/science/article/pii/0169743987800990)

Félix L.C.M.  Muñoz L.A.B., 2005: Representing a relation between porosity and permeability based on inductive rules, Journal of Petroleum Science and Engineering, Volume 47, Issues 1–2, 15 May 2005, Pages 23-34, ISSN 0920-4105, 10.1016/j.petrol.2004.11.008.

(http://www.sciencedirect.com/science/article/pii/S0920410505000069)

Gray G.R. and Darley, H.C.H., 1981; Composition and Properties of Oil Well Drilling Fluids. Gulf Publishing Company, 4th edition (1981).

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Molenaar N, Cyziene J, Sliaupa S, 2007: Quartz cementation mechanisms and porosity variation in Baltic Cambrian sandstones, Sedimentary Geology, Volume 195, Issues 3–4, 1 March 2007, Pages 135-159, ISSN 0037-0738, 10.1016/j.sedgeo.2006.07.009.

(http://www.sciencedirect.com/science/article/pii/S0037073806002120)

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Sarkisyan, S.G., 1972: Origin of Authigenic Clay Minerals and their Significance in Petroleum Geology. Sedimentary Geology vol 7, issue 1. January 1972- Elsevier Amsterdam. Online resource available from UNSW Blackboard for course number PTRL5013.

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5013 course manual Part B Petroleum Reservoir: University of NSW School of Petroleum Geology 2012- Online resource available from UNSW Blackboard for course number PTRL5013 

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