Notes 2 Reservoir Rocks 2010

PgDip/MSc Energy Programme/Subsurface Reservoir Rocks

Reservoir Rocks

Review

In this topic the student is introduced to the key properties of oil and gas reservoir rocks.

Content

Introduction The reservoir is the portion of rock containing the pool of petroleum. It is usually composed of unmetamorphosed sedimentary rocks, such as sandstones, limestones and dolomites. However, reservoirs do, rarely, occur in igneous, metamorphic and shale rocks. Pools of hydrocarbons accumulate within rocks that have enough space to accommodate them. For commercial viability, this pool must be big enough. What is regarded as big enough depends on many factors including porosity, permeability, and location of the reservoir and proximity to other reservoirs or fields. A reservoir formation must have both porosity and permeability.

Porosity, or the presence of void spaces, enables the rock to contain hydrocarbons and other fluids. The greater the porosity, the greater the holding characteristics of the rock. Porosity alone however does not make recovery of formation fluids possible. If all the pore spaces are sealed off after hydrocarbon migration, recovery will be nigh on impossible as no fluid will be able to flow through the rock. For this to be viable the rock also needs permeability. Permeability is a measure of the ease of fluid flow through the rock, ie, the connectivity between the pore spaces.

Porosity Void spaces within most rocks usually contain connate water. It is this water which is displaced due to hydrocarbon migration. Porosity can be expressed as a void ratio or percentage.

Equation 1 100%volume Bulk

voids of Volume)(Porosity =

Porosity is independent of grain size, but is affected by sorting and roundness of grains. Pores take on three different morphologies (Figure 1).

The Robert Gordon University 2006 1 campus.rgu.ac.uk


Figure 1. Pore Morphology.

Hydrocarbons can be recovered from catenary and cul-de-sac pores but not from closed pores. Catenary pores may be flushed out by natural or artificial water flow, whereas cul-de-sac pores will only produce hydrocarbons due to expansion as reservoir pressures drop. The ratio of total to effective porosity is important as it relates directly to permeability.

Most reservoirs are water wet. This means that, even in an oil sand, there will be a thin film of water attached atomically to the surface of each grain (Figure 2). It cannot be removed and is known as the irreducible water content (Sw).

Figure 2. Irreducible Water Films.

This film of water will occupy a proportion of the pore space and will therefore reduce the porosity of the reservoir. We define the effective porosity of the reservoir as:

Equation 2 ( )wS1porosityporosity Effective = Since in a fine grained rock the pore spaces are small, the irreducible water content will affect a greater proportion of the porosity. Effective porosity is therefore affected by grain size. Small pores will be completely filled with water due to capillary action. Effective porosities are commonly 5-10% lower than the total porosity. Common reservoir porosities are 10-20% with exceptions of 5-30%. Carbonates generally have higher porosities and permeabilities than clastic reservoirs.



Nature of Porosity Porosity can be defined as primary or secondary. Primary porosity is that present after deposition on first burial, whereas secondary porosity is that formed sometime after deposition. Primary porosity will only be maintained if the grains are not altered, fractured or dissolved in any way and depends on factors such as:

uniformity of grain size; grain shape; manner of packing, which is related to the above; effects of compaction after deposition.

Primary porosity may be further broken down into two subsets, namely, intergranular (interparticle) and intragranular (intraparticle). Interparticle pores are present in all sediments initially, but are often lost quickly in carbonate sands and shales due to compaction and cementation. Intraparticle pores are generally found within skeletal grains (fossils) of carbonate sands. Compaction and cementation again, may destroy this. Most of the porosity in sandstone is preserved primary interparticle porosity.

In theory, the grain size should make no difference to the percentage of porosity. However, large grained sediments are much more likely to have a wide variety of grain sizes. Smaller grains will take up the pore spaces between larger grains. Hence fine overall grained sediments may have higher porosities than course grained sediments.

Uniform spherical grains have a higher theoretical porosity than that of angular grains. However, in practice, spherical grains pack with minimal porosity, as absolute uniformity of grain size is never achieved, whereas angular grains tend not to. The highest porosity is often found in sediments containing well sorted angular grains.

Porosity as can be seen is highly dependent on sorting. Packing helps sort grains according to size but also tends to make the rock as tight as possible. Packing is an ongoing process during rock formation as depositional packing will be followed by post-depositional packing and then compaction under increasing loads produced by burial. Compaction deforms the rock grains in an irreversible manner past their elastic limit.

Secondary porosity is generally referred to as the occurrence of extra pore spaces caused by post-depositional and diagenetic processes. In sandstones, modification of primary porosity is due mainly to interlocking of grains through compaction, contact solution and re-deposition, and to cementation. In carbonates, the principle modifications are due to solution, recrystallisation, fracturing and cementation. Sandstones and carbonates therefore have very different natural porosity characteristics. Due to continued burial, however, unless secondary porosity is formed at a rate in excess of the loss due to compaction, the total resultant porosity may in fact be less than the original primary porosity.

Solution porosity is common in carbonate reservoirs and is present in two forms. Moldic porosity occurs when only the grains or rock matrix is leached out. Vuggy porosity is formed when leaching and resultant pores



cross cut grains, matrices and cementatious particles. Vuggy porosity tends to be larger than moldic porosity, and is termed cavenous porosity

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ation acturing tends to occur under three

when it reaches a larger scale, sometimes several metres across.

Cementation porosity again takes on two forms. Fenestral porosity occurwhere there is a gap in the rock that is larger than the grain supported interstices. This could appear to be a primary form of poroin fact to shrinkage and buckling caused by dehydration, characteristically of lagoonal deposits. Intercrystalline porosity referpore that occur between the crystal faces of crystalline rocks. Morecrystallised limestone have negligible porosity. Dolomitization (replacement of calcite with dolomite) in the formation of secondary dolomites however results in as much as 13% shrinkage in size from thoriginal rock bulk, leading to a much greater porosity. Intercrystalline pores are characteristically angular (polyhedral) with sheet like throats.

Fracture porosity is rare in unconsolidated, loosely cemented sediments as they flow plastically under applied stress. Relatively brittle rocks, sucas limestones, sandstones, shales and igneous and metamorphic rocks may however contain large numbers of fractures. Fractures tend to blarger than most pores and increase permeability as well as overall porosity. Fractures can be caused by tectonics, compaction, dehydrand diagenesis. Tectonically, frdifferent scenarios (Figure 3).

Figure 3. Fracture Porosity and Tectonics (after Selley, 1998).

ing y create fracturing on a large

scale, even in quite ductile rocks.

. le volume

gs.

These characteristics may again be altered by tectonics. Faulting, foldand the presence of unconformities ma

Porosity Measurement There are several techniques for porosity measurement. The most direct techniques in the laboratory involve the withdrawal of air from the pore spaces using a vacuum, and measurement of the volume of displaced airThis combined with a calculation comparison to the bulk sampcan be used to determine porosity. For clastic reservoirs the measurements are commonly made on quite small samples or core pluFor carbonate reservoirs, however, the nature of the porosity may be insufficiently homogeneous for the use of small samples to give accurate



readings. The presence of vugs for instance may be completely missed. Full core samples are generally used for analysis of carbonate reservoirs therefore. Porosity may also be measured indirectly from geophysical well logs and seismic data.

nt fluid will

pass through a roc tionship:

Equation 3

Permeability Permeability is the property of a medium of allowing fluids to pass through it without change in the structure of the medium or displacemeof its parts, or more simply, a measure of the ease of which a

k. It can be defined from the rela

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fluid ofviscosity =sample of lengthL

area sectional crossAsample across drop pressure)P-(P

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be tested is isolated and allowed to flow, or from wireline logging.

The unit of permeability is the Darcy (from H.Darcy who carried ouoriginal work on permeability in the 1850s) and is defined as the permeability that allows a fluid of 1 centipoise viscosity to flowvelocity of 1 cm/s for a pressure drop of 1 atm/cm.

Permeability is a property of the rock. The higher the permeability tfaster, and therefore the more economic, the well production. The presence of irreducible water content reduces the permeability, and it is the job of the petroleum engineer to calculate the effective or relativepermeability. Permeability is measured in millidarcies (md). Average reservoirs have permeabilitie

ra sal of pe bility is:

fair: 1.0 10.0 md good: 10.0 100.0 md very good: 100.0 1000.0 md.

In the laboratory, permeability is measured using a permeameter (Fig4). As with porosity measurement, smaller samples may be used for homogeneous rocks, whereas full core samples may be needed for prappraisal for rocks such as vuggy carbonates. Usually a gas such as nitrogen is pumped through the sample and readings taken. Mobile mini - permeaters which pump nitrogen via a sealed probe that is pressed against the rock sample are also commonly used for conveas they are portable. Permeability often varies in direction, and is generally greater horizontally along the bedding than vertically across it.Measurements are commonly taken in both directions therefore. In thfield permeability can be measured via drill stem testing, where the production zone to



Fluid of viscosity

L

A

P2P1

Figure 4. Permeameter Schematic.

Darcys Law is only valid for situations of uniform porosity/permeability and for single phases. As most reservoirs will contain water as well as hydrocarbons, the concept of effective permeability must be taken into account in the same way that we have effective porositiy. The mutual interference of fluids with one another within the reservoir is generally retardative to absolute permeability. The capacity for flow of each fluid present is therefore less relative to flow capacity for each individual fluid if it were the only one present. Figure 5 illustrates how an oil and gas mixture may affect flow. As can be seen, just because only one fluid is produced, does not mean that the rock does not contain other fluids. Hence, water free oil may be produced from water wet reservoir rocks.

Figure 5. Relative Permeability.

The Effect of Capillary Pressure Most reservoirs are water wet and will contain a certain irreducible water content. The level of water content will depend on the capillary characteristics of the rock. The capillary pressure is the difference between the ambient pressure and the pressure exerted by the column of liquid. In the laboratory it can easily be demonstrated that capillary pressures increase with decreasing tube diameter, and hence pore size in reservoir rocks (Figure 6, left). Capillary pressure is also related to the surface tension between adjacent fluids. The greater the surface tension, the greater the capillary pressure. Capillary pressure tests can tell us a lot about the reservoir relative permeability characteristics. The pressure required to inject a second fluid into the rock (commonly oil, water, gas



or mercury) is known as the displacement pressure. As pressure increases, the proportions of the two fluids gradually reverse until the irreversible saturation point of the first fluid is reached. At this point, no further increase in the proportion of the second fluid is possible. Figure 6 (right) shows different capillary pressure test results. Curve 1 shows good displacement characteristics, as once invasion of the second fluid has begun, only small increases in pressure are required for maximum displacement of the first fluid. Irreducible water saturation is also low. This rock is likely to be well sorted, porous and permeable a good producer. In contrast, Curve 3 shows high displacement pressures and high water saturation, and is likely to come from a poorly sorted reservoir a poor producer.

Figure 6. Capillary Pressure.

The Effect of Rock Characteristics There is a general relationship between porosity and permeability. In sandstones for example, where porosity may be mostly primary in nature, permeability changes by a factor of ten for a certain x percentage change in porosity. For thick Tertiary sections x is approximately equal to seven. Even where this approximation can be used, permeability is much more variable than porosity. The percentage of porosity does not define tortuosity, the length of path and resistance to flow that the fluid is exposed to. Changes in either of these factors can vastly alter permeability.

When porosity is largely secondary, the variation of permeability is even greater. This can be demonstrated by looking at an artificial rock, ie, concrete. Concrete undergoes various reactions on cementation. When cured, it is very porous, but largely impermeable. A similar situation occurs in many carbonate reservoirs. Subsequent cracking, fracturing or dissolution will increase permeability, often in a very direction dependant manner.

With constant porosity, permeability tends to decrease with decreasing grain size due to the increasing effects of capillary pressure. As with



porosity, permeability is also often poorer in unsorted formations due to the restriction of pore throats by finer particles.

The effects of grain shape may however be the reverse from porosity. Well rounded, spherical particles may form a less porous structure than angular particles, but the resistance of flow (tortuosity) between the angular particles in a more porous structure may have a greater effect on permeability. Elongated particles will tend to pack in a directional manner depending on local conditions during. Deposition processes and packing are therefore extremely influential for both porosity and permeability, but may affect both in different ways. The relationships are complex and still poorly understood.

Reservoir Types The presence of oil and gas in appreciable quantity within a rock does not mean that their recovery is viable, either commercially or practically. Any rock however containing hydrocarbons and possessing the suitable porosity and permeability characteristics enabling recovery is a reservoir rock. Generally reservoirs are considered as two basic types, clastic reservoirs (mainly sandstones) and chemical reservoirs (mainly carbonates - limestone or dolomite). Sandstones are wholly inorganic in origin, whereas limestones are at least partially organic or chemical in origin, even if they are now in a clastic state. A small proportion of reservoirs are found in other rock types.

Porous clastic rocks are formed by standard geological processes and are composed of essentially stable, insoluble, hard particles. A good sandstone will be formed of well sorted particles that have probably travelled long distances before deposition. In contrast, good carbonate reservoirs are formed from soft, reactive, soluble materials that have not been transported. An understanding of reservoir rocks and their properties is essential if hydrocarbon recovery is to be efficient. Mismanagement could render a reservoir, or at least a well, useless.

Clastic Reservoirs Clastic reservoirs are aggregates of particles and fragments eroded, transported and deposited as sedimentary rocks. They can have a marine or continental origin. Deltaic (Niger Delta), beach and turbiditic (North Sea) sandstones are examples of marine deposits. Dune sands (North Sea) are an example of continental deposits.

Not all sandstones form good reservoirs. They must possess certain characteristics. The best reservoir sands are those in which all the grains are the same size (well sorted), well rounded, devoid of clay, only lightly cemented and preferably coarse grained as this minimises the space filled by the irreducible water content. Sands deposited as desert dunes are ideal reservoir rocks, for example, gas in the southern North Sea is contained in dune sands of a Permian age (250 Ma). The quality of a sandstone is therefore a function of the source area, transport and depositional processes, depositional environment and subsequent compaction. Diagenesis after deposition may play a significant role depending on the type of sandstone formed.



Sandstones classified by source materials are dominated by three types:

almost entirely detrital quartz (orthoquartzites); significant feldspar content (arkoses); high content of rock fragments (lithic) or clay matrix (greywackes).

Although there are always exceptions in nature, the best clastic reservoirs are likely to be composed of detrital quatrz as transport and weathering is likely to produce a well sorted, unreactive sediment. High quantities of feldspar are undesirable as they easily decompose to form clays. A high lithic content is undersirable as many contstituents also decompose readily. In addition particles may be readily deformed on compaction, thus reducing porosity and permeability.

Environments of sand deposition are varied. They may be wholly terrestrial, (dunes), fluvial (river deposits), tidal, deltaic, coastal or deep marine. Individual bodies tend to be restricted in size and lenticular or linear in shape. For example, in a beach environment, just offshore of the wave action muds, not sands, will be deposited. Sandstone reservoirs are commonly less than 25 metres thick. The accumulation of sand requires conducive bottom conditions for localisation of it. Low energy environments may seem to be most suitable, but removal of fine materials transported to and deposited at the site, or after deposition, requires high energy or flow characteristics. Water currents are most effective.

The original porosity of high energy sands may be as much as 45% 50% with permeability of 25d 100d. Loose sands may have porosity of approximately 30% while tight siliceous sands may be only 1%. A porosity of 15% is common in sandstone reservoirs. In addition to commonly high porosity, horizontal permeability of sandstones is generally higher than carbonates. Conversely however, cross bedding permeability may be low due to the frequent occurrence of shale breaks.

Depositional sorting influences not only the initial porosity, but also the sandstones capacity to receive cementatious material from external sources. Good initial sorting with decreasing grain size commonly leads to increasing porosity, and also, a decrease in total cement content and the proportion of external cement within that content. A small amount of cementation is desirable because it prevents sand production from the reservoir. Widespread cementation however will tend to reduce porosity and permeability. The most significant minerals involved with cementation of sandstones are quartz, calcite and authigenic clays. Pure quartz sandstones present the smallest opportunity for diagenetic alteration, though overgrowths of secondary silica are common. Quartz and calcite distribution is dependent on the pore fluids that have migrated through the rock, their chemistry and where they flow, as dissolution and precipitation take place. Clays can occur as detrital parts of the rock matrix or due to chemical precipitation. Clays themselves will hold water and reduce permeability, but may also alter chemically, depending on pore fluid chemistry, further affecting the rock properties. The presence of hydrocarbons will tend to inhibit cementation as water will not flow through the trapping structure freely. Porosity and



permeability may therefore be lower in the water zones of a reservoir than in the oil bearing zones.

Dissolution of minerals and their subsequent removal may lead to an increase in porosity. Dissolution of original constituents, most commonly nonquartz materials, will lead to secondary porosity, while dissoloution of introduced cements will lead to the rejuvination of primary porosity. Usually weathering induced porosity is subsequently destroyed due to normal diagenesis on burial, and may only be preserved within hydrocarbon reservoirs. Dissolution will only occur if large quantities of undersaturated water flows through the rock.

Compaction is also important in sandstones, the effects of which are directly related to the texture and mineralogy of the rock and depth. Porosity willl decrease with increasing depth as compaction forces due to the weight of the rock and fluids increase. Any abnormal pressures within the sands, however, may help preserve porosity by reacting against the compaction forces. Abnormal geothermal gradients will also affect porosity gradients as reaction rates increase as temperature rises. Generally the more mineralogically mature a sand is, the better its ability to retain its porosity on burial. Pure quartz sand will have a much lower porosity gradient than a chemically unstable volcanistic sand for example (Figure 7A). Texture is also important. A poorly sorted sand with an abundance of clay will lose porosity much faster than a well sorted sand. A linear relationship between porosity and depth is often found (Figure 7B). Figure 8 simplifies diagenetic pathways for sandstones.

Figure 7. A Porosity Gradients and Mineralogical Maturity (Nagtegaal, 1978), B Linear Porosity Relationships for Tertiary Sandstones Containing Different Fluids (Gregory 1977).



Figure 8. Simplified Diagenetic Pathways for Sandstones (after Selley, 1998).

Carbonate Reservoirs Chemical reservoirs are composed of chemical precipitates. Carbonates are the most important reservoirs and are found in the form of Limestone (CaCO3) as aragonite (unstable) or calcite (stable), or in the form of dolomite (CaMg (CO3)2). More than 50% of the Worlds reserves are found in Carbonate reservoirs. The porosity is less predictable than that of sandstones, as carbonates undergo a dissolution/reprecipitation processes, dependant on the pH of the percolating waters. The effects of diagenesis within carbonates is much more important than in sandstones, resultant reservoir rocks tend to be much less uniform than sandstones.

Carbonates form primarily in shallow, warm, low energy marine environments that do not receive significant quantities of external sediments. Most carbonate rocks begin as skeletal assemblages of carbonate secreting animals and plants which are highly permeable and unstable in the subsurface environment. Carbonate minerals are therefore easily dissolved and reprecipitated to form limestones whose porosity is largely secondary in nature and often unrelated to the primary porosity.

Limestones are generally considered separately as reefs, sands and muds. Reefs are unique in the fact that they are formed as rock rather than from lithification of sediment. Porosity may be high (60% - 80%).



Because they are formed in a lithified state, they do not undergo compaction to a great extent. If the reef is buried quickly, by impermeable sands for example, water will not flow throught the formation and no dissolution or precipitation reactions will occur. Thus primary porosity will be preserved. If acid or alkaline waters pass throught the reef however, dissolution (porosity enhancement) or cementation (porosity loss) will occur respectively. Fluctuations in sea level over the formation time period of the reef before burial may lead to a very complex diagenetic history.

Lime sands (detrital grains) may also have high initial porosities, but as they are not consolidated porosity will be reduced on compaction. As with reefs, exposure of the sands to flowing waters will lead to diagenesis. Although cementation will tend to reduce porosity and permeability, if it occurs early enough after burial, it may infact limit the overall loss as crystals can consolidate the matrix and thus inhibit further compaction losses. Carbonate sands that do not undergo early cementation of some type rarely form reservoirs. Lime sands are extremely important reservoir rocks. Figure 9 shows simplified diagenetic pathways for lime sands.

Lime muds refer to deposition of any carbonate sediment consisting of largely clay sized particles. The mud may be directly organic (animal and plant remains), wholly detrital, or more commonly, formed by direct precipitation from warm seawater in the form of aragonite needles. Aragonite is unstable in subsurface waters and reverts to calcite. This reaction involves an 8% bulk volume increase. Compaction and the aragonite to calcite reaction lead to rapid loss of porosity, and no real potential as a reservoir rock unless fracturing or dolomitisation occurs at a later stage. If the mud consists mainly of calcite however, chalks form with preserved porosity. Overpressures may further inhibit compaction giving values of 30% - 40%. Permeability tends to be low, but later fracturing may enhance this. Porosity within this type of reservoir is usually much more uniform than in other carbonate formations.

Dolomites can form from calcites, and vice versa, and may therefore be primary or secondary. This reaction depends upon the Mg-Ca ratio and salinity (Figure 10). Primary dolomites arfe generally bedded and often from laterally continuous units. Porosity may be high, but permeability low due to small pore throats. The exact chemistry of formation of primary dolomites is still contested. Secondary dolomites crosscut bedding often occuring in irregular zones underlying unconformities or around faults and fractures. secondary dolomites are generally crystalline in nature with porosity values in excess of 30%. Due to the intercrystalline nature of the pores, secondary dolomites also tend to be permeable. As has been mentioned, dolomitisation of calcite leads to a reduction in bulk volume of 13% and subsequent porosity increase. Any fracturing of the dolomite itself around the main fracture or fault zone will further increase porosity and permeability. Secondary dolomites are important reservoir rocks.



Figure 9. Simplified Diagenetic Pathways for Lime Sands (after Selley, 1998).

Figure 10. Stability Fields for Different Carbonate Reactions (Selley, 1998).



Other Reservoir Rocks Theoretically, any rock can act as a hydrocarbon reservoir, as long as it possesses desirable porosity and permeability characteristics. Rocks that do not inherently possess these qualities may sometimes gain them in time due to either fracturing or weathering.

Weathering of sandstones and carbonates in the formation of solution porosity has already been noted. Weathering of other rocks such as granites and gneisses also occurs as feldspars are leached out, leaving unconsolidated quartz sand.

In addition to enhancing a current reservoir rocks permeabilty, fracturing can occur in any brittle rock, porous or not, thus turning it into a potential reservoir. Fracture intensity and orientation are important factors. For instance, fractures commonly occur vertically and are therefore suited to production from horizontal wells. Even shales, which are generally only cap rocks, can form reservoirs when fractured sufficiently.

As we can deduce from the notes thus far, no matter how suitable a rocks properties are as a reservoir, for the pooling of hydrocarbons and the formation of a reservoir within this rock, further structures are needed.

The reservoir rock must be capped by an impermeable rock, commonly a shale, or the hydrocarbons will leach to the surface. If this occurs, many of the lighter fractions will be lost. An example of this is the pitch lake or La Brea tar sands in Trinidad.

In addition to a cap rock, there must also be some form of trapping structure that stops the flow of hydrocarbons along the strata. In the absence of a trap continued migration will occur, with eventual leaching to the surface if none is encountered. Trapping structures are looked at in the next topic.


ReviewContentIntroductionPorosityNature of PorosityPorosity Measurement

PermeabilityThe Effect of Capillary PressureThe Effect of Rock Characteristics

Reservoir TypesClastic ReservoirsCarbonate ReservoirsOther Reservoir Rocks

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Notes 2 Reservoir Rocks 2010

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