Rocks and Their Properties


Rock Properties
Rock is the stable natural forming of mineral material on the earth’s surface and any other similar planet. A rock consists of either single or various minerals that are strongly compacted by a mineral that shares the same qualities as cement. There are three main types of rocks namely sedimentary rocks, igneous rocks and metamorphic. Rock classification is generally based on the origin which also helps in determination of the use and structure. The existence of rocks is significant to human beings since they assist in the manufacture of many things such as jewelry, graphite, limestone, slate, gypsum, toothpaste, and plates. Houses too are built using rock products as it provides jobs to the miners thus contributing to the economy of the region where it is found (Schlumberger, 2016).
There are different properties of rocks namely, permeability, porosity, and fluid saturation. Porosity is the measure of empty spaces in an object or the ability to hold liquid. The diagram below can help one understand porosity better (Rock Images, 2016).

It is the actual fraction of the volume of empty space over the total volume which is between o and 1. Rock porosity can still be calculated as the percentage ranging from 0 to 100%. In substance, there are various ways of determining porosity, one of the tests include industrial CT scanning. Porosity can as well be calculated using the formula.
The porosity of consolidated rocks such as shale, limestone, sandstone or granite, potentially posses a complicated “dual” porosity compared to alluvial sediments, and they can either be cracked into unconnected and connected porosity. Regarding measurement, connected porosity can be gauged through the liquid or gas volume flowing in the rock where fluids are not able to enter the unconnected holes. Porosity can be calculated as the pore volume to the total volume (Zhang, 2016, p. 13-17). However, porosity can be regulated by the type of rock, distribution of the pores, cementation, history of the digenetic, and composition. The grain size cannot be used to control porosity since the volume of the space between the grains is only related to the way the grains are packed. Porosity in rocks does decrease with the depth and age. Schlumberger (2016) states that tertiary age gulf coast sand stones seem to be more porous compared to the Cambrian age sandstones simply because of the thermal history and the burial depth. The porosity of the rock surface decreases while the unit size gradually increases. In subject to rock biological processes, the rock aggregation engages high resistance of compaction and adhesion. The aggregation of rocks results in the density of sands that ranges between 1.60 and 1.80 g/cm3 thus, giving a porosity of 0.35 and 0.45.
Categories of porosities
Porosity is grouped into two different categories of deposition namely; primary and secondary porosities. The initial porosity advanced at the reservoir rock, is the primary porosity while the secondary porosity is build up after the primary porosity is formed. These processes occur due to various geochemical and geological activities that interchange in the basin of rock characteristic. With the presence of the cavity, fluids find more space to collect in the particular rock; this will lead to the high porosity of the rock. The same applies to fractures that develop to rock. Through connectivity, that is effective and porous. Zhang (2016, p. 22) shares that, all spaces are not effectively interconnected to form the channel for the fluid to flow while some are effectively interconnected thus allowing an easy and free flow of the fluid.

Porosity and Permeability (Rock Images, 2016)

From the figure above, the rocks seems to be porous since there is room for liquid to collect in the rock which is well linked to t6hus giving a good flow of the fluid. The following is the formula for calculating effective porosity of rocks.

The following is the formula for calculating absolute porosity of rocks.

There are various factors that affect porosity like the grain’s shape which is categorized in two types that are angular and rounded. The rocks with angular shapes have less porosity compared to those with rounded shapes. According to (Zhang, 2016, p. 24-31), in sorting grain arrangement, there is higher porosity in rocks containing sorted arrangement. The following figures help understand porosity of rocks based on grain size (Schlumberger, 2016).

Sorting arrangement of grain particles and its shape (Rock Images, 2016)
In cementation, porosity level reduces equally to the level of interstitial and the cementing substance increases. Apart from the fluids, spaces in between the particles of the rock can accommodate smaller particles. Lastly, there are fractures and vugs where the pore spaces are not linked due to dissolution of solvent particles.
Permeability is the ability of the rock to transmit fluids. Permeability is measured in units of Darcy which is represented as ‘k’. The link between porous and permeability is that, a rock with high porosity formation are quiet high in permeability. Carbonates and sandstones like dolomites and lime stones are common in rock reservoirs are permeable and porous (Zhang, 2016, p. 33-37). However, some impermeable rocks contain low permeability that serves as the seal to hydrocarbons as accumulation of the petroleum takes place as shown below.

(Rock Images, 2016)

Factors affecting permeability
There are various factors that affects permeability which is directly and proportional to porous material which is a portion of the particular material’s mass volume occupied by the pores. Geological features resolve the degree of permeability by adding or reducing the cross-sectional part of the pore space that is open. These issues influence the geometry of the pore spaces that are free of fluid type. The cross-sectional areas of the pores are different as the permeability of the arrays is also different dramatically. Permeability of rocks that are made up of huge grains is higher compared to those of the small grains (Schlumberger, 2016). However, sorting is the series of the size of the grains occurring in the sedimentary materials. Sorted materials posses grains that assume the size however, grains that are sorted poorly consist of grains with different sizes. The level of permeability varies and it decreases with the degree of sorting grains from good to poor since the spaces between the large grains can be filled by the small grains. Additionally, permeability is influenced by the shape of the grains (Zhang, 2016, p. 41).
Measurements of the grain shapes are roughness, roundness, and sphericity which are the magnitude in which the size of the grains assumes the shape of a sphere. Another factor is the roundness that relates to the level of smoothness of the grain surface that ranges from round to angular shapes while on the other hand, roughness is the magnitude of the texture on the grains thus these shapes affects the packing. The variables in the size and shape of grains can block the grains from getting closer to possible arrangement of packing which at the end of it brings impact to the permeability.
However, the magnitude of packing increases the ability of loosely particles to tight making a single grain to have contact to high number to close grains. The spaces between the cross-sectional are and the grains are free and open to the flow of reduction leading to low level of permeability. The alteration of the original texture and mineralogy of a rock is known as the digenesis. Secondary porosity is created by the dissolution or fracturing of the rock that leads to increase the level of permeability. Permeability can still be reduced through the precipitation of rock grains and minerals. The pore volume is bridged by the clay minerals that form crystals forming the pore walls (Schlumberger, 2016).
Measuring permeability
The measurement of permeability can either be done in the laboratory or directly in the field. Analysis are done in the laboratory where a single-phase fluid that will flow through the rock core of an established diameter and length. Due to viscosity, the fluid flows on a set rate and immediately the fluid gains a steady flow, the analyst ought to take the pressure measurement which will drop across the core. At this point, the analyst will use the Darcy’s law in calculating permeability. In the field, it is estimated in the near-wellbore region where logging data is used. The initial logging data information is got from the Nuclear Magnetic Resonance (NMR) tools. To estimate the permeability from the NMR estimates, one to acquire knowledge on the empirical links between the calculated permeability, the size of distributed pore size and porosity. Additionally, permeability can as well be derived from sampling tools and down whole pressure measurements. On the reservoir scale, permeability is gauged with the drill-stem tests (DSTs). The interpreters do apply different techniques in order to match the transient behavior to the one predicted through a formation (Scho?n, 2011, p. 35).
Fluid Saturation
Due to the formation and the results of oil origin and migration conditions, reservoir rocks have the following fluids; gaseous hydrocarbons, salt water, and liquid hydrocarbons. The fluids are supplied at a certain way within the porous medium just below the rocks reservoir pressure and temperature conditions are generally found not to be similar distributions in the cores on the surface (Schlumberger, 2016). The adjustments in the modifications are due to the following; first and foremost, it is difficult to avoid the causes such as the incursion of drilling mud and the expansion of gas following the fall of pressure at the time the core are raised. Secondly, handling of errors like washing the cores or drying up of the temperatures.
Determining Fluid Saturation
In solving the fluid saturation, there are two main approaches to the issue by determining the original fluid saturation. There is a direct approach that involves selecting of the rock particles which are used in measuring of the saturations of samples that are retrieved from the parent rocks. However, an indirect method can be used to gauge the fluid saturation through taking direct physical measurements of other properties like using electronic logs; one can still use the measurements capillary pressure (Zhang, 2016, p. 46).
Determining Fluid saturations in the rocks
This is done to determine the amount of fluid saturations; it is done directly from the samples that are extracted from the reservoir. During this process, the first thing ones should do is to understand how the values are measured. Secondly, one needs to understand what the measured values indicate and thirdly, after knowing what they present, one needs to understand how they are applied. For one to measure the values of the original rock saturations, there are three important ways involved which can either be evaporation or leaching of the fluids from the rock through the extraction of solvent (Scho?n, 2011, p. 47).

Retort distillation apparatus (Rock Images, 2016).

Retort distillers shown in the figure above, are apparatus used in taking the measurements of initial saturation using the retort method which uses a small sample of the rock. Using the retort the sample is heated and the volumes of water measured and the amount of oil driven away thus taking the measurement of the fluid saturations. Samples first crushed before being weighed then placed on the apparatus later where it is heated directly to a 1200F, as it is heated, the liquid evaporates then collected and gets separated after it has been condensed. However, the retort method has got some challenges. For one to remove the oil, it is required that the temperatures are strongly heat from 1000 – 1200F.
At this moment, the degree of the temperatures drives off the crystallized water resulting to the recovery of water values which are larger compared to the interstitial water (Zhang, 2016, p. 48). Another error occurs when the oil in retorting samples is heated at high temperatures crack. This form of hydrocarbon molecule reduces the volume of the fluid thus causing coats to the internal parts of the wall of the sample used. Retort method is an effective and rapid means of determining the fluid saturations. It can as well provide oil and water volumes. This enables the water and oil saturations be calculated by the following formulas;

It is necessary to use a proper drilling fluid so as to achieve realistic results that correlates hydrocarbon saturations. The figures below represent the correlation used in correcting saturations that are measured ranging from cores to original conditions.

Laboratory determination of fluid saturation.

Determination of Fluid Saturations by Extraction with a Solvent

Modified ASTM extraction apparatus

The extraction can be done by a method of a modified ASTM or centrifuge. From the standard distillation method, the core is put to enable the vapour of naphtha, gasoline, or toluene via the core; it is later condensed to reflux back to the core (Zhang, 2016, p. 48-52). Through this process, the oil and water inside are leached out as water and extraction fluid that have been condensed are collected in a graduated marked tube for proper measurements and recordings. Due to the high density of water, it settles at the bottom of the tube as the extraction fluid refluxes back to the main vessel. The figure above is an illustration of the distillation apparatus.

Rock Images. “Rock Porosity Search.” Google. Last modified 2016.
Schlumberger. “Permeability – Schlumberger Oilfield Glossary.” The Oilfield Glossary – Schlumberger Oilfield Glossary. Last modified 2016.
Scho?n, Ju?rgen. Physical Properties of Rocks: A Workbook. Amsterdam: Elsevier, 2011.
Zhang, Lianyang. Engineering Properties of Rocks. Oxford, United Kingdom: Butterworth-Heinemann, 2016.







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