Engineering classification of porosity

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During sedimentation and lithification, some of the pore spaces initially developed became isolated from the other pores by various diagenetic and catagenetic processes such as cementation and compaction. Many of the pores will be interconnected, whereas others will be completely isolated. This leads to two distinct categories of porosity: total (absolute) and effective, depending upon which pore spaces are measured in determining the volume of these pore spaces. The difference between the total and effective porosities is the isolated or non-effective porosity.

Absolute porosity is the ratio of the total void space in the sample to the bulk volume of that sample, regardless of whether or not those void spaces are interconnected. A rock may have considerable absolute porosity and yet have no fluid conductivity for lack or poor interconnection.

Effective porosity is the ratio of the interconnected pore volume to the bulk volume. This porosity is an indication of the ability of a rock to conduct fluids. Effective porosity is affected by a number of lithological factors including type, content and hydration of clays present in the rock, heterogeneity of grain sizes, packing and cementation of the grains and any weathering and leaching that may have affected the rock. Many of the pores may be dead-ends with only one entry to the main channel system. Depending on wettability, these dead-end pores may be filled with water or oil, which are irreducible fluids.

In order to recover oil and gas from reservoirs, hydrocarbons must flow several hundred feet through pore channels in the rock before they reach the producing wellbore. If the petroleum occupies non-connected void spaces, it cannot be produced and is of little interest to the petroleum engineer. Therefore, effective porosity is the value used in all reservoir engineering calculations.

Geological classification of porosity

As sediments are deposited in geologically ancient seas, the first fluid that filled pore paces in sand beds was seawater, generally referred to as connate water.A common method of classifying porosity of petroleum reservoirs is based on whether pore spaces in which oil and gas are found originated when the sand beds were laid down (primary matrix porosity), or if they were formed through subsequent diagenesis (dolomitization in carbonate rocks), catagenesis, earth stresses and solution by water flowing through the rock {secondary or induced porosity).

The following general classification of porosity, adapted from Ellison, is based on time origin, mode of originand distribution relationships of pore spaces.

Characteristic features of the two basic porosity types:

Primary porosity:

1. Intercrystalline - voids between cleavage planes of crystals, voids between individual crystals and void in crystal lattices. Many of these voids are subcapillary, i.e. pores less than 0.002 mm in diameter. The porosity found in crystal lattices and between mud-sized particles has been called " micro porosity". Usually high recovery of water in some productive carbonate reservoirs may be due to the presence of large quantities of micro porosity.

2. Intergranular (interparticle) - voids between grains, i.e. interstitial voids of all kinds in all types of rocks. These openings range from subcapillary through super-capillary (voids greater than 0.5 mm in diameter).

3. Bedding planes - voids of many varieties are concentrated parallel to the bedding planes. The larger geometry of many petroleum reservoirs is controlled by such bedding planes. Differences of sediments deposited, of particle sizes and arrangements and of the environments of deposition are causes of bedding plane voids.

4. Miscellaneous sedimentary voids - (1) voids resulting from the accumulation of detrital fragments of fossils; (2) voids resulting from the packing of oolites; (3) vuggy and caverneousvoids of irregular and variable sizes formed at the time of deposition; (4) voids created by living organisms at the time of deposition.

Secondary porosity

Secondary porosity is the result of geological processes (diagenesis and catagenesis) after the deposition of sediment. The magnitude, shape, size and interconnection of the pores may have no direct relation to the form of original sedimentary particles. Induced porosity can be subdivided into three groups based on the most dominant geological process.

1. Solution porosity- channels due to the solution of rocks by circulating warm or hot solutions; openingscaused by weathering (enlarged joints or solution caverns); and voids caused by organisms and later enlarged by solution.

2. Dolomitization - a process by which limestone is transformed into dolomite. Some carbonate rocks are almost pure limestones and if the circulating ore water contains significant amounts of magnesium cation, the calcium in the rock can be exchanged for magnesium in the solution. Because the ionic volume of magnesium is considerably smaller that that of the calcium which it replaces, the resulting dolomite will have greater porosity. Complete replacementof calcium by magnesium can result in a 12 - 13% increase in porosity.

3. Fracture porosity- openings created by structural failureof the reservoir rocks under tension caused by tectonic activities such as folding and faulting. These openings include joints, fissures and fractures. Porosity due to fractures alone in carbonates usually does not exceed 1%.

4. Miscellaneous secondary voids - (1) saddle reefswhich openings at the rest of closely folded narrow anticlines; (2) pitches and flatswhich are openings formed by the parting of beds under gentle slumping; (3) voids caused by submarine slide breccias and conglomerates resulting from gravity movement of seafloor material after partial lithification.

In carbonate reservoirs secondary porosity is much more important than primary porosity. Primary porosity is dominant in clastic (detrital \ fragmental) sedimentary rocks (sandstones, conglomerates and certain oolite limestones). It is important to emphasise that both types of porosity often occur in the same reservoir rock.

Text 16

Read the text " Permeability" and make the annotation of it.

Permeability

(Definition, classification and the factors affecting the magnitude of permeability)

Permeability is easiness with which fluid can move through porous rock. High permeabilitymeans numerous channels for oil and gas migration. A reservoir rock must have the ability to allow petroleum fluids to flow through its interconnected pores. This rock property is termed permeability. The permeability of a rock depends on the effective porosity. Therefore, permeability is affected by the rock grain size, grain shape, grain size distribution (sorting), grain packing and the degree of consolidation and cementation. Permeability is affected by the type of clay present, especially where fresh wateris present.

French engineer Henry Darcy developed a fluid flow equationthat since has become one of the standard mathematical tools of the petroleum engineer. One Darcy is a relatively high permeability and the permeability of most reservoir rock is less than one Darcy. The common measure of rock permeability is in millidarcies (mD) or um in SI units.

The term absolute permeabilityis used if the porous rock is 100% saturated with a single fluid (phase), such as water, oil or gas. When two or more fluids are present in the rock, the permeability of the rock to the flowing fluid is called effective permeability.

Because fluids interfere with each other during their movement through the pore channels in the rock, the sum of effective permeability will always be less than the absolute permeability. The ratio of effective permeability of one phase during multiphase flow to the absolute permeability is the relative permeabilityto that phase.

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