Migration and Accumulation of Petroleum

The genesis of petroleum occurs in compacted clay and shale beds, which are essentially impermeable to fluid flow. The processes by which hydrocarbons migrate from the source rock to a porous, permeable reservoir are called primary migration. After leaving the source rock, the hydrocarbons migrate upward through permeable beds until they reach a sealed hydrocarbon trap where accumulation occurs forming a hydrocarbon reservoir. This process has been called secondary migration.

Primary Migration

The geochemical evidence of the generation for petroleum shows that hydrocarbons do not generally originate in the structural and stratigraphic traps in which they are found. The petroleum reservoirs are porous, permeable geologic structures, whereas the source rocks have been identified as compacted, impermeable shales.

Compaction of sediments begins as soon as the sediments begin to accumulate. During original accumulation, the loose, fine-grained sediments contain more than 50% water. As they are buried deeper, due to subsidence and continued deposition of sediments on top, the interstitial water from the deeper sediments is expelled, resulting in a decrease in porosity and an increase in bulk density.

The material acquires cohesive strength as the grains are pressed together tightly. Chemical changes occurring in the interstitial fluids may produce precipitates that cement the grains into an even more cohesive formation. The salinity of compaction fluids moving in an upward direction gradually increases until precipitation occurs due to supersaturation.

Secondary Migration

As petroleum reservoirs exist in a water environment, the migration of hydrocarbons from the point of release in a source rock to the top of the trap is intimately associated with capillary pressure phenomena and hydrology. The pore distributions, tortuosity of continuous channels, porosity, permeability and chemical characteristics of reservoir rocks and their interstitial fluids differ widely.

The migration of oil as distinct droplets in water-saturated rock is opposed by the capillary forces, which are functionally related to pore size, interfacial tension between oil and water and adhesion of oil to mineral surfaces (wettability).

The more usual case is one in which the oil droplet exists within the confines of a large pore containing several smaller-sized pore throat exits.

Under these conditions, the pressure required to displace the droplet from the large pore through the constriction of a pore throat (displacement pressure) is the difference between the capillary pressures of the leading and trailing pores. The two forces in a reservoir that are most likely to be operating on the droplet are buoyancy and hydrodynamic pressure.

As the oil leaves the source rock under the forces of compaction, large saturations develop at the entry of the reservoir rock. The oil then begins to migrate upward as a continuous phase in long filaments within the pores. Under these circumstances, sufficient buoyant and hydrodynamic forces can develop to cause migration of the oil.

Secondary migration of petroleum ends in the accumulation in a structural or stratigraphic trap and sometimes in a trap that is a complex combination of the two.

The hydrocarbons accumulate at the highest point of the trap and the fluids are stratified in accordance with their densities, which show that individual hydrocarbon molecules are free to move within the reservoir. The petroleum accumulation may become:

1. exposed by an outcrop and develop an oil seep;

2. uplifted and eroded to form a tar pit.

In addition, petroleum may be transported to another sedimentary sequence as a result of rapid erosion and clastic transport.

The caprock (oil trap seal) may not be absolutely impermeable to light hydrocarbons. The capillary pressure relationship of the rocks overlying the oil traps may form an effective vertical seal for liquid petroleum constituents, but the seal may not be completely effective in retaining lighter hydrocarbons.

Text 15

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

Porosity

Porosity is an availability of pore spaces between rock particles. Porosity is a ratio of open space to total volume of rock and is calculated in percentage

Sand grains and particles of carbonate materials that make up sandstone and limestone reservoirs usually never fit together perfectly due to the high degree of irregularity in shape. The void space created throughout the beds between grains, called pore space or interstices, is occupied by fluids (liquids \ gases). The porosity of a reservoir rock is defined as that fraction of the bulk volume of the reservoir that is not occupied by the solid framework of the reservoir.

According to this definition, the porosity of porous materials could have any value, but the porosity of most sedimentary rocks is generally lower than 50%.

Factors governing the magnitude of porosity

Fraser and Graton determined the porosity of various packing arrangements of uniform spheres. They have shown that the cubic or wide-packed system has a porosity of 25.9%.

The porosity for such a system is independent of the grain size (sphere diameter). However, if smaller spheres are mixed among the spheres of either system, the ratio of pore space to the solid framework becomes lower and porosity is reduced. Fig. 3 shows a three-grain-size cubic packing. The porosity of this cubic packing is now approximately 26.5%.

The porosities of petroleum reservoirs range from 55 to 40% but more frequently are between 10% to 20%. The factors governing the magnitude of porosity in clastic sediments are:

1. Uniformity of grain size (sorting): is the gradation of grains. If small particles of silt or clay are mixed with larger sand grains, the effective (intercommunicating) porosity will be considerably reduced. These reservoir rocks are referred to as dirty or shaly. Sorting depends on at least four major factors: size range of the material, type of deposition, current characteristics, and the duration of the sedimentary process;

2. Degree of cementation (consolidation): highly cemented sandstones have low porosities, whereas soft unconsolidated rocks have high porosities. Cementation takes place both at the time of lithification and during rock alteration by circulating groundwater. Cementing materials include: calcium carbonate, iron sulfides, dolomite, clays, including any combination of these materials;

3. Amount of compaction during and after deposition: compaction tends to close voids and squeeze fluid out to bring the material particles closer together, especially fine-grained sedimentary rocks. The expulsion of fluids by compaction at an increased temperature is the basic mechanism for primary migration of petroleum from the source to reservoir rocks. Whereas compaction is an important lithifying process in claystones, shales and fine-grained carbonates, it is negligible in closely packed sandstones or conglomerates.

Generally, porosity is lower in deeper, older rocks. Many carbonate rocks show little evidence of physical compaction;

4. Methods of packing:with increasing overburden pressure, poorly sorted angular sand grains show a progressive change from random packing to a closer packing.

Engineering classification of porosity

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 planesof 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 porositycan 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)

Permeabilityis 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.