GENERATION OF HYDROCARBON1.1-Petroleum Source Material1.1.1-Formation and Preservation of Organic Matter In the nineteenth century, it was widely believed that petroleum had a magmatic origin and that it migrated from great depths along subcrustal faults. But the overwhelming evidence now suggests that the original source material of petroleum is organic matter formed at the earth's surface.The process begins with photosynthesis, in which plants, in the presence of sunlight, convert water and carbon dioxide into glucose, water and oxygen: 6CO2 + 12H2O C6H12O6 + 6H2O + 6O2 Photosynthesis is part of the larger-scale carbon cycle (Fig. 01). Ordinarily, most of the organic matter produced by photosynthesis gets recycled back to the atmosphere as carbon dioxide. This can occur through plant and animal respiration, or through oxidation and bacterial decay when organisms die

1.1.2-Preservation and Organic ProductivityAll organic matter in the ocean is originally formed through photosynthesis. The main producers are phytoplankton, which are microscopic floating plants such as diatoms, dinoflagellates and the blue-green algae. Bottom-dwelling algae are also major contributors in shallow water, shelf environments. 1.1.3-Preservation and Organic DestructionAreas of high productivity are not necessarily those best suited for preservation. Destruction of organic matter must also be prevented. Complete biological recycling of organic carbon is retarded by anything that limits the supply of elemental oxygen. This occurs most favorably in either one of two settings: rapid rate of deposition; and stratified, oxygen-poor water bodies with anoxic bottoms First, rapid deposition may be necessary to keep the organic material from being destroyed. Preservation is also favored by density stratification, which produces oxygen-poor bottom waters. Water stratification and oxygen depletion are well known in the modern Black Sea, The Eocene-age lakes of Utah, Colorado and Wyoming, in which the Green River oil shale formation was deposited, have been interpreted as seasonally stratified water bodies which at a later stage become permanently stratified (Fig 02)

In the present-day world's oceans, there is a zone of maximum oxygen depletion at a depth of about 200 meters, with oxygen more abundant in the shallow surface waters and again at deeper levels (Figure03)

1.1.4-Diagenesis of Organic MatterThere are three important stages in the burial and evolution of organic matter into hydrocarbons: diagenesis;catagenesis; and metagenesis. Diagenesis of Organic MatterDiagenesis of organic matter begins as soon as sediment is buried. However, the point at which diagenesis ends is subject to how the term is used. Some geologists use the term in a restricted sense to include only processes that occur as sediment consolidates into sedimentary rock. Others expand the realm of diagenesis to include all processes extending up to, and blending imperceptibly into, regional metamorphism. In this discussion, diagenesis is defined on the basis of organic matter, and it includes all changes that occur up to the stage of petroleum generation.Freshly deposited muds are unconsolidated and may contain more than 80% water in their pores. These muds compact very quickly. Most of the porosity is lost in the first 500 meters of burial (Figure04). After that, compaction to form mudstones or shales continues much more slowly.

1.1.5-Kerogen ComponentsUnder the microscope, kerogen appears as disseminated organic fragments. Some of this material is structured. It is recognizable as plant tissue fragments, spores, algae, and other pieces with a definite biological organization. These plant-derived structured fragments can be grouped into distinct biological units called macerals. Macerals in kerogen are equivalent to minerals in rocks. Three major maceral groups are important: vitrinite, exinite and inertinite. Kerogen ComponentsVitrinite is the dominant maceral type in many kerogens and is the major component of coal. It is derived almost entirely from woody tissue of the higher land plants. Because it is derived from lignin and is difficult to break down, vitrinite can appear in almost any depositional environment, marine or nonmarine, and is generally the most abundant type of structured particle.Exinite macerals are mainly derived from algae, spores, pollen, and leaf-cuticle waxes. High percentages of exinite are not common, but if present, they usually imply lacustrine or shallow marine environments.Inertinite macerals come from various sources that have been extensively oxidized before deposition. Charcoal, derived from woody plants, is the major recognizable type. Inertinite is usually a minor component of kerogen, and is abundant only where much of the organic matter has been recycled.In addition to the structured macerals, some of the components of kerogen are amorphous. Amorphous particles have been so mechanically broken up and/or chemically altered by bacteria and fungi that their original maceral types and cell structures have been obliterated -Amorphous particles are not true macerals but alteration products, although the maceral term "amorphinite" has sometimes been applied to these materials.1.2-Hydrocarbons and Kerogen TypeThe macerals and amorphous particles in kerogen affect its ability to generate hydrocarbons. Oil-prone kerogens generally are made of more than 65% exinite and amorphous particles (Figure 05). Kerogens with 65% to 35% of oil-prone components will expel mostly condensate and wet gas. With less than 35% oil-prone constituents, the kerogen will yield dry gas if dominated by vitrinite and will be non-reactive and barren if dominated by inertinite.

The oil-prone kerogens can be divided into two types. Type I, or algal kerogen (Table 1), is rich in the algal components of exinite, and is formed in either lacustrine or marine environments. Type I kerogen is derived mainly from lipids and tends to produce crudes that are rich in saturated hydrocarbons.

Kerogen TypeOriginOrganic Constituents

I AlgalAlgae of marine, lacustrine,boghead coal environmentsMostly algal components: of exinite (alginite); some amorphous material derived from algae

II Mixed MarineDecomposition in reducing environments, mostly marineAmorphous particles derived mostly from phytoplankton, zooplankton, and higher organisms; also some macerals from these groups

III CoalyDebris of continental vegetation (wood, spores, leaf cuticle wax, resin, plant tissue )Mostly vitrinite;some exinite ( not algal ) and amorphous decomposition products

IV InertFossil charcoal and other oxidized material of continental vegetationMostly inertinite; some amorphous decomposition products

Type II is a kerogen derived from mixed marine sources. Its particles are mostly amorphous and result from the decomposition of phytoplankton, zooplankton, and some higher animals. Its chemical nature is intermediate between Types I and III. Type II kerogens tend to produce naphthenic and aromatic-rich oils, and they yield more gas than Type I. Type III or coaly kerogen, is rich in vitrinite macerals, and therefore has a very low capacity to form oil. It mainly generates dry gas. Any oils generated from Type III kerogens are mostly paraffinic waxy crudes derived from its exinite and amorphous constituents. There is a fourth kerogen type which is extremely rare. It is rich in inertinite macerals and produces very low hydrocarbon yields. Inertinite is, as its name implies, inert and has practically no ability to generate either oil or gas (Figure 05). Sedimentary rocks commonly contain mixtures of the kerogen types. Many oil shales contain dominantly Type I, the algal kerogens. Coals and some nearshore clastic source rocks, such as those found in deltas, contain mainly Type III, coaly kerogen. In some cases, coal deposits can be direct contributors to significant natural gas accumulations, as for example the Carboniferous coals of the North Sea. Many marine source rocks have either Type I algal or Type II mixed marine kerogen, with Type II the more common. For example, some of the excellent source rocks of Iran contain mostly Type I, algal kerogen, while the Paleozoic source rocks of the North African Sahara have Type II, mixed marine kerogen. In the stage of diagenesis, prior to the generation of oil and gas, each of the kerogen types has a unique chemistry (Figure06).This is because kerogen composition is controlled by the types of macerals and the original biopolymers from which it was formed. This chemical variability of immature kerogen types and the changes that occur as petroleum is generated are usually presented as plots of the atomic hydrogen to carbon ratio (H/C) against the oxygen to carbon ratio (O/C) . This graph is often called a Van Krevelen diagram ( Figure07, and Figure 08)

Of particular importance is the H/C ratio, which decreases rapidly as hydrogen-rich molecules are cracked off as oil or gas. Remember that the highest possible organic H/C ratio is 4, which is found in the hydrocarbon gas methane. The O/C ratio helps define the kerogen origin, but most of the oxygen is lost in diagenesis as CO2 and H2O and very little survives to affect the petroleum generation process.Of the four kerogen types, the Type I algal kerogens have the highest atomic H/C ratios during diagenesis, initially about 1.65. Type II, III and IV start out with progressively lower H/C ratios.

As any of these kerogens are heated, they may reach the second stage in the evolution of organic matter, the stage of catagenesis (Figure08). Catagenesis is defined as the stage at which oil and natural gas is generated from kerogen. Since oil and gas molecules have very high H/C ratios, generation of petroleum will cause the H/C of the residual kerogen to decrease. Ultimately, all kerogen types will converge along a common path during the final stage in the evolution of organic matter, the stage of metagenesis. During metagenesis, oil and gas generation directly from kerogen ceases, but considerable methane gas can still be generated from the thermal alteration of previously generated crude. The kerogen residue of this stage approaches the pure carbon state, that is, graphite.Since it starts out with a lower H/C ratio (Figure07 & Figure 08), Type II kerogen can generate less hydrocarbons than Type I, even though both are oil-prone. Similarly, Type III is less significant in the total quantity of hydrocarbons it can generate, and Type IV is almost barren.1.3-Depth, Temperature and Time in Petroleum FormationThe generation of hydrocarbons can be related to burial depths of source rocks, since temperature increases with increased depth. The actual generation depths for particular source rocks will depend on the local geothermal gradient, as well as kerogen type and burial history. The depths given in Figure09 are average, maximum and minimum generation depths.During diagenesis and at very shallow depths, only biogenic methane, or marsh gas, is generated by the action of anaerobic bacteria.

At about a depth of 1 to 2 kilometers the catagenesis stage begins. The early stage of catagenesis, down to a depth of about 3 kilometers, corresponds to the principle zone of oil formation. Source rocks buried within this depth range are said to be within "the oil window" .Late catagenesis typically begins at depths of about 3 kilometers to 3.5 kilometers. This is the principle zone of gas formation, and both wet gas and methane are produced. But below depths of about 4 kilometers, the source rocks become overmature. At this point, metagenesis begins and only methane is produced.

The correlation of petr. generation to depth is primarily a function of the increased Temp., and the graph in Fig. 09 can also be constructed with Temp. as the ordinate axis (Figure10). Major oil generation does not occur until source rocks are heated above approximately 60C. These low Temp. oils which form at shallower depths tend to be heavy and rich in NSO-compounds. With increasing temperature and greater depth, the oils become lighter. Maximum oil generation occurs at temperatures of about 100C. Above this temperature oil generation gradually declines and condensates form.The oil window closes, and the principal zone of gas generation begins, at temperatures of about 175C. Generation directly from kerogen stops at about 225C, but methane is still generated from the cracking of previously formed oil at temperatures up to 315C, the point at which source rocks begin to undergo regional metamorphism. At those elevated temperatures, however, porosity may be so reduced that gas generated at this stage might not be economically recoverable.

An example of the maturation progression is found in the western Canada basinImmature source rocks are present in the east within shallow Upper Cretaceous sediments (Fig. 11). These yield dry gas with a high N2 content. Deeper burial has resulted in Cretaceous and Devonian rocks rich in oil and wet gas. Evans and Staplin (1971) have estimated that the wet gas and liquid hydrocarbons in the western Canada Basin were formed in the temperature range of 60 to 170C. Near the basin's western margin, Paleozoic rocks are deeply buried and the dominant gases produced are methane and hydrogen sulfide.The maturation progression in the western Canada basin The laws of chemistry tell us that the rate of a reaction is the function of both temperature and time. Fig.12 shows the present formation temperature plotted against the age of various source rocks. This graph has been constructed using data from many actual case studies. Formation temperatures are lowest, less than 60C, for old Paleozoic source rocks, and increase to more than 150C for young Cenozoic ones. Figure13 compares the depth and temperature of the beginning of the oil window for several source rocks of different ages

Fig.12-The present formation temperature against the age of various source rocks

Fig.13-DEPTH AND TEMPERATURE @ THE BIGINNING OF THE PRINCIPAL ZONE OF OIL FORMATION1.4-Paleothermometry 1.4.1-Paleothermometry: Kerogen AnalysisSome paleothermometry methods are based on the physical and chemical properties of the kerogen itself..One method employs the Van Krevelen diagram (Fig.07)The color of some of the kerogen macerals can also be used as a paleothermomete Another method is based on the vitrinite reflectivity of the kerogen. This is measured by means of a reflecting microscope equipped with a photo-multiplier A linear increase in temperature causes the reflectivity of vitrinite to increase approximately exponentially, and plots as a straight line on semi-log paper (Figure14). Actually, the percent mean reflectance, called Rm, or sometimes Ro, averaged from several measurements is reported, because individual reflectance will vary somewhat with plant tissue type and with grain orientation under the microscope. Crude oil generation takes place for Rm values betw. 0.6% and 1.2%. Wet gas generation occurs mostly for Rm betw. 1.2% and 2%, and the zone of dry gas generation lies betw. Rm values of 2% and 4%

1.4.2-Paleothermometry: Rock Properties Analysis The minerals making up the source rock can also be used to determine paleotemperature. Some clays contain a high content of structurally bound water. This is particularly true of the swelling clays such as montmorillonite.As this clay is buried at increasing temperatures, it gradually dehydrates, loses its mixed layers and becomes more ordered. The systematic loss of expandable layers in swelling clays has been calibrated to temperature, by means of various X-ray diffraction techniques. Eventually, mixed layered clay and montmorillonite transform into other types of clay, mainly illite and chlorite. This takes place at about the optimum temperature of the oil window (80-120C)1.4.3 Paleothermometry: Comparison of MethodsIt is important to remember that unlike kerogen diagenesis, which is only affected by temperature and time, clay mineral diagenesis is affected by other factors, such as the chemistry of the pore waters. Therefore, calibration of paleothermometers based on clay diagenesis may ultimately prove less precise than kerogen-based methods.Although these paleothermometers are very different, they can be correlated to each other, to coal rank, and to the temperatures of oil and gas generation. A thorough correlation includes other maturation indicators too numerous to discuss here, such as fluorescence of exinite and electron spin resonance. Usually at least two different paleothermometry methods should be used to assess the maturity of a particular source rock.1.5-Oil ShaleSource rocks do not always reach the thermal maturity necessary to generate oil or gas, and so remain filled with kerogen. When they contain appreciable amounts of kerogen, these fine-grained rocks are often called oil shales. With these rocks, the oil is contained within the complex structure of the kerogen itself. This oil can be produced only by heating the oil shale in an inert atmosphere up to approximately 500C, a process known as pyrolysis. Pyrolysis can be thought of as instant maturation. The actual definition of an oil shale is any fine-grained sedimentary rock which yields oil during pyrolysis. However, the exact amount of organic material needed before a fine-grained organic rich rock can be classified as an oil shale is an arbitrary one. A cut-off value of 5% organic content by weight has been determined by economics.Oil shales primarily contain Type I or Type II kerogen. They occur in many places around the world, in rocks of many ages. They contain within them vast reserves. The world's oil shales have been estimated to contain some 4 trillion barrels of oil, only about 2% of which is recoverable using present-day technology. The world's largest and richest oil shale deposits include the Permian Irati shale of Brazil, the Cambrian-age deposits of northern Europe and Asia, and the Eocene-age Green River formation of the western United States. The Devonian shales of the eastern and central United States may also be classified in certain areas as a true oil shale but has been primarily exploited for its natural gas content.The Green River formation (Figure15) alone contains an estimated 2 trillion barrels of oil.

2 - HYDROCARBON MIGRATION PROCESSES2.1 - PRIMARY EVIDENCE FOR OIL MIGRATIONAccumulations in structural culminationsGushers Multiple reservoir horizons in single fieldsAccumulations under insufficient coverEvidence of former oil accumulations Visual evidence of upward oil movement2.2-MIGRATION DEFINITIONIn coarse-grained sediments, most organic matter was either winnowed away by wave and current-action, or destroyed in early diagenesis by deposit-feeders and bacterial oxidation. With the important exception of the oil shales, hydrocarbons found mainly in coarse-grained rocks. Migration is the the complex processes involved in moving oil and gas from its fine-grained source rocks to coarse-grained, permeable reservoir rocks. An important distinction, between primary and secondary migration, must be made, Fig.16 (the initial stage (I) and advance stage with formation of a petroleum accumulation (II)):- Primary migration is the first phase of the migration process; it involves expulsion of oil and gas from source rock into a carrier bed. - Secondary migration takes place within the porous reservoir rock, or from one reservoir rock to another.

2.3-MIGRATION PROCESSESIn coarse-grained sediments, most organic matter was either winnowed away by wave and current-action, or destroyed in early diagenesis by deposit-feeders and bacterial oxidation. With the important exception of the oil shales, hydrocarbons found mainly in coarse-grained rocks. 2.3.1 - PRIMARY MIGRATIONA - MECHANISMS OF PRIMARY MIGRATION:May truly be described as one of the last great mysteries of petroleum geology because of the small pore size within compacted shale and the low solubility of hydrocarbon in water.To day there are only three mechanism of primary migration that are serious consideration by most petroleum geologists: - Diffusion- Oil phase expulsion- Solution in gasThe first problem is the small pore size of the source rocks. Figure 17 shows that muds compact very quickly in early diagenesis. By the time shales have been buried to depths of 2 kilometers (about where oil generation takes place) pore diameters are reduced to about 50 angstroms. Getting petroleum through such small openings is not easy, no matter what mechanism is involved. The compaction of the shale can cause pressure buildups, however, and this can produce a network of microfractures with larger diameters than the pores. Although these micro fractures reseal upon the release of pressure, their presence has been reproduced experimentally (Lewan et. al., 1979) and has also been commonly revealed in lime muds by such techniques as cathode luminescence. Methane generation below depths of 3 or 4 kilometers can also increase pressure and cause microfracturing.

The second major problem of primary migration is the low solubility of hydrocarbons in water. Most models for primary migration involve aqueous processes, since the pores of shales are filled with water. If HC molecules could travel in true solution, we could easily deal with the problem of small pore sizes. However, Figure 18 shows the low solubility in water of two major groups of hydrocarbons, the paraffins or alkanes and the aromatics.

Similarly all hydrocarbons have low solubilities in water, and these solubilities decrease rapidly with increasing molecular size, as in Figure 18 Hydrocarbon solubility does increase exponentially with temperature but it is still fairly insignificant below a temperature of 200C. This is well above temperatures of the oil window. True solution could mainly be important in migration of some of the lighter aromatics, such as benzene, and the natural gas paraffins. Even with such low solubilities, commercial quantities of petroleum might still be obtained if large volumes of water could be squeezed out of the rock. In the early compaction of muds, however, pore water loss has largely been completed by the depths and temperature of the oil window. Therefore, any simple idea of oil and gas being squeezed out of the source rock, along with compaction water, is not really viable. However, there is another way to get oil and gas, along with water, out of shale. We may observe that some water attaches to the clay molecules themselves, particularly if the clay is swelling clay like montmorillonite. As a consequence, when montmorillonite-rich muds are buried.There are two phases of water emission -an early phase when pore water is given off, and a second quite distinct phase, when montmorillonite alters to illite Figure 19. The second phase commonly begins when temperatures are about 80C to 120C, which is right in the middle of the oil window. There does then appear to be an empirical relationship between clay dehydrating and petroleum formation in many situations. However, some shales that are source rocks are not made up of clays derived from montmorillonite, and these shales lack this second stage of water emission. There are also two ways that the solubility of hydrocarbon in water can be enhanced: through the formation of protopetroleum and through the formation of micelles. The first of these models suggests that it is not petroleum hydrocarbons that move out of the source rock, but more soluble NSO-containing percursors, such as acids and alcohol (Figure 20). These are often called protopetroleum. However, the abundance of these compounds in immature source rocks, is low. Furthermore, there are problems with getting the compounds back out of solution to form droplets in the carrier beds.

A second way to enhance solubility is to create micelles, in which polar organic molecules orient themselves with their water-seeking ends pointing outward into the pore fluid. Micelles can take either of two basic forms. They can be small spherical structures that incorporate hydrocarbons on their surface ( Figure 21 (a) ) or larger, cylindrical structures that accommodate hydrocarbons both in their interiors and on their surface ( Figure 21 (b) ). These micelle aggregates are basically colloidal-sized, acid soaps. The principles by which soaps are used to enhance oil solubility and increase production should be familiar to petroleum production engineers. However, micelles have been observed only in trace amounts naturally, in reservoir petroleum and in connate water. Furthermore most hydrocarbon micelles would be larger than 60 angstroms, too large to pass through the small pores of the shale source beds. DIFFUSIONDiffusion is the slow movement of material from an area high concentration or pressure to area of low concentration pressure.Diffusion has been shown to be active on at least a minor scale and over short distances.Diffusion is probably most effective immature rock, where preexisting high hydrocarbon bleed out rocks prior to the onset of significant generation and expulsion. OIL PHASE EXPULSIONThere appear to be three distinct ways in which oil phase expulsion can be occur:- One occur most commonly as a result of microfracturing induced by overpressure during hydrocarbon generation.- A second way in which oil phase expulsion can occur is from very organic rich rock prior to the onset of strong hydrocarbon generation. This early expulsion mechanism seems to be limited to rock having very high organic contents of liquids.- Finally, oil phase expulsion can take place when bitumen form continuous network that replaces water as the wetting agent in the source rock.SOURCES OF EXCESS PRESSURE IN SOURCE ROCKSDriving force for expulsion is P.Sources of excess pressure in source rocks:- Rapid sedimentation.- Aquathermal.- Hydrocarbon generation.- Mineral changes.- Capillary pressure.- Hydrocarbon bouyancy.Normal pressure are evidence for good ability to expel fluids. Overpressure indicates problems in expelling fluids. There are also two nonaqueous models should considered. The first model involves the explusion of high-pressured gas, which can carry oil molecules with it in solution. This mechanism would mainly occur in deeply buried rocks below the oil window, and it could be important only in condensate and very light oil migration. The second model involves migration through a continuous 3-dimensional organic network. Immature kerogen contains tiny dispersed droplets of petroleum. Under physical stresses, the bitumen could migrate through the kerogen network and out to carrier beds, without ever entering the pore water. This process may be important in black, organic-rich shales and some carbonates, where the kerogen is commonly dispersed as irregular clots and laminae. For example, this mechanism has been invoked to account for thick bitumen-filled dikes that are associated with the varved kerogen networks of the Green River oil shale (Jones, 1980). But in an average shale with only 1% total organic carbon, it is difficult to see how such a network could develop. It's likely that there is no single model that entirely accounts for migration of oil and gas out of the source rock. Primary migration probably involves several processes acting together and in sequence. It is likely that different mechanisms dominate under different geological conditions and at different stages of maturation. Protopetroleum expulsion may be a major mechanism in late diagenesis and early catagenesis. This may be followed by microfracturing, explusion of micelles and droplets, and formation of organic networks at burial conditions of the oil window. Finally, deeper burial and higher temperatures lead to high-pressured gas expulsion and true solution of light hydrocarbon molecules. Whatever mechanism is invoked, there is general agreement that primary migration occurs shortly after the petroleum is generated. SOLUTION IN GASThe third mechanism, expulsion of oil dissolved in gas, requires that there be a separate gas phase.Such a phase could only exist where the amount of gas far exceeded the amount of liquid hydrocarbon.Therefore, it would be expected only in the late stage of catagenesis or in source rock capable of generating mainly gas.B-DISTANCE AND DIRECTION IN PRIMARY MIGRATION In most cases the distances of primary migration are short (probably between 10cm and 100m). Primary migration ends whenever a permeable pathway is reached.Because the source rock is overpressure expulsion can be lateral, upward, or downward depending upon the carrier bed characteristics of the surrounding rocks. Thus a source rock lying between to sands will expel hydrocarbon into both carrier beds. 2.3.2 SECONDARY MIGRATIONSecondary migration is much better understood than primary migration. In secondary migration, petroleum occurs mainly as discrete oil droplets that migrate through a porous, permeable, water-wet conduit. Because pore diameters are large, even relatively large oil droplets can be accommodated.A-FACTORS CONTROLLING SECONDARY MIGRATION:Bouyance Capillary pressureHydrodynamic flowBouyanceWith buoyancy, oil droplets move upward through the carrier beds with a force dependent mainly on the density difference between the petroleum and the formation water. The process will continue until the droplet reaches a pore space that is smaller than its diameter. Capillary pressureFurther motion can occur only by deforming the droplet and squeezing it through the pore space. The force required to do this is called capillary pressure. Capillary pressure becomes higher as pore diameter decreases, until capillary pressure becomes so high that buoyancy forces cannot overcome it, and entrapment of the oil droplet takes place.Hydrodynamic flowSecondary migration will also be affected when the flow of subsurface waters creates hydrodynamic gradients. Upward hydrodynamic gradients assist flow by buoyancy (Figure21) Downward gradients oppose flow by buoyancy and can create hydrodynamic barriers to migration (Figure22).In some cases, these hydrodynamic barriers, either themselves or in combination with other factors, may produce traps.

UPWARD HYDRODYNAMIC GRADIENTS ASSIST FLOW BUOYANCE

DOWNWARD GRADIENTS OPPOSE FLOW BUOYANCE AND CAN CREATE HYDRODYNAMIC BARRIERS TO MIGRATION B-DISTANCE AND DIRECTION IN SECONDARY MIGRATION Secondary migration generally occurs along the layering of the carrier beds, and therefore lateral migration can take place over a wide range of distances. Short range migration is common where the reservoir is in close proximity to its source beds, for example in reefs on the flank of a deep, muddy basin or in shoestring sandstone bodies enclosed by their source shales. Movement within a confined carrier bed will be updip perpendicular to structural contours whenever possible. Migration may have to proceed at an oblique angle to structural contours where the faulting for facies changes create impassable barrier. Within a massive sandstone secondary migration will occur both laterally and vertically.Relatively small oil fields often have a local source and short migration distances. However, giant oil fields such as Hassi Messaoud, with probable reserves of 25 billion bbls (Balducchi and Pommier, 1970), generally require a very large drainage area and a large volume of source rock. To produce the huge Alberta tar sand deposits may have required secondary migration distances of up to 100 kilometers.Almost all lateral migrations also have a vertical component, usually upward. The dip of the carrier bed usually determines the extent of vertical movement, unless active faults and fracture systems provide a way for the oil to cut across layers. In some areas of severe faulting, for example the rift system of the Gulf of Suez, vertical oil migration is probably dominant.In searching for oil, it is also important to remember that the way the strata dip today can sometimes be misleading. The important thing is the dip of the carrier beds during the time of oil generation and migration. What is up-dip today may have been down-dip then.The nearest subcrop of Silurian shale is 40km away. The oil in Reservoir must have migrated long dist. Along the unconformity surface after the Mesozoic burial.GEOLOGIC CROSS SECTION IN THE HASSI MESSAUD FIELD