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CHAPTER ONE1.0 INTRODUCTIONTrap mechanism in hydrocarbon migration is fundamental in the analysis of a prospect and an important part in any successful oil and gas exploration or resource assessment program. A trap can be defined as any geometric arrangement of rock, regardless of origin, that permits significant accumulation of oil or gas, or both, in the subsurface. Although we define a trap as the geometric configuration that retains hydrocarbons several critical component must be in place for a trap to be effective, including adequate reservoir rocks and seals, and each of these must be addressed during trap evaluation. The oil and gas within a trap is part of the petroleum system, whereas the trap itself is part of one or more sedimentary basins and is evaluated as part of a prospect. The hydrocarbon-forming process and the trap-forming process occur as independent event and commonly at different types. The timing of the trap-forming process is important in a petroleum system study because if the trap forms before the hydrocarbon-forming process the evidence (oil and gas) that a petroleum system exist is preserved. The volume of oil and gas preserved depends on the type and the size of the trap, which is important in the evaluation of the prospect. The critical component of a trap (the reservoir, seal, and the geometric arrangement with each other) can be combined in variety of ways by a number of separate processes. Different authors have focused on various trap attributes as the key elements or elements of their classifications.

1.1 HYDROCARBON MIGRATIONHydrocarbon migration refers to the movement of petroleum from the source rock to the reservoir rocks. It is important to understand this process so that the direction of migration and trapping of petroleum can be predicted. Many different theories have been proposed in the past but it is now clear that petroleum is mainly transported as a separated phase and that the process is mainly driven by the buoyancy of petroleum relative to water. The solubility of oil in water is very low for most compounds. The solubility of oil in water is very low for most compounds. The solubility of gas, particularly methane, is much higher both in oil and water and increases with depth (pressure). There is however, also very limited flow in sedimentary basins to transport petroleum.

Figure 1.0: petroleum geology, (migration process in hydrocarbon migration) shanawaz mustafa

Figure 1.2: diagram illustrating the movement and accumulation of hydrocarbon (Kevin.T Bibble)

1.2 PRIMARY MIGRATIONPrimary migration is here defined as the movement of hydrocarbons (oil and natural gas) from mature organic-rich source rocks to an escape point where the oil and gas collect as droplets or stringers of continuous-phase liquid hydrocarbon and secondary migration can occur. The escape point from the source rock can be any point where hydrocarbons can begin to migrate as continuous-phase fluid through water-saturated porosity. The escape point then could be anywhere the source rock is adjacent to a reservoir rock, an open fault plane, or an open fracture. Secondary migration is the movement of hydrocarbons as a single continuous-phase fluid through water-saturated rocks, faults, or fractures and the concentration of the fluid in trapped accumulations of oil and gas. Numerous mechanisms for primary migration have been proposed. The main proposed mechanisms for secondary migration are buoyancy and hydrodynamics.The mechanisms of primary hydrocarbon migration and the timing of hydrocarbon expulsion have been debated by petroleum geologists since the beginning of the science. Mechanisms proposed for primary hydrocarbon migration include: solution in water, diffusion through water, dispersed droplets, soap micelles, continuous-phase migration through the water-saturated pores, and others. Early workers generally favored early expulsion of hydrocarbons with the water phase of compacting sediments, primary hydrocarbon migration, and secondary migration through reservoir carrier beds is the necessary next step for the formation of a commercial oil or gas accumulation. A thorough understanding of the mechanics of secondary hydrocarbon migration and entrapment is useful in the exploration for oil and gas. Knowledge in this area of exploration can be critical in tracing hydrocarbon migration routes, interpreting hydrocarbon shows, predicting vertical and lateral seal capacity, exploiting discovered fields, and in the general understanding of the distribution of hydrocarbons in the subsurface.1.3 SECONDARY MIGRATIONThe hydrocarbons expelled from a source bed next move through the wider pores of carrier beds (e.g., sandstones or carbonates) that are coarser-grained and more permeable. This movement is termedsecondary migration. The distinction between primary andsecondary migrationis based on pore size and rock type. In some cases, oil may migrate through such permeable carrier beds until it is trapped. If an oil droplet were expelled from a source rock whose boundary was the seafloor, oil would rise through seawater as a continuous-phase droplet because oil is less dense than water and the two fluids are immiscible. The rate of rise would depend on the density difference (buoyancy) between the oil and the water phase. The main driving force then for the upward movement of oil through sea water is buoyancy. Buoyancy is also the main driving force for oil or gas migrating through water-saturated rocks in the subsurface. In the subsurface, where oil must migrate through the pores of rock, there exists a resistant force to the migration of hydrocarbons that was not present in the simple example. The factors that determine the magnitude of this resistant force are (1) the radius of the pore throats of the rock, and (2) the hydrocarbon-water interfacial tension, and (3) wettability. These factors, in combination, are generally called "capillary pressure." Capillary pressure has been defined as the pressure difference between the oil phase and the water phase across a curved oil-water interface pointed out that capillary pressure between oil and water in rock pores is responsible for trapping oil and gas in the subsurface.

Figure 1.2 definition of primary and secondary migration (after tissot and welte).

1.4 DRIVING FORCES FOR HYDROCARBON MIGRATIONUnder hydrostatic conditions, buoyancy is the main driving force for continuous-phase secondary hydrocarbon migration. When two immiscible fluids (hydrocarbon and water) occur in a rock, a buoyant force is created owing to the density difference between the hydrocarbon phase and the water phase. The greater the density difference, the greater the buoyant force for a given length hydrocarbon column (always measured vertically). For a static continuous hydrocarbon column, the buoyant force increases vertically upward through the column.1.5 EFFECTS OF HYDRODYNAMICS ON DRIVING FORCESThe importance of hydrodynamics with regard to oil entrapment in structural traps has been discussed in detail by Hubbert (1953). Numerous other authors have since documented the effects of hydrodynamics on structural oil reservoirs throughout the world. In thinking of the effects of hydrodynamics on secondary migration and primarily stratigraphic-type entrapment of hydrocarbons, we must consider how a hydrodynamic condition would effect the buoyant driving force of a hydrocarbon filament in the subsurface. Hydrodynamic conditions in the subsurface change the buoyant force, and therefore the migration potential, for a hydrocarbon column of a given height. Buoyancy, as has been defined for a static oil filament, is the pressure in the water phase minus the pressure in the oil phase at a given height above the free water level. When a hydrodynamic condition exists, the pressure in the water phase (and therefore the buoyant force) at any point will be different from that for hydrostatic conditions.

1.6.0 RESISTANT FORCES TO SECONDARY MIGRATIONIn a previous example we discussed how a filament of oil released at the seafloor would rise through seawater because of the force of buoyancy. If the same filament of oil or gas is required to move through a water-saturated porous rock we have introduced a resistant force to hydrocarbon movement. For the hydrocarbon filament or globule to move through a rock, work is required to squeeze the hydrocarbon filament through the pores of the rock. In more technical terms, the surface area of the hydrocarbon filament must be increased to the point that it will pass through the previously water-saturated pore throats of the rock. The magnitude of this resistant force in any hydrocarbon-water-rock system then is determined by the radius of the pore throats of the rock; the hydrocarbon-water interfacial tension (surface energy); and wettability as expressed by the contact angle of hydrocarbon and water against the solid pore walls as measured through the water phase. This resistant force to migration is generally termed "capillary pressure."For a simplified example, visualize a hydrocarbon filament trying to move upward through a water-saturated cylindrical pore .The variables of the resistant force to hydrocarbon movement can be expressed by a simple equation (Purcell, 1949):

Where Pd = hydrocarbon-water displacement pressure (dynes/cm2);= interfacial tension (dynes/cm);= wettability, expressed by the contact angle of hydrocarbon and water against the solid (degrees); and R = radius of largest connected pore throats (cm). The displacement pressure is that force required displacing water from the cylindrical pore and forcing the oil filament through the pore.

1.6.1 INTERFACIAL TENSIONInterfacial tension can be defined as the work required enlarging by unit area the interface between two immiscible fluids (e.g., oil and water). Interfacial tension is the result of the difference between the mutual attraction of like molecules within each fluid and the attraction of dissimilar molecules across the interface of the fluids.Oil-water interfacial tension varies as a function of the chemical composition of the oil, amount and type of surface-active agents, types and quantities of gas in solution, pH of the water, temperature, and pressure. At atmospheric pressure and 70F, interfacial tension of crude oils and associated formation water for 34 Texas oil reservoirs of different ages ranged from 13.6 to 34.3 dynes/cm, with a mean of 21 dynes/cm (Livingston, 1938). Oil-water interfacial tension generally tends to decrease with increasing API gravity and decreasing viscosity (Livingston, 1938).With increasing temperature, oil-water interfacial tension generally decreases. For pure benzene-water and decane-water systems, interfacial tension decreases between 0.03 to 0.08 dynes/cm/F (Michaels and Hauser, 1950) depending on the pressure.In attempting to quantify oil-water-rock displacement pressure, a value for oil-water interfacial tension in the subsurface must be measured or estimated. Sophisticated laboratory equipment can measure oil-water interfacial tension at reservoir temperature and pressure. If this equipment is not available, interfacial tension can generally be measured at atmospheric conditions in most chemical laboratories. The results of atmospheric interfacial tension measurements must be extrapolated to subsurface temperature and pressure. If no laboratory data are available for the oil-water system in question, then an estimate must be made. Livingston's mean value for 34 Texas crude oils of 21 dynes/cm at 70F is the best value for medium-density crude oils (30 to 40 API). A value of approximately 15 dynes/cm may be appropriate for higher gravity crude oils (greater than 40 API) with 30 dynes/cm being a reasonable approximation for low-gravity crude oils (less than 30 API). These estimates or measurements at atmospheric temperature (70F) must be extrapolated to reservoir temperature. It is suggested that the oil-water interfacial tension value at 70F be decreased 0.1 dynes/cm/F temperature increase above 70F.

1.6.2 WETTABILITYWettability can be defined as the work necessary to separate a wetting fluid from a solid. In the subsurface we would generally consider water the wetting fluid and the solid would be grains of quartz in sandstone, calcite in a limestone, etc. The adhesive force or attraction of the wetting fluid to the solid in any oil-water-rock system is the result of the combined interfacial energy of the oil-water, oil-rock, and water-rock surfaces. Wettability is generally expressed mathematically by the contact angle of the oil-water interface against the rock or pore wall as measured through the water phase. For rock-fluid systems with contact angles between 0 and 90, the rocks are generally considered water-wet; for contact angles greater than 90, the rocks are considered oil-wet. Water-wet rocks would imbibe water preferentially to oil. Oil-wet rocks or oil-wet surfaces would imbibe oil preferentially to water. Although a contact angle of 90 has generally been considered the break over point to an oil-wet surface, Morrow et al (1973) stated that a contact angle of greater than 140 in dolomite laboratory packs was necessary for oil to be imbibed. Water-laid sedimentary rocks are generally considered to be preferentially water-wet owing to the strong attraction of water to rock surfaces and the initial exposure of pore surfaces to water rather than hydrocarbons during sedimentation and early diagenesis. Water is thought by many workers to be a perfect wetting fluid and a thin film of water would coat all grain surfaces. If this is the situation, the contact angle for oil-water-rock systems would be zero. The wettability term in the displacement pressure equation would then be unity, as the cosine of zero is one. If water is not a perfect wetting fluid and the oil-water contact angle is greater than zero, the displacement pressure should theoretically decrease for that oil-water rock system. L. J. M. Smits (1971, personal commun.) has done experimental work on identical size bead packs which suggests that displacement pressures are only slightly affected by changing the oil-water-solid contact angle from 0 to 85. Similar results were obtained by Morrow et al (1973) on displacement pressure tests in dolomite packs with contact angles ranging from 0 to 140. These data and the general assumption that most rocks are preferentially water-wet suggest that the wettability term in the displacement pressure equation can be considered unity.

If the rocks are partially oil-wet, then the wettability term can be significant in reducing displacement pressure from that for the water-wet case. In the subsurface, rocks are seldom completely oil-wet but are fractionally oil-wet, that is, some of the grain surfaces are oil-wet and some are water-wet. According to Salathiel (1972), this would most likely occur in reservoir rocks where oil has been trapped and the grain surfaces in the larger pores would be exposed to the surface-active molecules in the oil phase and form an oil film or coating on the grain, making it preferentially oil-wet. The pore surfaces at the smaller pores or in the corners of the larger pores that are not saturated with oil would remain water-wet. Fatt and Klikoff (1959) have determined that when a rock is partially oil-wet there is a reduction in the oil-water displacement pressure for that oil-water-rock system. They suggested that the degree of fractional wettability needed to significantly reduce displacement pressure from that for the water-wet case is greater than 25% oil-wet grain surfaces.

Figure 1.3 driving forces on hydrocarbon migration wikipedea(2009)

CHAPTER TWOHYDROCARBON TRAPS2.0 HYDROCARBON TRAPSA trap is a geologic structure or a stratigraphic feature capable of retaining hydrocarbons. Hydrocarbon traps that result from changes in rock type or pinch-outs, unconformities, or other sedimentary features such as reefs or buildups are calledstratigraphic traps. Hydrocarbon traps that form in geologic structures such as folds and faults are called structural traps. Any mixture of structural and stratigraphic elements is called a combination trap.2.1 STRUCTURAL TRAPSStructural traps are created by syn-to post depositional deformation of strata into a geometry (a structure) that permits the accumulation of hydrocarbons in the subsurface. The resulting structures involving the reservoir, and usually the seal intervals, are dominated by either folds, faults, piercements, or any combination of the foregoing. Traps formed by gently dipping strata beneath an erosional unconformity are commonly excluded from the structural category, although as sub unconformity deformation increases these distinction becomes ambiguous. Super posed multiple deformations may also blur the forgoing distinctions. Subdivisions of structural traps have been proposed by many authors based on a variety of schemes, example of these are fault dominated traps and fold dominated traps.

2.1.1 FOLD DOMINATED TRAPSStructural traps that are dominated by folds at the reservoir-seal level exhibit a wide variety of geometries and are formed or modified by a number of significantly different syn-and post depositional deformation mechanisms. Although usually considered to result from tectonically induced deformation the term fold is purely descriptive and refers to curved or non planer arrangements of geologic (usually bedding) surfaces. Therefore, folds include not only tectonically induced phenomena but also primary depositional features, gravity-induced slumping, compaction effect etc. it is convenient to divide prospect-scale folds into two categories those that are directly fault related and those that are largely fault free.Most fault related folds result from bending above non planar fault surface. Crystalline basement may or may not be involved, and strata shortening, extension, or transcurrent movements may have occurred. Common examples are fault bend folds and fault propagation folds in detached fold and thrust belts. Fault bend folds are also common in extensional Terranes. Other faulted related folds include drag fold, or fold formed by frictional forces acting across a fault, and drape folds, those formed by flexure above a buried fault along which there has been renewed movement. These latter folds however are not caused by slip over a nonplanar fault surface. Also, drape folds do not involve significant strata shortening or extension at the reservoir level. Fault free, or lift off folds result from buckling caused by strata shortening above a docollement, usually within a thick or very efficient sequence of evaporates or shale. Kink bands and chevron folds are special types of fault free folds. Other type of fault free folds may form by bending above material that moves vertically or horizontally by flow without significant strata shortening or extension at the reservoir seal interval.

Figure 2.1: diagram illustrating fault dominated trap (Kevin.T Bibble)

2.1.2 FAULT DOMINATED TRAPAs already pointed out, faults can be extremely important to the viability of a trap by providing either seals or leak points. They are capable of acting as top, lateral, or base seals by juxtaposing relatively permeable rock units against more permeable reservoir units or by acting as seals surfaces due to impermeable nature of the material along the faults. In addition, they may act as leak points by juxtaposing of permeable units or by creation of a fracture network. The term fault is descriptive in that it refers to a surface across which they have been displacement without reference to the cause of that reference (either, whether it is tectonically, gravitationally, diagenetically or otherwise induced). Structural traps that are dominated by faults at the reservoir - the seal level (the fault itself makes the trap by sealing the reservoir without an ancillary fold) can be divided into three categories based on the types of separation, or slip if it is known that geologic surface exhibit across the fault. These are normal, reverse, and strike separation or slip fault trap.

2.2 NORMAL FAULT Normal traps are the most common fault dominated structural traps. They are of two fundamentally different geometries and are most common in two different tectonostratigraphic setting. Normal fault involving the basement occur in areas of significant crustal extension, such as the gulf of cuez and the North Sea, and are characterize by tilted fault block that exhibit a zigzag map pattern. Probably the most important trap geometry is the trap door closure at fault intersection. Syn-and post depositional normal fault that are detached from the basement occur in area of rapid subsidence and sedimentation, commonly on passive continental margins, such as the USA, gulf coast, Niger-Delta and are characterized by a listric profile and a cuspate map pattern that is usually concave basinward. On the downthrown side of major displacement normal fault in these setting smaller synthetic and antithetic fault dominated trap are typically keystone normal fault dominated traps above deep seated salt intrusions are also common.

2.3 REVERSE FAULT Reverse fault traps may be associated with detached or basement involved thrust (No angle or high angle reverse faults.) these structures tend not to produce pure fault dominated traps because of attendant folding. In this position, the hanging wall moved up relative to the foot wall, indicating reverse fault activity. The picture shows that the central hanging wall was pushed up relative to the foot wall. Most of the faults in the Rocky Mountains are reverse fault.

Figure 2.3: types of traps in which folding dominate the reservoir-seal interval. Fault related traps include (A) fault bend (B) fault propogation, (C) fault grab (D) fault drape. Fault free types include (E) lift off, (F) chevron/king band, (G) diaper, and (H) differential compaction2.4 STRATIGRAPHIC TRAPIn 1936 levorsen proposed the term stratigraphic features in which a variation in stratigraphy is the chief confining element in the reservoir which traps the oil. The existence of such non structural trap has been recognized atleast the late 1800. Today we would define a stratigraphic trap as one which the requisite geometry and reservoir- seals combination where formed by any variation in the stratigraphy that is independent of structural deformation except for regional tilting. Many attempts have been made to classify types of stratigraphic traps. Early efforts, while not specifically using the term stratigraphic, lead to broad categories of traps that where close because of varying porosity within rocks later works recognized that considerable variability exist among such trap, and subdivision became more numerous. A number of treatments of stratigraphic traps provide information on different approaches to classification and supply abundant, we generally follow Ritten-House, (1972) and divide stratigraphic traps into primary and depositional stratigraphic trap, stratigraphic traps associated with unconformities, and secondary stratigraphic traps.Figure 2.4: types of traps in which faulting dominate the reservoir-seal interval. (A) Basement involved normal fault trap and trap. (B) Synthetic detached listric normal fault traps (C) two types of reverse fault traps. (D) strike-slip traps

2.4.1 PRIMARY OR DEPOSITIONAL STRATIGRAPHIC TRAPPrimary or depositional stratigraphic traps are created by changes in contemporaneous deposition. As described here such traps are not associated with significant unconformity two general classes of primary stratigraphic traps can be recognized: those formed by lateral depositional changes, such as facies changes and depositional pinchouts, and those created by buried depositional relief.Facies changes may juxtapose potential reservoir rocks and impermeable seal rocks over relatively short lateral distance in either siliciclastic or carbonate settings. The lateral transition from reservoir to seal is generally gradational, leading to possible non economic segment within the reservoir. Particular care must be taken to identify strike closure in this type of trap. Deposional pinchouts may lead to reservoir and seal combination that can trap hydrocarbon. The transition from reservoir to lateral seal may be abrupt, in contrast to facies change traps. Strike closure is also a risk for pinchouts traps.Both lateral facies change and depositional pinchouts traps generally require a component of regional dip to the effective. Both types are common elements of combination structural-stratigraphic traps, particularly if the structure was growing during deposition of the reservoir and seal rocksThe general second general class of primary stratigraphic traps is associated with buried depositional relief. These traps are equivalent to the constructive paleogeomorphic traps of Martin (1966). Carbonate reefs provide a classic example of potential traps associated with buried depositional relief. Reef growth with time enhances depositional relief, and the transition from tight lagoonal rocks to porous and permeable backreef-reef-fore reef rock may provide a good reservoir-lateral seal combination. The relationship between the forereef rocks and adjacent basinal deposits (potential source rocks) can create excellent migration partway. Formation of a top seal requires that reef growth is terminated and that the reef is very buried beneath the trap with low permeability material. A key risk for this type of trap is accurate prediction of porosity and permeability with the reef complex. The Devonian reef fields of the western Canada sedimentary basin are excellent example of this type of trap. Another type of buried depositional relief is associated with some submarine fan deposit. In such depositional settings sand- ridge depositional lobes may be encased in shale.

Figure 2.5 primary or Deposional stratigraphic traps. (A) Traps created by lateral changes in sedimentary rock type during deposition. (B) traps formed by buried Deposional relief.

2.4.2 SECONDARY STRATIGRAPHIC TRAPSAnother major category of stratigraphic traps results from post depositional alteration of strata. Such alteration may either create reservoir quality rocks non reservoir or create seals from former reservoir. Although the example used is taken from a carbonate setting, similar digenetic plugging can occur in just about any rock type under the proper circumstances. Porosity occlusion is not limited to only digenetic mineral cements. Asphalt, permafrost, and gas hydrates are other possible agents that may form seals for these types of stratigraphic traps. Unfortunately it is often difficult to predict position of the cementation boundaries in the subsurface before drilling, and this type of trap can be a challenging exploration target.The second type of secondary stratigraphic traps is associated with porosity enhancement that improves reservoir quality in otherwise tight sections.Dolomization of limited permeability limestones is a good example. Dissolution of framework or material is another porosity and permeability enhancement mechanism. Porosity enhancement associated with dolomization and dissolution potentially can create traps on its own. Commonly, though, porosity enhancement is associated with other types of traps as a modifying element.

Figure 2.6: secondary digenetic stratigraphic traps. (A) Traps created by post depositional up dip porosity occlusion. (B) Traps created by post depositional porosity and permeability enhancement 2.5 COMBINATION TRAPMany of worlds hydrocarbon traps are not simple features but instead combine both structural and stratigraphic elements. Levorsen recognized this in his 1967 classification of trap he noted that every a complete gradation exist between structural and stratigraphic end members and that discovered traps illustrates almost imaginable combination of structure and stratigraphy. Levorsen restricted the use of the term combination trap to features in which neither the structural nor the stratigraphic element alone forms the traps but both are essential to it. Many people now use the term combination trap in a less rigorous way and apply it to any trap that has both structural and stratigraphic element, regardless of whether both are required for the trap to be viable strict adherence to the definitions does not necessarily find hydrocarbon, both early recognition of stratigraphic complication associated with structural traps or structural modification of dominantly stratigraphic trap can help eliminate exploration or development suprises. An explanation that is commonly proposed for these observations is that reservoir conditions are hydrodynamic rather than hydrostatic. In general, dips of oil water contacts seldom exceed a few degrees, but higher dips have been reported up to 10 degrees, if the dip(tilt) of the oil water contact exceeds the trap flanks, the trap will be flushed (generally, if trap flank dips exceed 5 degrees, there is little risk of flushing). Therefore, in the evaluation of structural traps with relationship gently dipping flanks, consideration should be given to hydrodynamic conditions, it is important to note that tilted oil water contacts may be related to phenomena other than hydrodynamics (e.g), variation in reservoir characteristics and geotectonic), and that present day hydrodynamic condition may not reflect those in the past.It is possible to calculate the theoretical change in trap capacity and therefore the risk associated with trap capacity and therefore the risk associated with trap flushing in a strongly hydrodynamic situation. Hubbert (1953) showed that the tilt of the oil water contact is the direction of flow is a function of the hydraulic gradient and the densities of both hydrocarbons and water .the lower the oil density and greater the water flow, the more easily the oil density and greater the water flow, the more easily the oil is displaced.Figure 2.7: combination traps. (A) Intersection of a fault with an updip depositional edge of porous and permeable section (B) folding of an updip depositional pinchouts of reservoir section.

2.6 HYDRODYNAMIC TRAPSExplorationists have known since about mid-century that oil-water contacts in many hydrocarbons-bearing traps are tilted. In other cases, traps that have no static closure contain hydrocarbons, and traps that do not have static closure and should reasonably contain hydrocarbons do not. An explanation that is commonly proposed for these observations is that reservoir conditions are hydrodynamic rather than hydrostatic. In general, dips of oil-water contacts seldom exceed a few degrees, but higher dips have been reported. If the dip (tilt) of the oil water contact exceeds the dip of the trap flanks, the trap will be flushed (generally, if trap flank dips exceeds 50 , there is little risk of flushing). Therefore, in the evaluation of structural traps with relatively gently dipping flanks, considering should be given to hydrodynamic conditions. It is important to note that tilted oil water contact may be related to phenomena other than hydrodynamics (e.g., variations in reservoir characteristics and neotectonics), and that present day hydrodynamic conditions may not reflect those in the past. It is possible to calculate the theoretical change in trap capacity and therefore the risk associated with trap flushing in a strongly hydrodynamic situation. Hubbert (1953) showed that the tilt of the oil water contact in the direction of flow is a function of the hydraulic gradient and the densities of both hydrocarbons and water. The lower the oil density and greater the water flow, the more easily the oil is displaced.

Figure 2.8: (A) Generalized hydrostatic trap. (B) Generalized hydrodynamic trap. (C) Hydrodynamic traps with increased water flow or oil density. (D) Hydrodynamic trap without static closure created by down dip water flow. (E) Same situation as in (D) but with updip water flow. (F) Tilted oil-water contact in fold dominated trap with down dip water movement. (G)Tilted oil-water contact in fold dominated trap with updip water movement.

CHAPTER THREECOMPONENT OF A TRAP3.0 TWO CRITICAL COMPONENTS OF TRAPTo be a viable trap, a subsurface feature must be capable of receiving hydrocarbons and storing them for some significant length of time. This requires two fundamental components: a reservoir rock in which to store the hydrocarbons, and seal (or set of seals) to keep the hydrocarbon from migrating out of the trap. We do not consider the presence of hydrocarbons to be critical component of a trap, although this is certainly a requirement for economic success. The absence of hydrocarbons may be the result of failure of other play or prospect parameters, such as the lack of a pod of active source rock or migration conduits, and it may have nothing to do with the ability of an individual feature to act as a trap. 3.1 RESERVIORThe reservoir within a trap provides the storage space for the hydrocarbons. This requires adequate porosity within the reservoir interval). The porosity can be primary (depositional), secondary (digenetic), or fractures, but it must supply enough volume to accommodate a significant amount of fluids. The reservoir must also be capable of transmitting and exchanging fluids. This requires sufficient effective permeability within the reservoir interval and also along the migration conduit that connects the reservoir with a pod of active source rock. Because most traps are initially water filled, the reservoir rock must be capable exchanging fluids as the original formation water is displaced by hydrocarbons, traps are not passive receivers of fluids into otherwise empty space; they are focal points of active fluid exchange.A trap that contains only one homogenous reservoir rock is rare. Individual reservoir commonly include lateral/or vertical variation in porosity and permeability. Such variation can be caused either by primary depositional processes or by secondary digenetic or deformational effects and can lead to hydrocarbon saturation but non productive waste zones within a trap. Variation in porosity and, more importantly, permeability can also create transition that occurs over some distance between the reservoir and the major seals of a trap. This interval may contain significant amount of hydrocarbons that are difficult to produce effectively. Such intervals should be viewed as uneconomic parts of the reservoir and not part of the seal. Otherwise, trap spill points may be mis-identified. Many traps contain several discrete reservoir rocks with interbedded impermeable units that form internal seals and segment hydrocarbon accumulations into separate compartments with separate gas-oil-water contacts and different pressure distributions.

Figure 3.0: common trap limitations. (A) Waste or non productive zones in trap. (B) Multiple impermeable layers in trap creating several individual oil-water contacts (C) Non-to poorly productive transition zone. (D) Lateral transition from reservoir to seal. (E) Lateral stratigraphically controlled leak point. (F) lateral leak point or thief bed.

3.2 SEALThe seal is equally critical component of a trap, without effective seals, hydrocarbons will migrate out of the reservoir rock with time and the trap will lack viability. Most effective seals for hydrocarbon accumulations are formed by relatively thick; laterally continuous, ductile rocks with high capillary entry pressure, but other types of seals may be important parts of individual traps (e.g. Fault zone material, volcanic rock, asphalt, and permafrost). All traps require some form of top seal when the base of the top seal is convex upward in three dimensions, the contours drawn to represent this surface (called the sealing surface by Downey, 1984) close to map view. If these are the case, no other seal is necessary to form an adequate trap. In fact some authors have used the basic convex or non convex geometry of sealing surface as a way of classifying traps.Many traps are more complicated and require that, in addition to a top seal, other effective seals must be present. Lateral seals impede hydrocarbon movement from the sides of a trap and are a common element of successful stratigraphic traps. Facie changes from porous and permeable rocks to rocks with higher capillary entry pressures can form lateral seals, as can lateral digenetic changes from reservoir to tight rocks. Other lateral seals are created by the juxtaposition of dissimilar rock types across erosional or depositional boundaries. Traps in incised valley complexes commonly rely on this type of lateral seal. Stratigraphic variability in lateral seals poses a risk of leakage and trap limitation. Even thinly interbedded intervals of porous and permeable rock (thief beds) in a potential lateral seal can destroy an otherwise viable trap. Base seals are present in many traps and most commonly stratigraphic in nature. The presence or absence of an adequate base seal is not a general trap requirement, but it can play an important role in deciding how a field will be developed. Faults can be important in providing seals for trap, and fault leak is a common trap limitation. Fault can create or modify seals by juxtaposing dissimilar rock types across the fault, by smearing or dragging less permeable material into the fault zone, by performing a less permeable gouge because of differential sorting and cataclasis, or by preferential digenesis along the fault, fault induced leakage may result from juxtaposing of porous and permeable rocks across the fault or by formation of a fracture network along the fault itself.

Figure 3.1: diagram illustrating positions of seal in a hydrocarbon system.

CHAPTER FOURPOROSITY AND PERMEABILTY4.0 INTRODUCTION TO POROSITY AND PERMEABILITYHydrocarbon accumulations can occur only if all essential elements (source rock, reservoir rock, seal rock, and overburden rock) and processes (generation-migration-accumulation of petroleum and trap formation) have operated adequately and in the proper timespace framework. Absence or inadequacy of even one of the elements or processes eliminates any chance of economic success. Thus, sandstone reservoir parameters (reservoir size, porosity, and permeability) are among the geologic controls that have to be included in the consideration of risk factors for plays and prospects. The importance of accurate pre-drill assessments, including reservoir quality, is growing as oil and natural gas companies are increasingly exploring deeper targets. The proportion of undeveloped, deep reservoirs was even higher for gas fields. The trend toward greater producing depths has not been limited to the North Sea. Anomalously high porosities and permeabilities in deeply buried sandstones can extend the economic basement and provide critical support for commercial production. Four known major causes of anomalously high porosity in sandstones are as follows: (1) grain coats and grain rims (effective only in detrital-quartzrich sandstones), (2) early emplacement of hydrocarbons, (3) shallow development of fluid overpressure, and (4) secondary porosity. Although these phenomena are generally known to geologists, misconceptions exist regarding their occurrence and effectiveness. In this article, we discuss quantification and predictability of anomalous porosity as the result of the first three causes. 4.1 POROSITYPorosity refers to the percentage of total volume of a material that is occupied by voids or air spaces that exist between the rock grains. The more porous a material is, the greater the amount of open space, or voids, it contains. Stored in these voids are liquids and gases. Porosity differs from one material to another. Unconsolidated deposits of clay have the greatest porosities because of their crystallographic structure; they are comprised of parallel sheets of clay minerals. Unconsolidated deposits of sand have lower porosities because of the nature of the sand grains to each other. Source rocks have high porosities; the best source materials are clays & shales, but these same materials make poor reservoir rocks. Porosity of a rock is a measure of its ability to hold a fluid. Mathematically, porosity is the open space in a rock divided by the total rock volume (solid + space or holes). Porosity is normally expressed as a pecentage of the total rock which is taken up by pore space. For example, a sandstone may have 8% porosity. This means 92 percent is solid rock and 8 percent is open space containing oil, gas, or water. Eight percent is about the minimum porosity that is required to make a decentoil well, though many poorer (and often non-economic) wells are completed with less porosity. Even though sandstone is hard, and appears very solid, it is really very much like a sponge (a very hard, incompressible sponge). Between the grains of sand, enough space exists to trap fluids like oil or natural gas! The holes in sandstone are called porosity (from the word porous). Here is a very thin slice (thinner than a human hair) of actual sandstone as seen through a microscope. The larger brown and yellow pieces are grains of quartz, an extremely common mineral. Between the grains, you can see the porosity in the rock.If you take a piece of sandstone and pour water on it, you will see the water is absorbed right into the rock. The water is soaked into the porosity.The porosity is shown as black in the drawing on the right. Oil or gas will fill these holes in the rock. Notice that the more spherical the grains are, the more space or porosity is left between them. Hence, well-rounded sandstone will have more porosity than a poorly-routed one! A geologist loves to encounter well-rounded sandstone, because they hold the most oil and gas of any of the clastic rocks.4.2 PERMEABILITYPermeability (measured in centimeters per second) refers to the ability of a material to transmit [fluid or gas]. The rate at which a material will transmit a fluid or gas depends upon total porosity, number of interconnections between voids, and size of interconnections between voids. For example, although clay has a higher porosity than sand (clay has a greater number of voids), the voids that make up the clay are not interconnected and therefore cannot transmit the fluid or gas out of it. The permeability of a typical clay in Louisiana would be 1 x 10-7cm/sec, or a movement of about 3 feet in 30 years. Therefore movement of a fluid or gas out of clay is very difficult. Sand on the other hand has a typical permeability of 1 x 10-5cm/sec, or a movement of about 300 feet in 30 years. Therefore sand has greater permeability than clay. The permeability of a rock is a measure of the resistance to the flow of a fluid through a rock. If it takes alotof pressure to squeeze fluid through a rock, that rock has low permeability or low perm. If fluid passes through the rockeasily, it has high permeability, or high perm.Table 1.0: diagram illustrating permeability chart for typical sediments.

Permeability in petroleum-producing rocks is usually expressed in units calledmillidarcys(one millidarcy is 1/1000 of a darcy). Most oil and gas reservoirs produce from rocks that have ten to several hundred millidarcys. One darcy (1000 millidarcys) is a huge amount of permeability!In the last 10 years, an increasing amount of US gas production is coming from shale gas wells. Shale has a lot of porosity (much more than sandstone), butextremely low permeability. That means shale has historically been a poor producer of hydrocarbons. While gas has been produced from shales for over a hundred years, quantities were small. Two things have changed the situation, allowing for increased shale gas development. These concepts have allowed petroleum companies to artificially induce more permeability into shale gas rocks:

CHAPTER FIVESUMMARY AND CONCLUSIONWe have defined a trap as any geometric arrangement of rock that permits significant accumulation of hydrocarbons in the subsurface. We do not consider the presence of hydrocarbons in economic accounts to be a critical element of a trap. The absence of oil or gas in a subsurface feature can be the result of failure or absence of other essential elements or processes of a petroleum system and may have nothing to do with the viability of a trap. Although we use the geometric arrangement of key elements to define a trap, trap evaluation must include much more than just mapping the configuration of those elements. Reservoir and seal characteristics are so important to trap viability that their evaluation must be an integral part of any trap study. Traps can be classified as structural, stratigraphic, or combination trap, in addition, hydrodynamic flow can modify traps and perhaps lead to hydrocarbon accumulations where no conventional traps exist, as more and more of the worlds hydrocarbon provinces reach mature stages of exploration, such traps may provide some of the best opportunities for future discoveries.