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  • 1. Chapter 7 Migration of Petroleum by Martin D. Matthews
  • 2. Martin D. Matthews “Matt” Matthews is a consultant, retired, from Texaco’s International Exploration Department and is currently an adjunct professor at Rice University. He holds degrees in geology from Allegheny College (BS), West Virginia University (MS), and Northwestern University (PhD). Matthews has worked in surface and subsurface geochemistry, remote sensing, diagenesis, fractures, fluid flow, basin modeling, depositional systems, and global cyclostratigraphy. Prior to his work at Texaco International, he was a senior scientist for Texaco Exploration and Production Research and held a variety of positions with Gulf R&D Co., including manager of geochemical research and director of geological research. Matthews has also been a professor at Washington State University, has served on the Earth Science Advisory Board at Savannah River Laboratory, and was the director of oil and gas test sites for the Geosat–NASA Test Case study panel. He is listed in Who’s Who in Frontiers of Science & Technology, Who’s Who in Optical Science and Engineering, American Men and Women of Science, and Who’s Who in Technology Today.
  • 3. Overview Introduction Migration of hydrocarbons is a little-understood but critical process of the petroleum system. This chapter attempts to address the following questions: • How does oil escape from the source rock? • Does oil migrate out of the trap? • Why are there marked differences in oil gravity, wax content, and sulfur content in lateral and stratigraphically successive sands? • Why are there differences in water salinity for multiple sands in one structural trap? • What is the role of faults in transporting and trapping hydrocarbons? • Why are there barren sands within sequences of productive sands? • How is cross-formational flow of hydrocarbons accomplished? • Does the form change during migration and, if so, which form is dominant under what conditions? • How can we estimate the timing, volumes, and compositions of transported hydrocarbons? In this chapter This chapter contains the following sections. Section Topic Page A Migration Concepts 7–4 B Mechanisms of Migration 7–12 C Changes in Hydrocarbon Composition During Migration 7–18 D Migration Pathways 7–22 E Calculating Migration Rate and Charge Volume 7–29 F References 7–37 Overview • 7-3
  • 4. Section A Migration Concepts Summary of principles The principles of hydrocarbon migration, discussed in this section, can be summarized as follows: • Hydrocarbons migrate as a separate phase, primarily due to buoyancy. This force causes them to move vertically at geologically rapid rates. • Lithologic layers slow or restrict the vertical movement of hydrocarbons. Seals deflect the hydrocarbons laterally updip through underlying beds to a trap or spill point. Lateral migration is also facilitated by meteoric groundwater flow. Flow rates for compaction-driven water generally are too slow to significantly affect hydrocarbon flow. • The properties of reservoirs and carrier beds (dip, relative permeability, etc.) control the rate of migration and thus the specific direction of the bulk of hydrocarbons under seals. The broad principles of migration are reviewed in detail in this section. In this section This section contains the following topics. Topic Page Migration Basics 7–5 Factors That Cause Migration 7–6 Factors That Oppose Hydrocarbon Migration 7–9 7-4 • Migration of Petroleum
  • 5. Migration Basics Introduction Less is known about migration than any other process involved in the accumulation of hydrocarbons in the subsurface. It is generally described as that unknown process or group of processes that enable petroleum to move from a source to a reservoir. Observations of migration Hydrocarbon migration has been observed only rarely and indirectly in the natural environment under atypical conditions. Observation is difficult because it occurs either too rapidly, too slowly, or elsewhere. As such, migration is generally inferred rather than demonstrated. Conclusions about migration are based on snapshots in reservoir and source-rock systems. Laboratory migration experiments are limited in their applications by the time frame and the ability to reproduce subsurface conditions. Migration studies The movement of hydrocarbons through an entire stratigraphic section is generally ignored. Geochemists usually focus on migration out of source rocks, and reservoir engineers usually study migration within carrier beds (reservoir-quality rocks). Little is known, though much is inferred, about cross-facies flow required when source rocks and reservoir-quality rocks are not adjacent to one another. Migration constraints Physical conditions constraining migration through stratigraphic sections are pressure, temperature, permeability, capillarity, surface tension, molecular size, and density. The main chemical constraint is solubility of migrating hydrocarbons. Chemistry of migrated hydrocarbons Detailed chemical correlations made of reservoired hydrocarbons with source rocks strongly indicate that the migration process does not significantly affect the overall geochemistry of the migrated hydrocarbons. However, general differences exist between the chemical composition of oils and the source rocks to which they are chemically correlated. These differences must be explained. How we observe migration Materials trapped in diagenetic overgrowths offer snapshots of the migration process. Studies of these materials by microanalytical techniques such as fluid inclusion analysis, microfluorescence, and cathodoluminescence offer potential for great advances in our understanding of the migration process and our ability to recognize and perhaps predict migration pathways and timing. Migration stages Hydrocarbon migration consists of four stages: primary, secondary, tertiary, and remigration. The list below contains their definitions. • Primary Migration—The process of loss of hydrocarbons from the source rock. • Secondary Migration—Migration from source to reservoir along a simple or complex carrier system. Includes migration within the reservoir rock itself. • Tertiary Migration—Migration to the surface, either from a reservoir or source rock. Also called dismigration. • Remigration—Migration from one reservoir position through an intervening section into another reservoir position in the same or a different reservoir. Migration Concepts • 7-5
  • 6. Factors That Cause Migration Introduction Hydrocarbons migrate from a position of higher potential energy to one of lower potential energy. The spatial location of these energy differences defines the expected migration path. There are many sources for this energy that causes oil and gas migration. Sources of energy Three factors primarily cause hydrocarbon migration. All may be active at the same time during the migration process. Each factor produces energy from one or more sources. The table below lists these factors and their corresponding energy sources. Factors Energy Sources Presence of oil or gas • Buoyancy • Chemical potential (related to concentration differences) • Expansion due to a phase change (related to maturation) • Volume increase due to maturation • Sediment compaction (squeezing the oil or gas from collapsing pore space) Indirect effects on oil or gas due to burial • Thermal expansion • Water motion due to compaction • Topographically driven flow Decrease in pressure and temperature as a result of the upward migration of oil or gas • Phase change • Gas expansion Volume increase due to maturation As maturation proceeds, solid kerogen is converted to liquid and gaseous hydrocarbons. When the activation energy levels of the kerogen are exceeded, this conversion is very rapid. The change in phase is accompanied by an increase in volume, preferentially overpressuring the pore system within the source-rock unit and resulting in flow from the source-rock unit into the surrounding formations. This factor is of prime importance in source rocks Buoyancy A free hydrocarbon phase rises in a water column because its density is less than that of water. This buoyancy force is proportional to the density difference and the height of the hydrocarbon column. It acts vertically. When the rising hydrocarbons encounter a lowpermeability (high capillary entry pressure) sloping surface, they are deflected updip and the resultant force is decreased by an amount proportional to the slope of that surface. Temperature and pressure effects on buoyancy Rising temperature (T) increases the buoyancy force as the hydrocarbon is buried. The density of hydrocarbons decreases more rapidly than that of water as temperature increases. If the temperature is high enough, liquid hydrocarbons may alter to a gaseous phase. Rising pressure (P) decreases the buoyancy force as the hydrocarbons are buried. The density of hydrocarbons increases more rapidly than that of water as pressure increases. If the pressure is high enough, gaseous hydrocarbons may alter to a liquid phase. 7-6 • Migration of Petroleum
  • 7. Factors That Cause Migration, continued Temperature and The phase diagram below summarizes the competing effects of pressure and temperature pressure effects changes for a typical volatile oil. on buoyancy (continued) -50 0 50 100 150 Temperature C Gas rich system 200 250 Figure 7–1. After McCain (1990); courtesy PennWell Publishing Co. Chemical potential Diffusive forces spontaneously transfer hydrocarbons dissolved in water from areas of higher concentration to adjacent areas of lower concentration. The kilometers-long diffusion gradients of benzene and toluene within reservoirs demonstrate the effectiveness of this process. However, the lack of significant transport of benzene and toluene through barriers or seals indicates diffusion and active aqueous solution transport are minor mechanisms of the accumulation process. The figure below shows the diffusion of gas in water as a function of concentration at origin and distance from origin (free hydrocarbons). Figure 7–2. After Klimenko (1983); courtesy AGI. Migration Concepts • 7-7
  • 8. Factors That Cause Migration, continued Capillary imbibition Capillary imbibition transfers interconnected free hydrocarbon phases from fine-grained to coarse-grained layers. This force is dominant within source rocks—especially at their contact with coarser beds. If the layer is internal to the source rock (such as a silty streak), it will store these hydrocarbons until a continuous hydrocarbon network connects it with an external coarse-grained layer. If the coarse-grained layer is external, thick, and laterally extensive, it will act as a carrier bed and postexpulsion migration will begin. Capillary imbibition exceeds buoyancy as the force responsible for transferring the hydrocarbon phase to the carrier bed, resulting in downward as well as upward charging from source rocks. Sediment compaction Burial results in the downward motion of each sediment package and is accompanied by a decrease in porosity as it compacts. The resultant motion of water is continually upward with respect to the sediment. The water motion with respect to the sediment/water interface, however, is downward because some water is continually trapped as sedimentation continues. In order for compaction-driven fluids to escape the sediment/water interface, they must move laterally into areas of concentrated upward flow. 7-8 • Migration of Petroleum
  • 9. Factors That Oppose Hydrocarbon Migration Introduction The ease with which hydrocarbons move through the stratigraphic section is controlled by the petrophysical properties of the pore system, the mineralogy of the rock, and the properties of the hydrocarbons. These factors determine the preferential pathway of migration from high to low potential energy and are responsible for concentrating or dispersing the hydrocarbons. Pore throats as sieves Pore throats act as molecular sieves, allowing particles smaller than the orifice to pass and retaining larger particles. If seals were uniformly composed of the same pore throats, they would be perfect seals for compounds larger than the pore throat apertures. Hydrocarbon molecular size Shale pore sizes range over five orders of magnitude and are about the diameter of the individual hydrocarbon molecules. This suggests many pore throats will be able to pass only the smaller hydrocarbon molecules due to physical restrictions (styric effects). Thus, the larger shale pores are supplied with full-spectrum hydrocarbons migrating directly from kerogen in contact with the pores. Larger shale pores are also preferentially supplied with the smaller paraffin and aromatics from the neighboring smaller pores. The figure below compares shale pore size with hydrocarbon molecule size. Figure 7–3. From Momper (1978); courtesy AAPG. Migration Concepts • 7-9
  • 10. Factors That Oppose Hydrocarbon Migration, continued Trapping large molecules in shale Transport of larger molecules, while possible through the large shale pores, becomes increasingly less likely as the path traversed through shale lengthens. This is due to the increased probability of a continuous large pore network terminating into a small pore throat. Indeed, even the flow of the comparatively small water molecule often requires significant pressure gradients to overcome the restrictions to flow common in shales. For water, the problem is generally not one of ability to pass but rather one of rate of passage. Permeability Permeability is related to pore throat size, distribution, and interconnectedness. It is a measurement of the rate at which fluids move through a pore system. The properties of the fluids present in the pores also control the rate at which they move through the system. Permeability is inversely related to the viscosity of the fluid moving through the pores. The presence of more than one immiscible phase in the pore system reduces the permeability of each phase below what it would be if it were the only phase present. Permeability measurements are dominantly taken in sands for reservoir engineering purposes and rarely in shales because of difficulties in getting good measurements. Also, permeabilities derived from cores are characteristically lower than those measured during production tests. Capillary forces Once a separate phase is formed, capillary forces become effective. Capillary forces arise at the interface between two phases across a restricted opening. Capillary pressure is a function of the interfacial tension between the immiscible fluids and the pore throat size. As the pressure difference across a capillary restriction increases, the interface deforms and eventually the nonwetting phase penetrates the restriction. Capillary effects only arise at the contact of two immiscible phases. Neither solution transport nor continuous phase is affected by capillary effects. The phase that preferentially wets the grain surfaces (usually water) is continuous. The nonwetting phase is generally assumed to form one or more continuous networks through a bed when its concentration exceeds between 4.5% and 17% of the pore volume. Capillary forces between small pores For small pores [100 nanometers (nm) or less] and small pore throats (10 nm or less), the concept of surface tension becomes ambiguous. A spherical pore of 100 nm diameter has a pore volume of 5 × 10–16 cm3. The solubility of methane in water is on the order of 1 g/100 g of water. Therefore 150,000 molecules of methane may be dissolved in the pore water and any excess will be in a free phase. As a bubble of methane deforms to pass through the pore throat, about 75 gas molecules are in the pore throat water. It is unclear what the surface tension of the water is with this number of gas molecules or whether the concept of surface tension is valid for these conditions at all. Due to the decrease in solubility with increasing molecular weight and the increase in molecular size, these questions are even more applicable to the other hydrocarbon species and for smaller pores because the number of molecules in pore and pore throat is even less. 7-10 • Migration of Petroleum
  • 11. Factors That Oppose Hydrocarbon Migration, continued Pore pressure Differences in pore fluid overpressure determine the potential, general direction, and rate of fluid flow. For hydrocarbons, the force of buoyancy must be added. The spatial distribution of pressure differentials interacts with permeability and capillarity to determine the flow rates along multiple migration pathways. Perfect seals—ones that don’t leak at all—rarely occur. Pressure minimums are a perfect seal. When all the forces acting on a hydrocarbon mass are resolved and a local minimum in gradient field occurs, the hydrocarbons will remain in the minimum as long as it exists. There is no migration out of that minimum. Phase changes The mineralogy of surfaces contacted by migrating hydrocarbons and continually changing chemistry of pore water alters both the phase and chemistry of the hydrocarbons. Hydrocarbons are driven out of solution into a free phase by three things: • Increasing salinity • Decreasing pressure • Decreasing temperature Sorption Hydrocarbons can be preferentially sorbed on (wet) mineral surfaces. Sorption can control the rate of transporting different hydrocarbon compounds, acting as a chromatographic column. Sorption of saturated gasoline-range hydrocarbons is greatest for the higher boiling, larger molecules. Aromatic hydrocarbons show a similar relationship but are sorbed to a greater extent. A sorption threshold may need to be exceeded before hydrocarbons can migrate from the source rock. Sorption by kerogen is dominant over that of mineral phases. Migration Concepts • 7-11
  • 12. Section B Mechanisms of Migration Introduction The mechanisms by which hydrocarbons migrate controls the rate and direction of hydrocarbon motion and places a constraint on its composition. This section summarizes the proposed mechanisms and discusses the consequences of each mechanism to migration. Evidence exists that all mechanisms occur in the subsurface. Most hydrocarbons are believed to be transported as a separate phase in slug flow. The other mechanism may be dominant under special conditions. In this section This section contains the following topics. Topic Page Migration by Solution in Water 7–13 Migration by Separate Phase 7–15 7-12 • Migration of Petroleum
  • 13. Migration by Solution in Water Introduction Hydrocarbons dissolved in water occur as true solution and micellar solution. Both of these forms enable the hydrocarbons to move one molecule at a time and thus restrict movement minimally. The method of transport is either through direct transport by the water or by diffusion through the water. Reservoirs formed by this type of migration are limited to gas and light condensates. Solution transport is responsible for the loss of gas from many reservoirs and water-washing of oils. True solution True solution is a function of pressure, temperature, salinity, molecular weight, and mixtures of components present. The aqueous solubility of normal alkanes and aromatics at 25°C is shown below. Figure 7–4. After McAuliffe (1980); courtesy AAPG. Composition of hydrocarbons moved by water Reservoirs formed by true solution migration are limited to gas and light condensates. This compositional relationship differs significantly from that found in most reservoired oils. However, a few light oils have molecular abundances in agreement with solubility ratios. The occurrence of these light oils as a separate phase demonstrates that solution transport of oils does occur. The infrequent occurrence (less than 10 reported cases) of oils with a compositional signature consistent with solution solubilities suggests this process of migration is an exception rather than the rule. Exsolution of dissolved hydrocarbons The movement of water from one location to another transports the associated dissolved gas and oil. As the water mass moves into lower temperature and pressure conditions or its salinity increases, the hydrocarbons exsolve and form a free phase. This should be a relatively continuous process, forming a cloud of bubbles throughout the carrier bed system. A free-phase transport mechanism is then needed to accumulate these bubbles within a reservoir. Mechanisms of Migration • 7-13
  • 14. Migration by Solution in Water, continued Migration by diffusion Migration by diffusion of light hydrocarbons in a water-filled pore system is extremely slow. Diffusion conveys hydrocarbons from areas of high concentrations to areas of lower concentrations. It is dominantly a dispersive force and is generally responsible for the loss of hydrocarbons, not their accumulation. Diffusion time vs. distance The time it takes a light hydrocarbon to diffuse a given distance and reach a concentration level equal to half the concentration of a nondepleted source is shown below. Figure 7–5. From Krooss (1987); courtesy Institute Français du Petrole. Diffusion in shale vs. sand In sampled beds, dissolved benzene and toluene can follow a diffusion gradient horizontally for miles in sands but be absent vertically in the over- and underlying sections. This observation suggests diffusion is not a practical transport mechanism in shale. However, even in sands for distances greater than 10–100 m, migration by diffusion is insignificant relative to bulk flow of oil or gas as separate phases. Selective depletion by diffusion Studies of source and reservoir contacts show that diffusion of dissolved hydrocarbons selectively depletes the more soluble compounds from the edges of source rocks into adjacent sands. The extracts found in sands resemble condensates or light oils, while the extracts found on the edges of depleted source rocks look less mature and somewhat biodegraded compared to the less depleted center of the source rocks. Diffusion selectively depletes the more soluble compounds in reservoirs. Although light hydrocarbons are expected to be transported only tens of meters into a shale capping a reservoir, significant quantities of light hydrocarbons can diffuse into this section of overlying seal. Micelles Micellar solution increases the capacity of water to carry molecular hydrocarbon species by the use of naturally occurring hydrocarbon solubilizers called micelles. Micelles are roughly the size of median shale pores and therefore are only able to travel through the largest shale pore throats without being subject to capillary forces. Natural micelles generally are not present in sufficient concentration to significantly alter the ability of water to contain dissolved hydrocarbons. A major problem with micelles as a transport mechanism is the difficulty of separating the hydrocarbons from them to form an accumulation in a reservoir. 7-14 • Migration of Petroleum
  • 15. Migration by Separate Phase Introduction Continuous, separate-phase migration of hydrocarbons moves high volumes of hydrocarbons during primary, secondary, tertiary, and remigration. Several processes can occur during separate-phase migration: formation of small free hydrocarbon masses, slug flow, cosolution, and compositional changes due to phase changes. Small free hydrocarbon masses The existence of small free hydrocarbon masses in the subsurface is inevitable. Each kerogen particle produces such a mass. Small hydrocarbon masses are commonly subdivided by size: • Colloids—masses the size of median shale pores • Emulsions—masses the size of large shale pores • Droplets—masses larger than most shale pores Of these, only hydrocarbon colloids are able to travel through the largest pore throat network without the limiting effects of capillarity. There is doubt, however, that a small mass of hydrocarbons has sufficient buoyant force to free itself from its attraction to the surface of a kerogen particle. Slug flow in primary migration Slug flow (or bulk phase flow) is generally accepted as the dominant mechanism of primary hydrocarbon migration. Within the source rock, the volume of hydrocarbons produced from kerogen increases until a continuous mass forms (a slug) that has enough force to overcome the capillary forces of the largest pore throat network. At that time, the slug moves into the closest coarse-grained bed. Expulsion is preferentially upward because of the hydrocarbons’ buoyancy, but it may be downward due to generation and compaction pressure if the pathway is less restrictive. Expulsion probably acts discontinuously, resulting in periodic slugs of migrating hydrocarbons. Broad compositional differences between the slug and those hydrocarbons generated from the kerogen appear to be due to preferential retention of large hydrocarbons by fine pores. Slug flow in secondary, tertiary, and remigration Slug flow also dominates secondary, tertiary, and remigration. At each contact between a coarse pore network and a fine pore network, the mass of hydrocarbons accumulates until it reaches a buoyancy pressure great enough to overcome the capillary forces of the fine pore network. Relative permeability effects also aid migration. As hydrocarbons fill a pore network, the ability of a pore network to transport water decreases. This process builds pore pressure, helping push the hydrocarbons through the capillary restrictions. Slug flow compositional changes Changes in hydrocarbon composition during secondary, tertiary, and remigration do not appear to be significant. Bulk phase flow minimizes the opportunity of the hydrocarbons to interact with the substrate. Bulk phase flow overloads the adsorption–desorption capability of the substrate due to the quantity and concentration of the migrating hydrocarbons. Broad compositional modifications may be related to physical filtering of the larger hydrocarbons during their passage through a fine pore throat network. Mechanisms of Migration • 7-15
  • 16. Migration by Separate Phase, continued Cosolution Hydrocarbons have the capability of dissolving other hydrocarbons in them. This process is called cosolution. Methane, for example, which might normally be in a gaseous form, can be dissolved in a liquid oil. Similarly, a small amount of normally liquid oil may be dissolved in gaseous methane and be transported as part of the gas. The properties of the carrying phase are altered by the dissolved component. Pressure effects At pressures that exceed the critical point for hydrocarbon mixtures, the terms “gas phase” and “oil phase” become ambiguous. A single phase generally occurs at pressures above 4,000 psi and temperatures above 200°F (93°C). For a hydrostatic gradient, this pressure converts to a little less than 9,000 ft with a geothermal gradient of about 1.5°F/100 ft and a surface temperature of 70°C. Phase effects on composition A migrating hydrocarbon mass passes into different pressure and temperature conditions. As this happens, the mass may separate from its original phase into two phases, each containing a different mixture of hydrocarbons. In the following phase diagram, the X-axis shows the phase of the migrating hydrocarbons. The Y-axis on the left side shows pressure in terms of depth. The Y-axis on the right side shows the temperature. Figure 7–6. After Pepper (1991); courtesy Geological Society. 7-16 • Migration of Petroleum
  • 17. Migration by Separate Phase, continued Compositional changes during phase changes Phase migration occurs when a gas is expelled with oil or migrates through an oil-rich source rock. The figure below shows the gasoline range and heavier hydrocarbons in a single-phase fluid expelled from a source rock at 3000 m. As the fluid migrates upward to lower temperatures and pressures, it undergoes a process called separation migration. At 2500 m, the 100 tons of single phase have separated into 40 tons of gas and 60 tons of oil. The figure shows the composition of each phase and the mass partitioning of the migrating-gas phase as the liquids are trapped. Note that the migrating-gas phase becomes enriched in the gasoline range and the liquids left behind progressively lose their heavier compounds. Light gas compounds are not shown. Surface geochemical studies indicate the ratios at C1 to C5 are little changed by upward migration. Separation–migration can significantly alter the gross composition of the migrated and trapped intervals, while maintaining sufficient detailed similarities so they can be recognized as belonging to the same family and source rock. Figure 7–7. After Ungerer et al. (1984); courtesy AAPG. Kerogen network Migration along a kerogen network can occur either one molecule at a time or as a separate phase. It is a special case, restricted to rich source rocks where a continuous kerogen network is likely. Mechanisms of Migration • 7-17
  • 18. Section C Changes in Hydocarbon Composition During Migration Introduction The process of migration alters the chemical characteristics of the hydrocarbons from that which was produced in the source rock. The factors that govern these changes and their effect on hydrocarbon composition are discussed. In this section This section contains the following topics. Topic Page Compositional Changes During Primary Migration 7–19 Compositional Changes During Postprimary Migration 7–20 7-18 • Migration of Petroleum
  • 19. Compositional Changes During Primary Migration Introduction The composition of hydrocarbons expelled from a source rock is a primary control on the composition of reservoired hydrocarbons. In general, the larger-molecular-weight compounds are preferentially retained in the source rock while the smaller compounds are expelled. Factors favoring oil expulsion The following factors favor oil expulsion from a source rock: • Type I or 2 kerogen • Sufficient time in the oil window • High levels of TOC • Concentration of organic matter in lamina • Low-capillary-pressure conduits Factors favoring gas expulsion Five factors favor gas expulsion from a source rock: • Type 3 kerogen • Rapid burial through the oil window • Low TOC • Dissemination of organic matter • High-capillary-pressure conduits Composition of early vs. later generation Early generation concentrates light products into large pores and fracture networks. Thus, the oil expelled is lighter in composition than the oil retained. However, as maturity continues, the difference between these two disappears and oil–source correlation improves. Compositional changes and correlation Expulsion favors light compounds over heavy compounds and saturated hydrocarbons over aromatics. This is due to molecular filtering and adsorption–desorption phenomena, particularly during the early stages. However, because significant quantities of hydrocarbons are retained in the large and medium pore systems within the source rock, the correlation of reservoired oil with its respective source rock is not significantly affected. The effect of continued maturation of the source rock after expulsion is a more significant impediment to correlation. Changes in Hydrocarbon Composition During Migration • 7-19
  • 20. Compositional Changes During Postprimary Migration Introduction During postexpulsion migration, many processes can alter the chemical characteristics of the hydrocarbons expelled from the source rock. The geochemical similarity of reservoired hydrocarbons and hydrocarbons expelled from source rocks, however, indicates there is usually little compositional alteration along the postexpulsion migration routes. An exception to this is the selective trapping of gas- and liquid-rich phases due to the quality of the seal. Alteration processes Processes responsible for altering the composition of hydrocarbons during migration include the following: • Water-washing—selective removal of the more water-soluble components • Adsorption—selective removal and retardation of hydrocarbon migration rate by mineral and kerogen particles • Phase partitioning—concentration of different hydrocarbon species into gaseous and liquid phases with changes in pressure and temperature • Mixing—by (1) including hydrocarbons from post-source-rock kerogen particles along the migration path; (2) mixing migration streams from two or more source rocks; or (3) precipitation of asphaltenes and other high-molecular-weight compounds by the addition of methane • Biodegradation—biologic alteration of the hydrocarbons Migration method and alteration The migration method partly determines the extent of compositional changes that occur during secondary, tertiary, or remigraton. If the petroleum moves as a broad front—as would be expected for solution gas or light oil in water and perhaps for dispersed colloids or droplets—there would be a maximum probability of interactions. However, if the petroleum moved as a slug or filament, contact with elements that could alter its composition would be more limited. Seal leakage from traps with gas caps In traps with gas caps, the buoyancy of the gas and oil column can exceed the breakthrough pressure of the seal prior to the trap being filled to the spill point. If this happens, the trap will leak through the seal and preferentially lose the gas phase. This situation (deep oil, shallow gas) is observed but is opposite to the expected sequence of entrapment due to maturation (oil migrates first, then gas). The figure below illustrates what happens when seals leak from traps with gas caps. Figure 7–8. After Schowalter (1979); courtesy AAPG. 7-20 • Migration of Petroleum
  • 21. Compositional Changes During Postprimary Migration, continued Differential entrapment The differential entrapment of gas in downdip traps (Gussow, 1954) is achieved by successively filling a sequence of traps in the same formation with oil and gas. As each trap fills to its spill point, the phase that is spilled first is the liquid leg. Thus, the gas is retained in the structurally lower traps and the oil is trapped farther up the migration path. This situation is the expected sequence of entrapment (shallow oil, deep gas) from the maturation sequence. The figure below illustrates what happens when traps preferentially spill oil and retain gas. Figure 7–9. From Gussow (1954); courtesy AAPG. Changes in Hydrocarbon Composition During Migration • 7-21
  • 22. Section D Migration Pathways Introduction Hydrocarbon migration appears to occur in spatially limited areas (always unsampled because of their small size) and in discrete time intervals. It leaves either no trace or a trace that is continually modified or destroyed by later events. Effective hydrocarbon migration occurs along discrete pathways, not along broad, uniform fronts. These pathways are determined by the pore networks, the interaction of these networks between formations, and the stratigraphic variation within the basin. Within the carrier/reservoir bed, the migration pathway is controlled by the structural configuration of the contact with the overlying seal and the continuity of both the carrier permeability network and the overlying seal. This section discusses the general characteristics of these paths and shows several examples. In this section This section contains the following topics. Topic Page Formation-Scale Migration Pathways 7–23 Defining Migration Pathways from Source to Trap 7–24 Vertical and Lateral Migration Distance 7–26 Migration Rate 7–27 7-22 • Migration of Petroleum
  • 23. Formation-Scale Migration Pathways Introduction Flow of an immiscible phase through a series of beds does not proceed uniformly but occurs preferentially through beds of higher permeability when possible. It is dependent on the capillary properties of individual beds, the proportion of higher- to lower-permeability beds, and spatial relationships of beds to the principal flow directions (bed parallel and bed perpendicular). These factors are similar to the factors reservoir engineers use to characterize reservoir heterogeneity. They are, however, more difficult to assess because of the uncertainty of the characteristics of low-permeability rocks. The knowledge base is currently undergoing rapid change. Bed orientation control of flow The effect of bedding geometry on permeability direction and magnitude is significant. The table below shows how bedding orientation controls flow of hydrocarbons during migration. If bed orientation is... Then the flow is ... Parallel to the flow direction Perpendicular to the flow direction principally controlled by the least permeable units Random alignment to the flow direction Bed-parallel vs. bedperpendicular flow principally controlled by the most permeable units not preferentially focused The following crossplot shows the difference in relative permeability at varying water saturations for bed-parallel vs. bed-perpendicular muliphase fluid flow in a wavy bedded rock. The water saturations need to be much lower in bed-perpendicular flow to achieve the same relative permeability. The flow within a bed is a function of the proportions of end-member lithologies, their permeability and capillary pressures, and the orientation of the beds to the direction of the flow. Figure 7–10. After Ringrose and Corbett (1994); courtesy Geological Society. Migration Pathways • 7-23
  • 24. Defining Migration Pathways from Source to Trap Introduction The general flow of petroleum from a mature source rock to a trap can be estimated using a few simple assumptions: • The dominant force causing petroleum to move is buoyancy. • Petroleum is deflected laterally through sand-rich sections by overlying shale-rich sections. • Where there are closed traps along this pathway, petroleum will accumulate until the trap is full and spills, or leaks, any additional migrating petroleum. The exact flow paths generally require more detailed information about stratigraphic variability, distribution of fractures, and permeability of faults than is generally available to geologists. Procedure The table below lists a procedure for defining migration pathways. Step Action 1 2 Identify stratigraphic units with low permeability that could serve as regional seals. 3 Make a structure contour map at the top of carrier beds or the base of regional seal. Highs focus flow; lows diffuse flow. 4 Locate source rocks and map the location of the upper boundary of the oil and gas maturation windows. 5 Locate other geologic features that could influence flow pathways, e.g., fault segments, fractures, unconformities, boundaries of intrusions, flanks of salt domes. 6 Data requirements Identify stratigraphic units with high permeability that could serve as carrier beds. Draw migration vectors based on the above information. A map of the structure at the top of the main sand-rich section is required to make a petroleum migration map. Generally, a map showing the present structure is used. However, a much better result can be obtained by using a map showing the structure at the time of main hydrocarbon expulsion. The location of mature source rock is projected vertically onto this map. 7-24 • Migration of Petroleum
  • 25. Defining Migration Pathways from Source to Trap, continued Constructing a map The area of the mature source forms the boundary from which petroleum is considered to migrate. Flow lines showing the expected direction of hydrocarbon migration are constructed on this map using the assumption that migration flow is perpendicular to structural contour lines and moves updip. All closures should be considered as the end of the migration path unless there is a good reason why the trap should spill hydrocarbons. Faults can be considered as either nonsealing (the flow lines go updip right through them) or sealing (they divert the flow of hydrocarbons around them). Influence of regional seals The map described above assumes petroleum expelled from the source rock migrates vertically until it reaches a single regionally continuous seal and then migrates laterally into traps, or that any immediate seals have the same structure as the regional seal. Although the latter assumption is often justified, it sometimes may be necessary to make drainage maps on intermediate regional seals and assume the petroleum from the source rock migrates vertically to the first regional seal above it and is deflected laterally as shown by the flow lines interpreted on the base of that seal. At the limit of that seal or at holes in that seal, the petroleum is assumed to migrate vertically until it once again becomes constrained by a seal. In this way, the petroleum is seen to stairstep up the section. It migrates below intermediate regional seals and possibly fills intermediate traps until it is finally constrained below a master sealing section, if one is present. Example The figure below is an example of defining migration pathways in the Williston basin. Part A is a structure map at the base of the principal source rock, the Bakken Formation. This simplified map is a reasonable representation of the structural configuration for the basin. Part B shows migration pathways from the Bakken, based on the basin structural configuration only; hydrodynamic effects are not included. Figure 7–11. From Hindle (1997); courtesy AAPG. Migration Pathways • 7-25
  • 26. Vertical and Lateral Migration Distance Introduction Distance of migration from source to reservoir varies greatly. The rule that the first sealed reservoir in a trapping configuration has the highest probability of containing hydrocarbons has been proven over and over again. Lateral migration distances, established by oilsource geochemical fingerprinting, reach hundreds of kilometers; vertical distances reach tens of kilometers. Estimation of migration distance is based on geochemical observations and inferences. These include maturity of product, geothermal gradients, fingerprint matching between source and reservoir, and geological estimation of the nearest rock unit of source quality. Vertical migration A reservoired hydrocarbon is analyzed geochemically to determine the maturity of the source from which it was derived. Using this information and an estimate of the change in maturity, the minimum vertical depth of origin is determined. The change in maturity with depth is estimated from measurement or modeling. Detailed geochemical studies of extracts, including isotopic analysis, often show a smoothly increasing gradient of maturity, suggesting local genesis and short migration distances. Superimposed on this gradient are isolated spikes of hydrocarbons with maturities characteristic of much deeper conditions. These represent migrated product. Long-distance migration factors The factors that influence the distance hydrocarbons may travel are complexly interrelated. Such a detailed knowledge of the petroleum system and the stratigraphy of the area is required that prediction of migration distance is next to impossible. It requires source– reservoir correlation, knowledge of the extent of the source rock, and knowledge that there are no other potential sources. The dominant factors favoring long-distance transport of hydrocarbons include the following: • Large volume of hydrocarbons • Efficient expulsion • High-quality carrier beds • Uninterrupted updip pathways • High-quality regional seal 7-26 • Migration of Petroleum
  • 27. Migration Rate Introduction From a linear rate standpoint, the least efficient process along the migration path is the rate-limiting step that controls the overall rate of the process. In a sequence of sands and shales, the rate limiter is the least permeable shale and the expulsion rate of hydrocarbons in the source. However, the migration rate of a nonwetting separate phase through barriers like shales is self-adjusting. This is accomplished by enlarging the area through which the process operates. For example, in traps, hydrocarbons are accumulated and spread laterally until the accumulation size causes the rate of migration into the structure to equal that going out of the structure. This accumulation process increases the hydrocarbon flux rate through the overlying shale by increasing the contact area of the hydrocarbons with the shale. Any weaknesses in the shale, such as fractures, will eventually be reached by the accumulating hydrocarbons, increasing the leakage from the trap. Accumulation size is also limited by the spill point. Parallel and serial processes The flux rate of hydrocarbon transport in the subsurface is viewed as consisting of both parallel and serial processes. Parallel processes occur simultaneously. They are • Diffusive transport • Aqueous transport in solution and as micelles • Separate phase transport Serial transport processes are dominant. They occur sequentially along the most effective migration path. Examples of serial processes are • Expulsion from the source rock • Capillary restrictions along the migration route to the trap • Leakage through the seal Rates for different mechanisms Hydrocarbons migrate by different mechanisms; each has its own rate. The table below lists the mechanisms and rates. Migration Mechanism Migration Rate Hydrodynamic Compaction 0.001 and 1 m/year Buoyancy Meters per day for gas (oil not measured) Diffusion Hydrodynamics or compaction transport rate 0.1 and 100 m/year 1 to 10 m/m.y. The rate of water movement through pore systems places an upper limit on the rate of hydrocarbon transport by hydrodynamics or compaction. If the hydrocarbons are present as a free phase, buoyant forces may be added to the rate. In practice, however, the additional force supplied by hydrodynamics or compaction is largely counterbalanced by capillary forces and relative permeability effects. Rates vary for hydrodynamic transport, depending on permeability and elevation head. Rates from compaction depend primarily on permeability since pressure can only vary between hydrostatic and geostatic pressure. Migration Pathways • 7-27
  • 28. Migration Rate, continued Buoyancy transport rate The rate of transport of hydrocarbons by buoyancy depends on the density contrast of the hydrocarbons with water and hydrocarbon column height. The rate of transport of large hydrocarbon masses is limited by the time it takes the mass to grow to a column height that can overcome capillary forces of barriers to migration. Once a continuous thread of hydrocarbons connects two coarse-grained units through an intermediate fine-grained unit, the transfer of hydrocarbons from the lower unit to the upper is only limited by the permeability of the pathway. Diffusion transport rate Hydrocarbon transport by diffusion is very slow. Rates depend on the concentration at the location from which diffusion proceeds. For a free phase this is always a concentration of one; the diffusion coefficient is between 10–10 and 10–12 m2/sec. Rate measurements Rate measurements of migration are seldom made because of the uncertainty associated with migration length, cross-sectional area, and time interval. Linear rate estimates of gas-phase migration in the upper 200 m of sedimentary basins are as high as tens of meters per day, based on known times of injection of gas into storage reservoirs and subsurface coal burns. Estimates of vertical seepage velocities over larger areas are between 75 and 300 m/year. Oil volume rate estimates of 50 m3 (300 bbl) per year have been made in the marine environment by collecting bubbles. These rates clearly indicate separate phase migration along multiple narrow migration pathways. Maximum rates Maximum rates of separate phase migration are estimated to be much faster than commonly envisioned. Many old fields, particularly gas fields, have produced more hydrocarbons than their original estimates of reserves in place. Initial production rates often decline to a low steady-state value. Discounting the uncertainties involved in these estimates, it appears production may decline until it is balanced by the area integrated charge rate of the field. Many shut-in wells show pressure buildup, indicating transfer of fluids into the field at relatively rapid rates. It is, however, uncertain what portion of the recharge is hydrocarbons and what portion is water. 7-28 • Migration of Petroleum
  • 29. Section E Calculating Migration Rate and Charge Volume Introduction This section contains the formulas and procedures needed to calculate the expected rates of hydrocarbon migration and the expected volume of hydrocarbons delivered to a trapping configuration. In this section This section contains the following topics. Topic Page Calculating Migration Rate 7–30 Calculating Charge Volume 7–32 Estimating Expulsion Efficiency 7–35 Calculating Migration Rate and Charge Volume • 7-29
  • 30. Calculating Migration Rate Introduction The rate of migration for oil or gas can be estimated using Darcy’s law, the principal formula for calculating permeability. Darcy’s law generally holds for rocks with tube-shaped pore systems; however, it is only an approximation for flow in rocks with high percentages of clays, like shales, due to the platey grain shape of the clays. The Kozeny–Carman correction estimates the permeability of rocks with high percentages of clays Procedure The procedure for calculating the migration rate of oil or gas is outlined in the table below. Step Action 1 2 Calculate the buoyancy pressure. 3 Calculating migration rate Gather data, including permeability of carrier beds, viscosity of oil, fluid density, and pore pressure gradient. Calculate the rate of hydrocarbon migration. Use the version of Darcy’s law presented below to calculate the rate of migration for oil or gas: R = – ( k ✕ A/m ✕ [(Pgrad + Pc) – ρhc ✕ g] ) where: R k A m Pgrad Pc ρhc g Correcting for clay-rich rocks = = = = = = = = rate of migration (m3/sec) permeability to oil or gas at a given saturation (m2) cross-sectional area (m2) dynamic viscosity (Pa-sec) (use 0.01 Pa-sec for oil and 0.0001 for gas at 20°C; 0.001 Pa-sec for oil and 0.00001 for gas at 150°C pore pressure gradient (Pa) (use 4.5 psi/ft if not available) capillary pressure gradient hydrocarbon density (kg/m3) acceleration of gravity (~9.81 m/sec2) For rocks with high percentages of clay, use the Kozeny–Carman correction as shown in the table below to obtain a closer approximation of permeability. Porosity > 10% 7-30 • Migration of Petroleum k = [0.2 ✕ φ3] / s 2 ✕ (1 – φ)2 < 10% where: φ s Use k = [20 ✕ φ3] / s 2 ✕ (1 – φ)2 = free porosity = rock surface area (surface area of grains in cross section A)
  • 31. Calculating Migration Rate, continued Buoyancy pressure Buoyancy pressure for a particular hydrocarbon must be calculated for its migration rate. Use the formula below to calculate buoyancy pressure: PB = g ✕ z ✕ (ρw – ρhc) where: PB z ρw ρhc Minimum buoyancy pressure for migration = = = = buoyancy pressure height of hydrocarbon stringer water density hydrocarbon density Migration upslope under a seal occurs when buoyancy is greater than capillary pressure, or g ✕ l ✕ sinQ ✕ (ρw – ρhc) > 2γ where: l = length of oil stringer Q = angle with the horizontal γ = interfacial tension (oil–water), dynes/cm Each dip reversal in or near a flat hydrocarbon migration path will trap hydrocarbons and make continued hydrocarbon flow updip less likely. Calculating Migration Rate and Charge Volume • 7-31
  • 32. Calculating Charge Volume Introduction The volume of hydrocarbons expected to be delivered to a trap is an important risk parameter. This section covers methodology and information to calculate the hydrocarbon charge volume parameter. Volume constraining factors Certain factors constrain the amount of hydrocarbon delivered to a trap. These factors can be divided into two groups, as shown below. Source Rock Factors Migration Factors Drainage area Lateral migration distance Thickness Vertical migration distance Potential ultimate yield Lateral migration factor* Yield fraction timing Vertical migration factor* * A function of lithology, depth, degree of fracturing, and/or faulting Procedure The table below lists a procedure for estimating the volume of migrated hydrocarbons available to fill a trap. Step 1 Action Calculate the volume of hydrocarbons generated by the source rock, using the formula V = A ✕ T ✕ Y ✕ M where: V = A = T = Y = potential charge volume area source rock thickness hydrocarbon yield per volume of source from each kerogen facies and maturity class M = migration efficiency 2 Estimate the proportion of the source rock that supplied hydrocarbons to the area in which the trap is located (drainage area). Use a map of the mature source rock. 3 Estimate the efficiency of the migration process. For example, did 20% of the generated hydrocarbons travel from the source rock to the trap? 4 Calculate the volume of migrated hydrocarbons available to fill the trap 7-32 • Migration of Petroleum
  • 33. Calculating Charge Volume, continued Estimating drainage area It is important to make a migration map showing the location of the source rock facies and the drainage areas that feed the areas of interest. The map is best drawn for the time when maturation analysis indicates the hydrocarbons should be migrating. A rougher estimate can be made from a map or the stucture as it exists today. A drainage map is made from the migration map. It should include estimates of maturity and hydrocarbon yield in an appropriate number of area classes. Subareas within these classes are defined by thickness and yield variation within the total drainage area. Example drainage map The upper map below is a hypothetical migration pathway map. The lower map shows the thickness of source rock, the top of the oil and gas windows, and the drainage areas for two traps labeled A and B of the same area shown in the upper map. The drainage areas for traps A and B were made using the migration pathway map. Figure 7–12. Calculating Migration Rate and Charge Volume • 7-33
  • 34. Calculating Charge Volume, continued Example of calculating volume The table below gives an example of calculating hydrocarbon charge volume for traps A and B. The volume of expelled hydrocarbons is calculated using V = A ✕ T ✕ Y ✕ M. Estimation of charge volumes for the two traps (A and B) are made as follows. Factor Trap A Trap B Area 3 (1000-m-thick mature source rock) 0 km2 50 km2 Yield/volume of source in area 1 0.2 bbl/m3 0.2 bbl/m3 0 bbl 10 billion bbl Area 2 (500-m-thick mature source rock) 10 km2 350 km2 Yield/volume of source in area 2 0.1 0.1 0.5 billion bbl 17.5 billion bbl Area 3 (200-m-thick mature source rock) 40 km2 10 km2 Yield/volume of source in area 3 0.02 0.02 0.16 billion bbl 0.04 billion bbl Total generated (areas 1 + 2 + 3) 0.66 billion bbl 27.54 billion bbl Migration effeciency 10% 10% Volume available for charge 0.066 billion bbl 2.754 billion bbl Total volume generated in area 1 Total volume generated in area 2 Total volume generated in area 3 Charge volume classification Because of the uncertainties in estimating the charge volume, these estimates are often compared to the estimate of reservoir pore volume within the trap. The following classification is suggested. Overcharged Trap—Charge volume exceeds one order of magnitude of the trap pore volume. It is likely that significant volumes of hydrocarbons have been spilled from the trap. Fully Charged Trap—Charge volume within plus or minus one order of magnitude of the trap pore volume. It is unlikely that significant volumes of hydrocarbons have been spilled from the trap. Undercharged Trap—Charge volume is less than one order of magnitude of the trap pore volume. No hydrocarbons are likely to have been spilled from the trap. 7-34 • Migration of Petroleum
  • 35. Estimating Expulsion Efficiency Introduction Efficiencies of expulsion and transport need to be estimated and used to account for inefficiencies in the migration path. Only part of the oil and gas generated by the source rock is actually expelled; of the amount that is expelled, only a small amount is trapped. The diagram below summarizes the efficiencies of the expulsion, migration, and entrapment processes. Figure 7–13. After Magara (1980); courtesy AAPG. Expulsion percentage ranges Typical oil expulsion efficiencies are estimated to be in the 5–10% range, with values in the 15% range uncommon and 30% rarely demonstrated. This efficiency is low because most of the source rock section contains too low a concentration of organic material to participate in the expulsion process. Efficiencies of gas expulsion are estimated to be 50–90%, with values of 75% common. Unfortunately, much of this is gas lost due to solution and does not participate in reservoir charging. For both oil and gas, expulsion efficiencies tend to increase with increasing TOC. Expulsion efficiencies for oil and gas can be as high as 70–80% for very rich, effective source rocks near preferential migration pathways. Procedure In migration volumetrics, it is important to estimate the original petroleum potential of the source rock—not just its present measured potential (with increasing maturation, a portion of the original potential will have been realized and is therefore unmeasurable). Estimates of expelled hydrocarbons may be derived by measuring the amount remaining in a source and subtracting that value from the amount that should have been generated from the original assumed kerogen content. Calculating Migration Rate and Charge Volume • 7-35
  • 36. Estimating Expulsion Efficiency, continued Procedure (continued) Below is a procedure for estimating expulsion efficiency. Step Action 1 2 Model the original hydrocarbon generation potential of the source rock using the estimated original kerogen content. 3 Measure the volume of hydrocarbons expelled during pyrolosis (S2.) 4 Estimate the actual expelled hydrocarbon volume by subtracting the S2 value from the original hydrocarbon generation potential of the source rock. 5 Expulsion diagram Estimate the original kerogen content of the rock using TOC values measured from source rock samples. Calculate efficiency by dividing the expected volume of expelled hydrocarbons from the actual volume of hydrocarbons generated. The following figure summarizes the procedure for estimating expulsion efficiency. Recoverable 0.0 - 0.2X Not Recoverable Lost Through Time by Diffusion and Leakage Currently Trapped 0.0 - 0.3X Trapped 0.0 - 0.3X Spilled Loss en Route Retained in Source Delivered to Reservoir 0.0 - 0.3X Expelled to Reservoir 0.0 - 0.3X Total Hydrocarbons Generated in Drainage Area X Figure 7–14. From McDowell (1975); courtesy Oil & Gas Journal. 7-36 • Migration of Petroleum
  • 37. Section F References References cited Gussow, W.C., 1954, Differential entrapment of gas and oil: a fundamental principle: AAPG Bulletin, vol. 38, p. 816–853. Hindle, A.D., 1997, Petroleum migration pathways and charge concentration: a three dimensional model: AAPG Bulletin, vol. 81, p. 1451–1481. Klimenko, A.P., 1983, Diffusion of gasses from hydrocarbon deposits, in Petroleum Geochemistry, Genesis, and Migration: AGI Reprint Series, vol. 1, p. 117–122. Krooss, B.M., 1987, Experimental investigation of the diffusion of low-molicular weight hydrocarbons in sedimentary rocks, in B. Doligez, ed., Migration of Hydrocarbons in Sedimentary Basins: 2nd IFP Expl. Res. Conference Proceedings, p. 329–351. Magara, K., 1980, Evidences of primary migration: AAPG Bulletin, vol. 64, p. 2108–2117. McAuliffe, C.D., 1980, Oil and gas migration: chemical and physical constraints, in W.H. Roberts and R.J. Cordell, eds., AAPG Studies in Geology no. 10, p. 89–107. McCain, W.D., Jr., 1990, The Properties of Petroleum Fluids: Tulsa, PennWell Books, 548 p. McDowell, A.N., 1975, What are the problems in estimating the oil potential of a basin? Oil & Gas Journal, June 9, p. 85–90. Momper, J.A., 1978, Oil migration limitations suggested by geological and geochemical considerations, in W.H. Roberts and R.J. Cordel, eds., Physical and Chemical Constraints on Petroleum Migration: AAPG Continuing Education Course Notes Series no. 8, p. B1–B60. Pepper, A.S., 1991, Estimating the petroleum expulsion behavior of source rocks: a novel quantitative approach, in W.A. England and E.J. Fleet, eds., Petroleum Migration: Geological Society Special Publication no. 59, p. 9–31. Ringrose, S.P., and P.W.M. Corbett, 1994, Controls in two phase fluid flow in heterogeneous sandstones, geofluids, in J. Parnell, ed., Origin, Migration, and Evolutions of Fluids in Sedimentary Basins: Geological Society Special Publication no. 78, p. 141–150. Schowalter, T.T., 1979, Mechanics of secondary hydrocarbon migration and entrapment: AAPG Bulletin, vol. 63, p. 723–760. Ungerer, P., F. Behar, P.Y. Chenet, B. Durand, E. Nogaret, A. Chiarelli, J.L. Oudin, and J.F. Perrin, 1984, Geological and Geochemical models in oil exploration, principles and practical examples, in G. Demaison and R.J. Murris, eds., Petroleum Geochemistry and Basin Evaluation: AAPG Memoir no. 35, p. 53–77. References • 7-37
  • 38. References, continued Additional references Brace, W.F., 1980, Permeability of crystalline and argillaceous rocks: International Journal of Mechanics and Mineral Sciences and Geomechanical Abstracts, vol. 17, p. 241–251. Cooles, G.P., A.S. Mackenzie, and T.M. Quigley, 1986, Calculations of petroleum masses generated and expelled from source rocks: Organic Geochemistry, vol. 10, p. 235–245. Dahlberg, E.C., 1982, Aplied Hydrodynamics in Petroleum Exploration: New York, Springer-Verlag, 161 p. Hermannrud, C., S. Eggen, T. Jacobsen, E.M. Carlsen, and S. Pallesen, 1990, On the accuracy of modeling hydrocarbon generation and migration: the Egersund basin oil field, Norway: Organic Geochemistry, vol. 16, p. 389–399. Hunt, J.M., 1979, Petroleum Geochemistry and Geology: San Francisco, W.H. Freeman Company, 617 p. Lerch, I., and R.O. Thomsen, 1994, Hydrodynamics of Oil and Gas: New York, Plenum Press, 308 p. Mann, U., 1994, An integrated approach to the study of primary petroleum migration, in J. Parnell, ed., Origin and Evolution of Fluids in Sedimentary Basins: Geological Society Special Publication 78, p. 233–260. Matthews, M.D., 1996, Hydrocarbon migration—a view from the top, in D. Schumacher and M.A. Abrams, eds., Hydrocarbon Migration and Its Near Surface Expression: AAPG Memoir 66, p. 139–156. Perrodon, A., 1983, Dynamics of oil and gas accumulations: Bulletin des Centres de Recherches Exploration-Production Elf-Aquitaine, Memoir 5, 368 p. Rhea, L., M. Person, G. de Marsily, E. Ledous, and A. Galli, 1994, Geostatistical models of secondary oil migration within heterogeneous carrier bed: a theoretical example: AAPG Bulletin, vol. 78, p. 1679–1691. Tissot, B.P., and D.H. Welte, 1984, Petroleum Formation and Occurrence: Berlin: Springer-Verlag, 699 p. Vandenbroucke, M., 1993, Migration of hydrocarbons, in M.L. Bordenave, ed., Applied Petroleum Geochemistry: Paris, Technip, p. 123–148. Acknowledgment The author thanks Texaco for permission to publish this manuscript. He is particularly indebted to Vic Jones, Ted Weisman, the late Bill Roberts, and Hollis Hedberg for their guidance as well as to co-workers throughout the industry for their stimulating discussions. 7-38 • Migration of Petroleum