1. Chapter 7
Migration of Petroleum
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.
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
• How can we estimate the timing, volumes, and compositions of transported hydrocarbons?
In this chapter
This chapter contains the following sections.
Mechanisms of Migration
Changes in Hydrocarbon Composition During Migration
Calculating Migration Rate and Charge Volume
Overview • 7-3
4. Section A
The principles of hydrocarbon migration, discussed in this section, can be summarized as
• 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
The broad principles of migration are reviewed in detail in this section.
In this section
This section contains the following topics.
Factors That Cause Migration
Factors That Oppose Hydrocarbon Migration
7-4 • Migration of Petroleum
5. Migration Basics
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.
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.
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.
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.
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.
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.
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
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.
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.
Presence of oil or gas
• 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
increase due to
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
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.
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.
Gas rich system
Figure 7–1. After McCain (1990); courtesy PennWell Publishing Co.
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 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
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
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
Pore throats as
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.
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
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 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
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.
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
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.
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
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
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.
Migration by Solution in Water
Migration by Separate Phase
7-12 • Migration of Petroleum
13. Migration by Solution in Water
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 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.
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.
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 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.
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.
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.
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.
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
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.
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
• 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
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
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.
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
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.
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.
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
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.
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
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.
Compositional Changes During Primary Migration
Compositional Changes During Postprimary Migration
7-18 • Migration of Petroleum
19. Compositional Changes During Primary Migration
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
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
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
early vs. later
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
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
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
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
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.
from traps with
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
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
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.
Formation-Scale Migration Pathways
Defining Migration Pathways from Source to Trap
Vertical and Lateral Migration Distance
7-22 • Migration of Petroleum
23. Formation-Scale Migration Pathways
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.
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
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
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
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
The table below lists a procedure for defining migration pathways.
Identify stratigraphic units with low permeability that could serve as
Make a structure contour map at the top of carrier beds or the base of
regional seal. Highs focus flow; lows diffuse flow.
Locate source rocks and map the location of the upper boundary of the oil
and gas maturation windows.
Locate other geologic features that could influence flow pathways, e.g.,
fault segments, fractures, unconformities, boundaries of intrusions, flanks
of salt domes.
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
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).
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.
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
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.
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.
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
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.
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
Hydrocarbons migrate by different mechanisms; each has its own rate. The table below
lists the mechanisms and rates.
0.001 and 1 m/year
Meters per day for gas (oil not measured)
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
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.
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 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 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
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.
Calculating Migration Rate
Calculating Charge Volume
Estimating Expulsion Efficiency
Calculating Migration Rate and Charge Volume • 7-29
30. Calculating Migration Rate
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
The procedure for calculating the migration rate of oil or gas is outlined in the table
Calculate the buoyancy pressure.
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
R = – ( k ✕ A/m ✕ [(Pgrad + Pc) – ρhc ✕ g] )
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.
7-30 • Migration of Petroleum
k = [0.2 ✕ φ3] / s 2 ✕ (1 – φ)2
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 for a particular hydrocarbon must be calculated for its migration rate.
Use the formula below to calculate buoyancy pressure:
PB = g ✕ z ✕ (ρw – ρhc)
height of hydrocarbon stringer
Migration upslope under a seal occurs when buoyancy is greater than capillary pressure,
g ✕ l ✕ sinQ ✕ (ρw – ρhc) > 2γ
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
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.
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
Lateral migration distance
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
The table below lists a procedure for estimating the volume of migrated hydrocarbons
available to fill a trap.
Calculate the volume of hydrocarbons generated by the source rock, using
the formula V = A ✕ T ✕ Y ✕ M
potential charge volume
source rock thickness
hydrocarbon yield per volume of source from each
kerogen facies and maturity class
M = migration efficiency
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.
Estimate the efficiency of the migration process. For example, did 20% of
the generated hydrocarbons travel from the source rock to the trap?
Calculate the volume of migrated hydrocarbons available to fill the trap
7-32 • Migration of Petroleum
33. Calculating Charge Volume, continued
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.
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.
Calculating Migration Rate and Charge Volume • 7-33
34. Calculating Charge Volume, continued
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.
Area 3 (1000-m-thick mature source rock)
Yield/volume of source in area 1
10 billion bbl
Area 2 (500-m-thick mature source rock)
Yield/volume of source in area 2
0.5 billion bbl
17.5 billion bbl
Area 3 (200-m-thick mature source rock)
Yield/volume of source in area 3
0.16 billion bbl
0.04 billion bbl
Total generated (areas 1 + 2 + 3)
0.66 billion bbl
27.54 billion bbl
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
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
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
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
Figure 7–13. After Magara (1980); courtesy AAPG.
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.
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
Below is a procedure for estimating expulsion efficiency.
Model the original hydrocarbon generation potential of the source rock
using the estimated original kerogen content.
Measure the volume of hydrocarbons expelled during pyrolosis (S2.)
Estimate the actual expelled hydrocarbon volume by subtracting the S2
value from the original hydrocarbon generation potential of the source
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.
0.0 - 0.2X
Lost Through Time by
Diffusion and Leakage
0.0 - 0.3X
0.0 - 0.3X
Loss en Route
0.0 - 0.3X
Expelled to Reservoir
0.0 - 0.3X
Total Hydrocarbons Generated in Drainage Area
Figure 7–14. From McDowell (1975); courtesy Oil & Gas Journal.
7-36 • Migration of Petroleum
37. Section F
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References • 7-37
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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