Primary
migration is the process by which hydrocarbons are expelled from
the source rock into an adjacent permeable carrier bed.
Paradox: Most source rocks are black shales which have very low permeabilities. How can the hydrocarbons move through these rocks?
Processes that have been proposed involve either the transport of hydrocarbons in solution, or their diffusion through shales, or migration of an independent hydrocarbon phase either as oil or gas.
Solution: The solubility of hydrocarbons is water is very low, usually less than 50 ppm. Exceptions are methane, benzene and toulene which may have solubilities of 500 to 2000 ppm at reservoir conditions. Solubility is enhanced by increasing temperature, but within the oil window temperatures are too low to make any difference. In summary, the volumes of water required to move the hydrocarbons found in a normal oil field would huge due to the low solubility. So this is not an important mechanism for primary migration.
Micelles are molecules that behave like soap, attaching themselves to a hydrocarbon molecule on one end and to an OH- at the other end. These could increase the amount of hydrocarbons transported by water. However, micelles are not found in rocks in sufficiently large quantities to explain most hydrocarbon accumulations.
Diffusion of most hydrocarbons through rocks is also exceedingly slow. Methane can diffuse through shales, but very slowly. This helps to explain why small quantities of methane can be detected in many sedimentary rocks, but cannot explain the formation of any significant gas deposit. Molecules larger than butane are to big to move by diffusion at all.
Gas
phase migration- Compressed gas can dissolve liquid hydrocarbons.
For example at 5000 psi (conditions found at about 10,000 feet)
methane and decane (C1 and C10) form a single gas phase. Migration
of hydrocarbons dissolved in the gas phase can facilitate the
movement of hydrocarbons through the source rock, as the gas
phase migrates into shallower regions where temperature is lower,
the liquid hydrocarbons come out of solution. However, the gas/oil
ratio of most oil fields is too low for the gas to be the only
means of transporting the oil out of the source rock. Also at
the onset of generation most the kerogen produces little gas,
most gas is generated late during the maturation history.
Oil
Phase Migration- Most hydrocarbons probably are expelled
from the source rock as liquids. The expulsion of the oil out
of the source rock is a dynamic process driven by the oil generation
itself. Good source rocks have TOC (total organic content) ranging
from 3 to 10%. At low TOC the kerogen may occupy a position within
the matrix porosity of the rock, at high TOC the kerogen can
form connected bands within the rock. Then the kerogen is bearing
part of the lithostatic load. As the organic matter transforms
into oil this load-bearing kerogen turns into liquid. The fluid
pressure of the oil within the black shales can become high enough
to produce microfractures in the rock. 
Once the microfractures
form, the oil is squeezed out and the source rock collapses.
So primary migration can be viewed as a second episode of compaction.
Microfractures of this type can be seen in most productive source
rocks and they are often filled with remnants of oil.
In
order for expulsion to take place a minimum level of saturation
of the source rock with oil must be reached. This minimum level
depends on the viscosity ratio between the oil and the water.
Low viscosity oils can be expelled at low saturation (less than
10%), high viscosity oils require saturations larger than 50%.
This means that the efficiency of generation is greater for low
viscosity (high API) oil than for high viscosity (low API).
- What is the distinction between primary
and secondary migration?
- Explain how hydrocarbons are expulsed from the impermeable source rock.
- Is the transport of hydrocarbons in water a viable mechanism for primary migration?
- Do hydrocarbons get expelled as soon as the kerogen is transformed into oil?
- References:
Hunt, John M., Petroleum geochemistry and geology, NY : , W. H. Freeman and Company, , 1996, 743 p.- Palciauskas, V. V. "Primary migration of petroleum", in: Merrill, Robert K. , editor, Source and migration processes and evaluation techniques, Tulsa, OK : Am. Assoc. Pet. Geol.,1991; p. 13-22.
- Explain how hydrocarbons are expulsed from the impermeable source rock.
Secondary migration is the movement of hydrocarbons along a "carrier bed" from the source area to the trap. Migration mostly takes place as one or more separate hydrocarbons phases (gas or liquid depending on pressure and temperature conditions). There is also minor dissolution in water of methane and short chain hydrocarbons.
Driving forces for migration:
- Buoyancy (This force acts vertically and is proportional to the density difference between water and the hydrocarbon so it is stronger for gas than heavier oil)
- Hydrodynamic flow (water potential deflect the direction of oil migration, the effect is usually minor except in over pressured zones (primary migration))
Resisting
forces:
- Capillary pressure (opposes movement of fluid from coarse-grain to fine- grain rock, also the capillary pressure of the water in the reservoir resists the movement of oil)
One
result of hydrodynamic flow is a tilted oil-water contact
(OWC) in a trap. OWC is an equipotential surface, but if the
water is flowing the equipotential surfaces are inclined in the
direction of flow, so the OWC will be tilted too.
During migration the pressure and temperature conditions of the hydrocarbons can change a lot affecting the phase behavior of the oil.
Example 1: Type I, oil prone source rock during peak generation produces oil with a gas-oil ratio (GOR) of 0.2 kg/kg (1000 cf/bbl). At depths greater than ~10,000 ft all the gas can be dissolved in the oil.Migration will be as a single liquid hydrocarbon phase. Above ~10,000 ft the gas will begin to exsolve, like opening a soda can. At that point two hydrocarbon phases will migrate together.
Example 2: A gas-prone source rock produces a gas condensate with high proportion of dissolved liquid C6+ hydrocarbons. As pressure and temperature drop the C6+ fraction will condensate as a minority liquid phase.
Rate of migration is controlled by Darcy's law q= -k/v dp/dz (for a single fluid phase)
where q=volumetric flow rate, k=permeability, v=viscosity, dp/dz=pressure gradient.
Given typical permeabilities of sandstone, and flow rate of oil can range from 1 to 1000 km per million years. This is faster than rate of generation and expulsion, so oil generation is the rate-limiting factor.
Because
the carrier bed has to reach a minimum oil saturation before
oil can flow, there is a volumetric loss associated with migration.
The oil will seek a tortuous path of least resistance which typically
will be a small portion of the total carrier bed volume.
Very
long horizontal migration distances have been documented in some
basins, in the Alberta basin of Canada the oil has migrated more
than 400 km. In other cases the dominant direction of migration
is vertical following fault or fracture systems, such as some
accumulation in the North Sea.
- What forces drive hydrocarbon migration?
What forces oppose migration?
- How far can hydrocarbons migrate?
- What role do faults play in the migration of oil and gas?
- Explain capillary pressure and its role in oil migration.
- How do the change of temperature and pressure with depth affect hydrocarbon migration?
- Is migration 100% efficient? Explain the losses that can occur during migration.
- How far can hydrocarbons migrate?
- References:
- Effective porosity vs. total porosity
- Types:
- Primary porosity
- Secondary porosity
- Porosity in Clastic rocks vs Carbonate
rocks
- Relationship between porosity and permeability
- Depositional aspects:
- Relationship between porosity and permeability
- Composition
- Sorting
- Rounding
- Grain size
- Rounding
- Packing
- Sorting
- Diagenesis:
- Dewatering
- Compaction
- Cementation
- Compaction
What is good porosity? - 0-5% - Negligible
- 5-10%- Poor
- 10-15%- Fair
- 15-20%- Good
- >20% - Very good
- 5-10%- Poor
- Practical cut off for oil
- Sandstone ~8%
- Limestone ~5%
- For gas the cut off is lower
- How do we measure porosity?
- 0-5% - Negligible
This microphotographs illustrates the typical components of a sandstone reservoir: quartz grains (gray), secondary quartz cement (also gray), pore space (dark), and secondary minerals in the pore spaces (brownish). Notice that the original grains are well rounded, but the quartz cement is forming a polygonal crystal. 
This is an example of well-rounded, clean sandstone. The green area is open pore space. This rock has high porosity and probably high permeability also. 
Poorly sorted coarse sandstone. The spaces between the large, well-rounded grains are filled by small angular fragments in a dark clay-rich matrix. This rock has very low porosity and permeability. 
This is a sandstone that has been completely cemented. It is now a quartzite: a metamorphic rock with no porosity left. Notice that irregular grain boundaries, like a jig-saw puzzle.This is the result of pressure solution under high stress conditions. Pressure solution causes the grains to indent each other at the points of contact. 
This is an oolitic sandstone with most of the primary porosity (space between the round oolites) filled with secondary quartz crystals.
- This is the key parameter in determining
reservoir quality. Many rocks (shales for example) have high
porosity, but very low permeability. Determined from Darcy's
law.
- Main controls on permeability are:
- Grain size (determines the size of
the pore throats)
- Pore connectivity
- Pore connectivity
Effective permeability:
When multiple fluids are present they interfere with each other.
So that the effective permeability of the moving fluid is much
lower than if a single fluid is present. In a typical reservoir
at least water and oil are present, frequently water, oil, and
gas share the pore space.
-
What is good permeability? - <1 millidarcy - Poor
- 1-10 md- Fair
- 10-100 md- Good
- 100-1000 md- Very good
- 1-10 md- Fair
- Compaction
- Cementation
- Heavy hydrocarbon residue
- Cementation
- Dissolution
- Fracturing
- Dolomitization
- Fracturing
- Reservoirs are heterogeneous in both
vertical and horizontal dimension at all scales. This is due
to Stratigraphic facies changes, faults, variation in diagenetic
features such as cementation or dissolution, etc. A huge body
of data is needed to adequately characterize most reservoirs.
Most often reservoir barriers are revealed by the pressure history
of neighboring wells.
- What characteristics of sandstone reservoir would you look for to find a good reservoir rock. Think in terms of composition, of texture, and of history of the sandstone after deposition.
- How does the presence of multiple fluids in a reservoir affect the permeability to any one of them?
- Discuss the relationship between porosity and permeability in a sandstone, ... in a shale, ... in a limestone.
- Which natural processes enhance reservoir quality? Which processes decrease it?
- Why is permeability so hard to predict?
