Hello Ijaz, Petroleum Geology holds that hydrocarbons migrate from source rock into a poorly understood receptacle and moves from there to the reservoir rock owing to bouyancy resulting from density differences. The mechanisms include 1. Diffusion: Because of differing concentrations of the fluids in the source rock and the surrounding rock there is a tendency to diffuse. This is a widely accepted theory. 2. Migration by molecular solution in water: While aromatics are most soluble in aqueous solutions, they are rare in oil accumulations, therefore discrediting the general importance of this mechanism, although it may be locally important. 3. Migration along micro-fractures in the source rock: During compaction the fluid pressures in the source rock may become so large that spontaneous “hydrofracing” occurs. This is a useful but underestimated hypothesis. 4. Oil-phase migration. This provides a continuous oil-wet migration path along which the hydrocarbons diffuse along pressure and concentration gradient. This is a reasonable but unproved hypothesis, good for high TOCs. I hope these help.

The book to read:

Magoon, L.B., and W.G. Dow, eds. 1994. The petroleum system – from source to trap: AAPG Memoir 60

Tissot, B. P. and D. H. Welte (1984). Petroleum Formation and Occurrence

Part III

The Migration and Accumulation of Oil and Gas

J.M. Verweij (1993). Hydrocarbon Migration Systems Analysis

As U. know, generation of hydrocarbons form organic matters occurs in fine sedimentary rocks. Then hydrocarbon moved from host rocks into permeable & porous rocks to form an accumulation. The movement of hydrocarbons from non-reservoir rocks to reservoir rocks is the method of primary migration. It differs from the secondary migration method of oil concentration and accumulation in reservoir rocks themselves. Primary migration includes the form in which they migrate, such as molecular solution, micellar solution, and separate hydrocarbon phase, causes of migration, and water source and movement. Secondary hydrocarbon migration includes migration under hydrostatic conditions, hydrodynamic conditions, and regional aspects of secondary hydrocarbon migration. Secondary migration system is characterized by the masses and initial composition of petroleum (hydrocarbons) available for secondary migration, the three-dimensional migration pattern, the flux of migrating hydrocarbons, and the migration losses. Secondary hydrocarbon migration systems are classified according to the dominant force or combination of forces affecting migration. In hydrostatic one, the separate phases of hydrocarbons are moved by buoyancy forces mainly depending on hydrocarbon-water density differences and capillary forces. The tectonically-induced lateral driving force for groundwater flow in basins near zones of plate convergence and continental collision may enhance lateral migration of hydrocarbons through available carrier rocks in the basins away from the active zones. The length of the path of secondary hydrocarbon migration may be a few meters to hundreds of kilometers laterally, and a few meters to kilometers vertically.

Developments in Petroleum Science

Volume 35, 1993, Pages 121-160.

Dear Ahmed,

(Primary) migration form the source rock can be as a discrete oil and gas phase or in solution. The former can be related to 1) compaction or dewatering of clay minerals, 2) in a network of kerogen for very rich source rock with high kerogen contents, 3) overpressure and microfracturing/hydrofracturing/tectonic fracturing. The later is dependent on the amount of water that dissolve the hydrocarbons, temperature and solubility, molecular wt. of hydrocarbons etc. Migration (including secondary migration) can be triggered by rapid glacial/sediment loading/unloading, erosion/uplift, polygonal faulting etc.

I hope this could help you for further reading.

Regards,

Mohammed

Complements to a set of great answers! The two main factors controlling successful (conventional petroleum system) HC migration are effective porosity and rock permeability which are a function of the lithology,rock compaction trends (sedimentary rocks), etc. In addition to the age i.e. exposure to different P-T conditions, overburden, sealing capacity, (depending of regional tectonics) faults could represent either major fluid barriers or liquid/gas conduits.

Migration of hydrocarbon from source rock to reservoir rock can be either primary, secondary or tertiary migration.

Primary Migration can occur in three ways. First, migration by diffusion. This is the spreading of the Hydrocarbon as a result of a concentration gradient. This process leads to dispersal rather than accumulation. Diffusion rates in porous media are very low. Methane, the HC with the highest diffusion coefficient, is estimated to take 80 Ma to diffuse a distance of 1 km.

Second, migration also occur in aqueous solution. Here, methane is widely distributed in the subsurface because of its solubility in pore fluids and its high mobility as a gas phase. Solubilities decrease with increasing pore fluid TDS, decreasing pressure and temperature, and increasing HC saturation.

Lastly, primary migration can also occur as hydrocarbon phases.

Most migration of petroleum takes place by flow of a hydrocarbon liquid or gaseous phase through microfractures in the source rock. Matrix permeabilities for source rocks range from 1 to 10-8 md or 10-15 to 10-23 m2 . These low values are unlikely to be sufficient for migration. A few microfractures can increase permeability by many orders of magnitude.

During secondary migration , the main force is the buoyancy of hydrocarbons. There is a tendency for oil and gas to segregate from aqueous phase liquids because of density differences. If capillary and buoyancy forces are matched, hydrocarbon can be trapped within a particular lithology. Hydrodynamic traps of this kind are found in western Canada when gas is found down-dip and below water saturated rocks.

read this article through the link below too

https://ocw.tudelft.nl/wp-content/uploads/PGeo_L4_Petroleum_Geology_-_Lecture_4_08.pdf

Check this publication "Mechanics of Secondary Hydrocarbon Migration and Entrapment by Tim T. Schowalter".

Good luck

You can also read Hydrocarbon Migration Systems Analysis by By J.M. Verweij for more details.

Cheers

Normally just one fluid (water) is found under ground. In a hydrocarbon basin two additional fluids i.e. oil and gas also exist; in terms of specific gravity these fluids range from lightest gas to oil and water, respectively. The hydrocarbons are generated in a source rock, which is normally a shale. The problem with shale is that it has higher porosity, but very low permeability. Conversely, a reservoir has lower porosity than a shale, but higher permeability. The micro droplets of generated oil and gas, thus, remain stuck in isolation in the source rock. Subject to compaction and varying physical parameters, the isolated globules start moving from higher pressure to the areas of lower pressure. This movement is facilitated by either the opening of a microscopic 'neck' between the two adjacent globules or the development of fracture system. Here, the dominant force is density that allows gas to move up first than oil; water is immovable.

As the globules reach a higher porosity area they get larger and larger in size and the buoyancy gets support of gravity segregation within three fluids. Reaching a reservoir and a trap, the gas occupies the highest place underlain by oil and water, respectively. This is one simple and basic scenario, and is designated as primary migration. Sometimes the process requires hydrocarbons to travel long distance where the source and reservoir are far apart, like the Cretaceous shale and sand sequence in southern Pakistan. This setup was subjected to extensional regime resulting in horst- graben geometry. The tectonics has resulted in open and sealed faults that run from the source rock deep down, to the overlying sand reservoir way up. The open faults are interpreted to provide the conduit's for hydrocarbon migration and the sealed faults, apart from the up dip pinch-outs, provide the barrier. This process requires millions of years for the accumulation to become commercially viable. The Earth is live and dynamic. With tectonics, the geometry of the traps get disturbed and even hydrocarbons are lost to the atmosphere. The subsurface changes result in the secondary migration to the the newly created higher regions and traps.

Ijaz Ahmed, I am not very fond of using technical jargon, which you may find missing. But hope, you find it helpful.

You can also check Chapter No. 5 (Generation and Migration of Petroleum) in "Elements of Petroleum Geology" 3rd Edition, 2014, by Richard Selley and Stephen Sonnenberg.

I tell you more, if you if you invite other ten person and pay for my lessons 2000 USD/ person, Bfoere 1000 after another 1000 if you it was useful)… My model is not verified, only the initial form, when I have worked in petroleum exploration…Was minimum twice better than my Hungarian colleagues method… When I wanted to apply at Saudi Aramco, I have send to them, but they did not answered for me. No problem I have made it more better. And I know same that they did not write study about it. ( If you are interested: I can write a booklet for you with 100 USD... But this time need minimum 400 buyers of booklet: they are putting down the price of booklet at an international law firm. You can sell the booklets for 120 USD and same Time I will give you 10 percent) the initial condition can be changed same).

The Basic formula of HC is very simple, You have need four important things:

1.) The source rocks of Hydrocarbon

2.) Reservoir rocks

3.) The conditions which lead the HC from the sources to reservoirs.

4.) if you do not have expensive tools, the knowledge which help you to find the correct reservoir rock.

The Best Regards,

László

Migration can begin with primary one, which is movement from source rocks to reservoir rocks. Further, secondary porosity in reservoir rock leads to secondary migration from initial reservoir rock to a more porous rocks. Details of this can be seen in a number of resources given above by Ahmed Abdelmaksoud, Ebong etc.

From kerogen which has a density of ~1.2 g/cc to hydrocarbons, with progressively lower density, 0.8 to 0.1g/cc, the volume expands by a factor of 2 to 5. There is not enough room for the HC in the source rock, so excess gets pushed out by capillary pressure linked to volume increase (like injecting). Increased capillary pressure pushes hydrocarbon phase trough the largest pore throat around it, could be above or below (note buoyancy force does not cause downward migration). When the next pore, patch of pores, or a trap is filled, the process continues, always finding the direction of largest pore throat. In the case of filling a large trap, it fills from top to bottom (downward migration again), and spills out, or if the capillary pressure is high enough, it leaks through the top seal, and continues. This process stops when the volume increase stops. This is much like you taking a bottle of water and poring slowly onto the street, .. and watch it flow and stop when you run out of water.