What drives the fluid flow during Primary Migration?
How does the hydrocarbon move within a non-reservoir rock (source rock), before it starts heading towards a reservoir rock?
Is it just sufficient for the hydrocarbons within a source rock to over-come the capillary pressure for its successful migration? (The average pore spaces in clay varies between 100 Angstroms and 10 Angstroms for a depth between 1 and 3 km)
Whether the required over-pressure for the expulsion of hydrocarbons from the source-rock is a complex function of multiple variables?
Can the hydrocarbon (in terms of molecular solution or colloidal/micellar solution) within a non-reservoir rock be still treated to be a Newtonian Fluid?
What is the source of water within a non-reservoir rock and which parameter decides it migration behavior?
Does the water assist in moving the hydrocarbons within a source rock?
Capillary pressures in the petroleum system between the porous and non porous rocks. The source rock, which is not porous/permeable is under pressure and the allowance in the reservoir rock causes the movement/migration from source rock with high pressure under gas pressure to reservoir rock that has low pressure due to its porosity.
+ osmose - the passage of a fluids through a semipermeable membrane from a less concentrated to a more concentrated solution until both solutions are of the same concentration 2) diffusion through any membrane or porous barrier, as in dialysis
Pressure difference between source rock and reservoir rock + tectonic factot
There are several factors postulated by several autor which drive hydrocarbons flow during primary migration. The agreed main factor can be explained as follow: Kerogen during burial is a load bearing (overpressured) with the maturation it transform into hydrocarbon fluids which will be more overpressured. Over pressure is causing fractures and hydrocarbons excape, the fracture will close until next generation event and sufficient pressure can restart the process.
I an currently involved in a detailed overpressure study. Ettore Carcione expressed much more elegantly what I will say in a few words: creation of overpressure by hydrocarbon generation followed by an opportunity to move towards larger pore spaces with less pressure.
If the pore pressure becomes higher than the minimum principal stress, the rock will fail (as in the case of hydraulic fracturing). Low-permeability rocks (such as shale, evaporite & etc.), due to the pore waters isolation, typically have a high pore pressure; even in cases they don’t have organic matters. Therefore, in these rocks, a slight increase in pore pressure, due to Kerogen conversion, can cause rock fracturing. These fractures will be closed immediately after creation and their morphology is probably different from stiff rock fractures.
I would like to comment on Mohsen Ezati's response...this is on his comment that evaporites are low-permeability. In fact, if these evaporites are subsurface more than 30 meters, their pore pressure is zero and their ability to transfer pressure from below is also "zero". It would be rare for the pressure to be enough to fracture the salt unless the salt layer is thin. See my salt velocity paper.
To Ms. Cornelius
The cap rock member of the Gachsaran Formation, which is one of the world's famous cap rocks, is located at 1500-2000 m depths. The cap rock member has a thickness of 20 to 40 meters and mainly composed of Anhydrite and Rock Salt. It pore pressure is very high and this member is drilled using about 120 pcf mud weight. Please refer to this paper:
Article Mechanical earth modeling and fault reactivation analysis fo...
It should be noticed that Rock Salt is not the only evaporatic rock; sulfates such as Anhydite, Celestite, Epsomite, Alunite & etc. are evaporatic ,also.
The Failure of evaporatic rocks depends on the stress rate.
To Mohsen Ezati
Thank you for your response...we learn from each other in hopes of all doing better research. I converted your 120 pcf mud weight into something more recognizable for me, and that is 16.04 ppg. In my research area of the deepwater Gulf of Mexico, the top of overpressure is at 13.5 ppg, so by your mudweight you
are in "medium" overpressure, not yet at "hard" overpressure, which begins around
17.0 ppg. In the deepwater Gulf of Mexico, the salt canopy varies in thickness and in mineralogical composition (mostly halite with gypsum, anhydrite, sylvite and some clastic sediment incorporated due to salt movement). The top of salt can be close to the seafloor or as deep as 6000 m BUT MUD WEIGHTS VARY WITH DEPTH AND/OR THE PRESENCE OF OVERPRESSURE FROM SHALE DIAGENESIS, SHALE DISEQUILIBRIUM, HYDROCARBON GENERATION, AND/OR PORE PRESSURE INCREASE CAUSED BY FAULTS OR SALT MOVEMENT. I have studied hundreds of well logs in this region and nowhere do the mud weights increase simply by being inside salt. I might add that the salt thickness varies from 100 m to 6000 m, but its thickness has no bearing on the pressure INSIDE THE SALT. We do not observe failure of salt, the salt is more "plastic" and moves basin-ward very slowly over geologic time scales.
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