scholarly journals Numerical modeling of porosity waves as a mechanism for rapid fluid transport in elastic porous media

2015 ◽  
Author(s):  
◽  
Ajit Joshi
Keyword(s):  
Porous Media ◽  
Fluid Transport ◽  
Fluid Pressure ◽  
Source Rocks ◽  
Lithostatic Pressure ◽  
Accretionary Wedge ◽  
The World ◽  
Porosity And Permeability ◽  
High Fluid ◽  
High Fluid Pressure

The rapid ascent of fluids through kilometer-scale thicknesses of low permeability sediments at rates much faster than predicted Darcy fluxes has been observed in numerous locations around the world. A consistently observed condition associated with this anomalously rapid fluid flow is high fluid pressure approaching lithostatic pressure. This high fluid pressure can be produced by a number of geologic processes, including the production of hydrocarbon fluids by maturation of organic matter, the production of water through dehydration reactions of hydrous minerals, compaction disequilibrium during the deposition and burial of sediments, and earthquakes. As fluid pressure increases in a deformable porous medium, the pore spaces in the medium expand, increasing porosity and permeability. This zone of increased fluid pressure, porosity, and permeability, termed a porosity wave, may travel much faster than fluids flowing at Darcy fluxes in the surroundings, provided that permeability is a sensitive function of fluid pressure or effective stress. In addition, because porosity waves have higher porosity than their surroundings, they can serve as a mechanism for enhance fluid transport. The main goal of the present study was to evaluate the formation and fluid transport capabilities of porosity waves in elastic rocks. The study was performed using a numerical solution to a mass conservation equation for fluids in porous media and Darcy's law. Results of the study show that rates of fluid pressure generation by sediment compaction disequilibrium and hydrocarbon formation in porous media saturated with dense and viscous fluids like oil or water can generally only form porosity waves at depths below ~4 km, and are unable to form porosity waves in porous media saturated with low density and viscosity fluids like methane. In order to form porosity waves in methane-saturated porous media, geologically instantaneous rates of fluid pressure generation are needed, which may be possible from earthquakes. Once formed, methane-saturated porosity waves may travel at speeds of ~10's of m per year for distances of 1-2 km under geological conditions similar to those of the Eugene Island hydrocarbon field in the Gulf of Mexico basin, one of the focus areas of the present study. However, porosity waves are unlikely to have played a major role in transporting methane to shallow reservoirs at Eugene Island. This is in part because Eugene Island appears to have been seismically quiescent throughout its geological history and because most of the reservoirs are separated by more than two kilometers from the hydrocarbon source rocks. In the Nankai accretionary wedge, another focus area of the present study, results show that porosity waves formed at a depth of ~2 km can ascend along the decollement at the minimum 1's of km per day velocities needed to cause aseismic slip, provided that fluid pressures in porosity source region either exceed lithostatic pressure or are slightly below lithostatic pressure but other hydrogeologic parameters are near the limits of their geologically reasonable ranges. Though the present study was focused on two specific field sites, the results have implications for rapid fluid transport in other geologically similar environments in other locations around the world.

scholarly journals An inorganic origin of the “oil-source” rocks carbon substance

Georesursy ◽  
2021 ◽  
Vol 23 (3) ◽  
pp. 164-176
Author(s):  
Sergey A. Marakushev ◽  
Olga V. Belonogova
Keyword(s):  
Black Shale ◽  
Hydrogen Pressure ◽  
Fluid Pressure ◽  
Black Shales ◽  
Source Rocks ◽  
Alkaline Magmatism ◽  
Oil Hydrocarbons ◽  
High Fluid ◽  
High Fluid Pressure ◽  
Phase Relationships

On the basis of an inorganic concept of the petroleum origin, the phase relationships of crystalline kerogens of black shales and liquid oil at the physicochemical conditions of a typical geobarotherm on the Texas Gulf Coast are considered. At the conditions of the carbon dioxide (CO2) high fluid pressure, the process of oil transformation into kerogens of varying degrees of “maturity” (retrograde metamorphism) takes place with decreasing temperature and hydrogen pressure. Kerogen generation in black shale rocks occurs by the sequential transition through metastable equilibria of liquid oil and crystalline kerogens (phase “freezing” of oil). The upward migration of hydrocarbons (HC) of oil fluids, clearly recorded in the processes of oil deposit replenishment in oil fields, shifts the oil ↔ kerogen equilibrium towards the formation of kerogen. In addition, with decreasing of the hydrogen chemical potential as a result of the process of high-temperature carboxylation and low-temperature hydration of oil hydrocarbons, the “mature” and “immature” kerogens are formed, respectively. The phase relationships of crystalline black shale kerogens and liquid oil under hypothetical conditions of high fluid pressure of the HC generated in the regime of geodynamic compression of silicate shells of the Earth in the result of the deep alkaline magmatism development. It is substantiated that a falling of hydrogen pressure in rising HC fluids will lead to the transformation of fluid hydrocarbons into liquid oil, and as the HC fluids rise to the surface, the HC ↔oil ↔ kerogen equilibrium will shift towards the formation of oil and kerogen. It is round that both in the geodynamic regime of compression and in the regime of expansion of the mantle and crust, carboxylation and hydration are the main geochemical pathways for the transformation of oil hydrocarbons into kerogen and, therefore, the most powerful geological mechanism for the black shale formations.

Mélanges and disrupted rocks at the leading edge of the Humber Arm Allochthon, W. Newfoundland Appalachians: Deformation under high fluid pressure

2019 ◽  
Vol 74 ◽  
pp. 216-236 ◽  
Author(s):  
Ryan A. Lacombe ◽  
John W.F. Waldron ◽  
S. Henry Williams ◽  
Nicholas B. Harris
Keyword(s):  
Fluid Pressure ◽  
Leading Edge ◽  
High Fluid ◽  
High Fluid Pressure

scholarly journals Permeability Evolution of an Intact Marble Core during Shearing under High Fluid Pressure

Geofluids ◽  
2021 ◽  
Vol 2021 ◽  
pp. 1-18
Author(s):  
Yuan Wang ◽  
Yu Jiao ◽  
Shaobin Hu
Keyword(s):  
Normal Stress ◽  
Laser Scanning ◽  
Shear Failure ◽  
Fluid Pressure ◽  
Shear Displacement ◽  
Permeability Evolution ◽  
Fracture Permeability ◽  
Effective Normal Stress ◽  
High Fluid ◽  
High Fluid Pressure

The progressive shear failure of a rock mass under hydromechanical coupling is a key aspect of the long-term stability of deeply buried, high fluid pressure diversion tunnels. In this study, we use experimental and numerical analysis to quantify the permeability variations that occur in an intact marble sample as it evolves from shear failure to shear slip under different confining pressures and fluid pressures. The experimental results reveal that at low effective normal stress, the fracture permeability is positively correlated with the shear displacement. The permeability is lower at higher effective normal stress and exhibits an episodic change with increasing shear displacement. After establishing a numerical model based on the point cloud data generated by the three-dimensional (3D) laser scanning of the fracture surfaces, we found that there are some contact areas that block the percolation channels under high effective stress conditions. This type of contact area plays a key role in determining the evolution of the fracture permeability in a given rock sample.

scholarly journals Rules for Flight Paths and Time of Flight for Flows in Porous Media with Heterogeneous Permeability and Porosity

Geofluids ◽  
2017 ◽  
Vol 2017 ◽  
pp. 1-18 ◽  
Author(s):  
Lihua Zuo ◽  
Ruud Weijermars
Keyword(s):  
Porous Media ◽  
Fluid Transport ◽  
Initial Conditions ◽  
Time Of Flight ◽  
Flight Path ◽  
Flow In Porous Media ◽  
Transport Mechanisms ◽  
Local Porosity ◽  
Fluid Properties ◽  
Porosity And Permeability

Porous media like hydrocarbon reservoirs may be composed of a wide variety of rocks with different porosity and permeability. Our study shows in algorithms and in synthetic numerical simulations that the flow pattern of any particular porous medium, assuming constant fluid properties and standardized boundary and initial conditions, is not affected by any spatial porosity changes but will vary only according to spatial permeability changes. In contrast, the time of flight along the streamline will be affected by both the permeability and porosity, albeit in opposite directions. A theoretical framework is presented with evidence from flow visualizations. A series of strategically chosen streamline simulations, including systematic spatial variations of porosity and permeability, visualizes the respective effects on the flight path and time of flight. Two practical rules are formulated. Rule  1 states that an increase in permeability decreases the time of flight, whereas an increase in porosity increases the time of flight. Rule  2 states that the permeability uniquely controls the flight path of fluid flow in porous media; local porosity variations do not affect the streamline path. The two rules are essential for understanding fluid transport mechanisms, and their rigorous validation therefore is merited.

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