Effective Porosity: Feasible to measure?
Since, most of a 'petroleum reservoir cross section' remains occupied ‘by rock’ and ‘by oil and water’ that remains securely attached to the rock surfaces by molecular attraction, the ‘actual’ area through which ‘the water and oil keeps flowing’ is definitely going to be lesser than the ‘total’ reservoir cross sectional area of the oil and water bearing petroleum reservoir. In this context, would it remain feasible to deduce this ‘reduced cross-sectional area’ through the fluid (oil and water) keeps flowing?
Is there a way to grab the details on the effects of ‘attached water and oil’ that would probably help us to deduce the extent by which the ‘effective-porosity’ has been reduced from its actual value?
To what extent, this effective porosity would influence the resulting migration of ‘water flow’ and ‘oil flow’?
To what extent, the 'reservoir pressure' would influence the resulting 'effective porosity' associated with a sandstone and a carbonate reservoir?
Is there 'a straight-forward method' to determine the effective-porosity of a petroleum reservoir? If any such direct method exists, then, what exactly (which force) is supposed to drain ‘water and oil’ from those inter-connected pore-spaces?
Feasible to precisely estimate the volume of water and oil that remains retained by the petroleum reservoir as ‘specific retention’ (volume of oil and water that cannot easily drained by free gravity)?
In the absence of precise value on effective porosity, how do we deduce the ‘oil flow rate’ and ‘water flow rate’ exactly?
How do we have a control over the details on
(a) the degree of compaction encountered by matrix-porosity (microscopic porosities); and on
(b) the degree of intensity of fracturing – resulting from overlying rock mass – as a function of depth - towards estimating 'effective porosity'?
To what extent, the extent of ‘effective porosity’ associated with the matrix (primary) and fracture (secondary porosity) in soluble carbonate reservoirs 'gets modified' by 'the process of karstification or dissolution of carbonate minerals' by 'flowing brine containing weak carbonic acid' (assuming major oil fields around the globe remain hosted in limestone and dolomite reservoirs, which keep encountering various depositional environments and processes of its diagenesis)?
When the diameter and throat size, in general, have no relation to sedimentary particle size or sorting in a carbonate reservoir, how do we then deduce the ‘average pore sizes’ in a carbonate reservoir associated with low-permeable rock-matrix; and how exactly, we deduce the 'average fracture aperture thickness' associated with the high-permeable fracture-network?
Yes, it is feasible to measure the effective porosity of a petroleum reservoir using various techniques such as core analysis, well logging, and seismic imaging. However, it is important to note that effective porosity is a dynamic property that changes over time due to fluid flow and rock deformation.
2. Is there a way to determine the extent to which effective porosity is reduced by attached water and oil?
Yes, laboratory experiments can be conducted to determine the impact of attached water and oil on effective porosity. These experiments involve saturating rock samples with fluids and measuring the resulting change in porosity.
3. How does effective porosity influence water and oil flow in a reservoir?
Effective porosity is a critical property that determines the ability of fluids to flow through the rock matrix. A higher effective porosity generally leads to a higher flow rate of oil and water.
4. How does reservoir pressure influence effective porosity in sandstone and carbonate reservoirs?
Reservoir pressure can have a significant impact on effective porosity, particularly in carbonate reservoirs. Increased pressure can lead to the dissolution of carbonate minerals and the creation of new porosity, while decreased pressure can cause compaction and reduction of porosity.
5. Is there a straightforward method to determine effective porosity, and what force drains oil and water from pore spaces?
There is no one-size-fits-all method for determining effective porosity, and multiple techniques may need to be used to obtain accurate measurements. The force that drains oil and water from pore spaces is generally a combination of capillary forces and gravity.
6. Is it feasible to estimate the specific retention volume of water and oil in a reservoir?
Yes, it is feasible to estimate the specific retention volume of water and oil in a reservoir using laboratory experiments and reservoir simulation software.
7. How do we determine oil and water flow rates in the absence of precise effective porosity values?
In the absence of precise effective porosity values, flow rates can be estimated using empirical correlations based on well log data or reservoir simulation software.
8. How do we control the degree of compaction and intensity of fracturing in estimating effective porosity?
The degree of compaction and intensity of fracturing can be controlled by using advanced drilling techniques and optimizing production strategies based on reservoir properties and geomechanical models.
9. How does karstification or dissolution of carbonate minerals impact effective porosity in carbonate reservoirs?
Karstification and dissolution can significantly increase effective porosity in carbonate reservoirs by creating new pore spaces and enlarging existing ones. However, the impact of these processes can be complex and depend on various factors such as the type of carbonate minerals present and the fluid chemistry.
10. How do we determine average pore sizes and fracture aperture thickness in a carbonate reservoir?
Average pore sizes and fracture aperture thickness can be determined using various techniques such as core analysis, well logging, and imaging. However, it is important to note that these properties can vary significantly across different regions of a reservoir and at different depths.
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