Julie Asks PERM:
I have two main questions if you could help me:
-How to choose the pressure of gas if we want to measure the permeability of a reservoir rock?
-When doing the saturation, is it possible that the pore volume is much higher than the fluid volume, if yes, what could be in the exceeding pore or what could be the reason of it? For example, if the saturation inside the pore is 30% water and 20% bitumen, but there is no gases in this reservoir. So I’d like to ask if it is possible because I don’t know what is inside the remaining 50% of the pore.
I am new at this group, maybe I didn’t see yet all the documents here, if there are some if you could suggest me,
Dr. Jonathan Bryan from PERM Answers:
When measuring gas permeability of a reservoir rock, there are a couple of things to remember. First, permeability is a rock property, and should not be affected by the pressure of the fluid in the pore space, unless that fluid pressure is high enough to expand pores and alter porosity. Let’s assume that this isn’t what you mean. In the case of gas flowing through the rock pores, pressure matters because at lower values molecules of gas slip along the rock surfaces, leading to enhanced flow for a given pressure drop. This is known as the Klinkenberg effect, and it is addressed by measuring permeability at several values of mean pressure (i.e. permeability vs. 1/Pm, where Pm = (Pin + Pout)/2). The data are fitted to a linear expression, and the y-intercept is absolute permeability for a system of infinite pressure, where gas behaves like a liquid. Note that this data is not always reported, because it takes longer to acquire permeability at different pressures, so sometimes labs just report one value of permeability (i.e. permeability measured for just one flow rate value). PERM prefers the steady state approach (multiple flow rates) and the Klinkenberg correction for the gas. Operationally, the choice of pore pressure is defined by your equipment. Of course higher pore pressures are better, but not all measurement systems are designed to be run at high pressures. Most air permeability rigs assume that the core is left at ambient pore pressure, and flow rate is measured at this condition.
Yes, unfortunately this is a common occurrence when dealing with core samples. Remember that in the reservoir everything is under pressure, but when we bring the fluids to the surface, there is a lot of expansion and this drives significant fluid out of the rock. So whenever we measure fluid saturations we always get total fluid that is less than the actual porosity of the system. Now the tricky part is figuring out what was lost – oil or water or both. There is no easy answer to that. You could look at the initial water saturations and compare that to irreducible water saturations from something like a relative permeability test, but probably you don’t have relative permeability or end point saturation data. So you could also go and compare against your logging tool data, but that requires (a) good log-core depth correction on your data and (b) a way to quantify your log resistivity information. I wish there was an easy answer to this, but it is one of the big problems with working with core data. The best advice we can give you is to review your core data along with all other information you have, and try to find answers that have fidelity to most of your data.
Dr. Jonathan Bryan