Shale as reservoirs?
Posted by D Nathan Meehan June 23, 2010

Shale as reservoirs?
Shales are known to be the principal sources for conventional hydrocarbon plays. They also often function as reservoir seals because of their low permeabilities.  They can also be the reservoir and trap under certain circumstances. Most of the gas created in such reservoirs would be thermogenic in origin although some shales (e.g. the Antrim) have significant quantities of biogenic gas. Gas is stored in shales either as free gas in the pore spaces or adsorbed onto the organic material or surface walls in the shale.

Most coal bed methane (CBM) gas production is dominated by gas that is adsorbed in the micro-porosity of the coal with lesser amounts of free gas present in the natural fractures. Measures of the available gas in a CBM reservoir are generally made with an isotherm as illustrated in the above Figure. In this figure, a Langmuir isotherm is used to describe the gas storage content of the coal. The y-axis is the adsorbed gas content in scf/ton and the x-axis is presssure.
The Langmuir volume of 375 scf/ton in this graph represents the total theoretical volume of gas that can be adsorbed in the coal. The Langmuir pressure is that  (lower) pressure that must be achieved in order for half of the theoretical gas to be recovered. In this example, the initial reservoir pressure is 3210 psi at which the Langmuir isotherm match would have predicted a little over 318 scf/ton of adsorbed gas. In reality, the coal bed methane reservoir only has 281 scf/ton of adsorbed gas and will produce water until the reservoir pressure is reduced to 1700 psi, the critical desorption pressure. The isotherm can then be used to predict the volumes of adsorbed gas that are released until the abandonment pressure is reached.

While this approach is common for screening CBM projects, cores taken from shale gas projects often show relatively small volumes of adsorbed gas with exceptions such as the Antrim shale.

Gas produced from shale reservoirs may either be thermogenic or biogenic or a combination.

Thermogenic gas was formed when organic matter was compressed at  high temperatures (and pressures) for a  long time. Just as in oil formation, thermogenic methane is a cracking process transforming organic particles carried in the clastic materials which became the shales. The nature of the organic material and time and pressure dictate what is formed in thermogenic processes. Thermogenic gas can contain significant quantities of heavier hydrocarbons; however, thermogenic gas may also be nearly pure methane.

Biogenic methane can be formed by microorganisms that chemically break down organic matter. Biogenic methane is generally formed at shallow depths in anoxic environments. While most such methane escapes to the atmosphere, some can be trapped and buried at depth. Modern landfills can also form biogenic methane. Biogenic methane is essentially unrelated to the processes that form oil. Biogenic gas primarily contains methane with very few heavier hydrocarbons. A standard way to determine whether a gas is thermogenic or biogenic is available in gas geochemistry. Thermogenic gas has less 13C compared to the predominant 12C than do biogenic gases.

Next time: A quick look at shale geochemistry

5 responses | Add Yours


Rodolfo Galecio says:

This is really an illustrative article, using a Langmuir isothermal curve we could address the forecasting issue in a CBM reservoir at early stages of development, I would like to know what is the uncertainty related to this method? can we apply this curve in gas shale formations without any restriction?

D Nathan Meehan says:

This technique is well established with CBM reservoirs but cannot be applied independently of many other factors there. It should not be used “without restriction” in shale gas reservoirs! It is in fact quite difficult to quantify recoveries, drainage areas and the degree to which adsorbed gas plays a role in shale gas reservoirs.

I plan on covering shale gas reserve estimation methodologies in more detail.

Yousaf says:

It is very informative article. I would like to have “Shale Gas Reserve Estimation methodologies” from you asap.
Suppose if we don’t have such experiments performed in past on target shale gas reservoir, how we can or calculate Gas Constant then? Can you update? Thanks

D Nathan Meehan says:

We are building such a methodology. Most operators have relied on performance data (decline curve analysis of some type) and analogies. A few use reservoir simulation models with a large number of inherent difficulties. I will definitely be posting more articles in this area once I take a pause from the economics section.

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