I would like to discuss a idea which Faith brought up, that “deep age isn’t testable or provable in any way”, which when applied to petrology leads to the claim (see ,):
Age is irrelevant to the task of finding oil by stratigraphic means
A demonstration that “deep age” is more than an ideological construct of mainstream geology can be found for example in basin modeling , a set of methods which is used by the oil industry for oil exploration. The problem is to get an adequate understanding of the potential of an assumed oil field with sparse input data - for example by drill holes or seismic measurements. That’s a bit like a puzzle: We have only some pieces at hand and try to guess the whole picture. But there is at least one important difference to solving a puzzle: a geological model does not simply generate a way to connect the dots, it tries to reconstruct the development of a sedimentary basin based on well known and quantifiable processes like conductive cooling, erosion, tectonic uplift, which in most cases require geological time spans.
An example would be the modeling of the thermal history of a basin, which covers the "magnitude of maximum paleotemperatures in individual samples", "the timing of cooling from maximum paleotemperatures" and the "style of timing" to name only the most important aspects. This information is used to determine the thermal maturity for source rocks - that are rocks which (possibly) generate petroleum - when direct measurements are not available. Maturation is the process whereby hydrocarbon is formed from kerogen. This important change occurs only when kerogen is subjected to high temperature over long periods of time. A simple way to model this behavior is to calculate a measure called TTI, the time-temperature index. It uses a time factor, which is the time interval for a certain temperature (in millions of years) and a temperature factor which increases exponential, by a factor of 2 for every 10°C. By multiplying both factors one obtains a dimensionless number, the interval TTI, which represents the maturity acquired by the rock at given time interval and temperature. The total TTI is calculated by summing up incremental maturity values which when calculated over the whole time span gives a good measure for the overall maturity of the source rock. (see )
Maturity in combination with type and amount of the organic material present in a source rock (measured as TOC) gives a good indication whether drilling is recommendable or not. (see )
Before deciding what to do about this post, please have a look at my request for clarification .
First of all, please excuse my late answer - as I have already explained in my email, Iâ€™m hard pressed to meet a deadline end of September, so thereâ€™s little time left to participate in discussions. I expect things to improve in October. And it's great that youâ€™re interested in petroleum geochemistry and eager to learn more about it, but Iâ€™m a bit skeptical whether you have found the right person to advance: I have no formal qualification in geology, therefore you should examine all what I say critically -what you would probably do anyway.
But now to the topic at hand. You asked how it was determined that maturation occurs only over long periods of time and whether one can increase temperature and pressure without requiring long periods of time and still get the same product.
To answer your last question first, it is possible to reproduce catagenesis in the lab by hydrolysis within very short time spans (see  ). How do we then conclude that in nature it takes almost always million of years to form petroleum? When we observe the reaction rate of artificial catagenesis in the lab, we see that it increases exponential with temperature. From chemical reaction theory we know, that this type of reaction can be modeled by the Arrhenius equation. It reads:
where k is the reaction rate, A is a linear factor - including time - Ea the activation energy, R the gas constant and T the temperature. In short, the amount produced by the reaction depends linearly on time and exponentially on temperature.
In other words, when we can establish that the reaction occurred at low temperatures, we can conclude that long time spans were required to build petroleum. There are several lines of evidence which support this assumption. For one the maximum temperature of a probe can be determined by the following methods routinely used in oil exploration (see )
Thermal history determined by apatite or zircon fission track dating
A second, independent line of evidence is the existence of biodegraded oil, the bacteria which drive this process survive only at temperatures lower than 80Â°C (see )
The main point I would like to discuss has to do with the so called oil window. That is the temperature range - under the assumption of long time spans for oil formation - within which oil is formed, between 60 and 120 Â°C. At temperatures higher than 175Â°C we find only gas and nearly no oil. The majority of the known oil resources have been found between 2 and 5 km depth, which fits well with the current geothermal gradient of 25-30Â°C/km. When we suppose the formation of oil during the flood, that is within one year, this temperature range would be mapped to 330Â°C and 370Â°C. The calculation is based on the range of TTI values for oil formation - between 15 and 160 - and the formula
TTI = 2m*Δt
with t times in million of years, m is a temperature range in steps of 10 degree (for 100Â°C-110Â°C m is 0, for 110Â°C-120Â°C m is 1 and so one) To sum it up the scenario requires a much lower geothermal gradient combined with a much higher temperature. And not to forget: rock with a temperature of 330Â°C would take several millions of years to cool to the present temperature of 60Â°C.