Geochemistry for shale gas plays
Posted by D Nathan Meehan August 6, 2010

Geochemistry
Many tools are used to analyze and study shales. The TOC (total organic carbon) is typically determined as the difference between total organic carbon and the carbonate carbon concentration. While both of the latter measurements are generally made with cuttings or core samples, petrophysical estimates of TOC can provide excellent and continuous estimates of TOC.

Pyrolysis of organic matter in shales involves heating samples with increasing temperatures to extract hydrocarbons. The amount of volatile hydrocarbons (referred to as S1), thermogenic hydrocarbons (S2) and the carbon dioxide released up to a fixed temperature (S3). The methodology to make these measurements involves pulverizing a small sample of rock and heating it to increasing temperatures and measuring released volumes of hydrocarbons and carbon dioxide. These values (S1 through S3) are used in calculating several common geochemical values including the hydrogen and oxygen indices (HI and OI). The temperature above which no further hydrocarbons are released by pyrolysis is referred to as Tmax and provides a common measure of organic matter. The indices are defined as follows:

HI=(100 S2) ⁄ TOC

with units of milligrams hydrocarbons per gram of organic carbon and

OI=(100 S3) ⁄ TOC

with units of milligrams CO2 / gram organic carbon.

Geochemists use these values to assess the source rock potential of shales along with their hydrocarbon generation potential and to describe the types of kerogen. Dan Jarvie and others have pointed out the value of the S1/TOC ratio and demonstrated that values in excess of 100 milligrams hydrocarbons/gram of organic carbon are very positive for the production potential of shale oil and shale gas.

Vitrinite reflectance is another widely used measurement associated with shales. Plants take in CO2 and water to generate carbohydrates and polymers that form plant material such as cellulose and lignins. It is this plant material that (with time, temperature and pressure) ultimately creates oil or natural gas. Vitrinite is a shiny material formed by the thermal alteration of such organic matter and is present in most kerogens and coals. Vitrinite reflectance is often used to describe the maturity of coals (lignite being a coal with low thermal maturity and reflectance and anthracite being highly reflective and more mature.) Coalification of peat is strongly analogous chemically and physically to the maturation of kerogen and vitrinite reflectance can be used in conjunction with TOC values, pyrolysis data, etc. Virinite reflectivity is typically measured with an oil-immersion microscope and device for measuring reflected light. Comparisons are made with reference standards to define the reflectance in oil, Ro. While Ro is a measure of thermal maturity, its significance is a function of the type of kerogen being analyzed. Nonetheless, low values of Ro indicate immature kerogen. As Ro increases, the indicated maturity levels suggest oil generation, gas generation with condensates (wet gases) and ultimately dry gases at high levels of thermal maturity. At such levels, sufficient time and temperature will have cracked heavier organic molecules.

Different types of kerogen are usually described based on their relative amounts of hydrogen, carbon and oxygen. Each type of kerogen has varying tendencies to form oil, gas and coal. The reasons for the different chemical compositions include the type of organic material present (including plankton, algae, spores, pollen, diatoms, etc.) and the chemical processes to which the material was exposed.

While not as routinely used in shale oil and shale gas evaluations, geoscientists often make use of the organic carbon isotope ratios 13C/I2C and atomic carbon nitrogen ratios in analyzing shale depositional histories and related studies. Geochemistry can be a powerful tool for reservoir engineers in many areas besides the analysis of unconventional reservoirs.

4 responses | Add Yours

Responses

Rohan Belvalkar says:

Isn’t CAI (Conodont Alteration Index) a better and easier way to determine the thermal maturity? Which is prefered and why?

D Nathan Meehan says:

Good question. Glad we have clever readers out there!

We usually recommend that thermal maturity be assessed using as many tools as possible. The CAI approach is relatively straightforward approach based on the color of certain fossils when dissolved in acid. These conondont fossils are compared to a color index which shows the maximum temperature reached by the rock and thus the thermal maturity. Conondonts are present in many of the Paleozoic shales that have been developed. An example paper that compares CAI and other techniques can be found here: http://preview.tinyurl.com/c8xj8k

There are many other methods for estimating thermal maturity. Consider http://www.papgrocks.org/laughrey2_p.pdf and http://www.papgrocks.org/laughrey2.pdf as a more detailed summary. The author points out the strengths and weaknesses of numerous approaches. In the size of a blog post I don’t cover the topic in detail.

I am less likely to suggest the method for Mesozoic shales as conondonts are less pervasive and die out at some age ealier than the Paleozocic. Neither technique is expensive; the methods I mentioned in the blog are more prevalent and more has been published on the common shale gas plays with them.

Andrew Green says:

Very interesting, i would however like to correct your quote that: “The temperature above which no further hydrocarbons are released by pyrolysis is referred to as Tmax and provides a common measure of organic matter.”

Tmax is in fact the pyrolysis temperature at which you get maximum rate of pyrolysis yield of the P2 (S2) peak and is measured in °C. Hydrocarbons are infact still relased after the Tmax temperature but just at lower rates.

Best Regards

Integrated Geochemical Interpretation

Andrew Green says:

also could i ask for a reference link to the comment:

Dan Jarvie and others have pointed out the value of the S1/TOC ratio and demonstrated that values in excess of 100 milligrams hydrocarbons/gram of organic carbon are very positive for the production potential of shale oil and shale gas.

many thanks

You must be logged in to post a comment.

We’re here to help
D Nathan Meehan
+1.800.229.7447