Publication History: This article is based on "Crain's Data Acquisition" by E. R. (Ross) Crain, P.Eng., first published in 2010. Updated Feb 2018. This webpage version is the copyrighted intellectual property of the author.

Do not copy or distribute in any form without explicit permission.

GEOCHEMICAL ANALYSIS BASICS
Geochemical analysis is used to determine the type and quantity of  organic carbon and other properties of unconventional reservoirs and source rocks. Organic carbon in the form of kerogen is the remnant of ancient life preserved in sedimentary rocks, after degradation by bacterial and chemical processes, and further modified by temperature, pressure, and time. The latter step, called thermal maturation, is a function of burial history (depth) and proximity to heat sources. Maturation provides the chemical reactions needed to give us gas, oil, bitumen, pyrobitumen, and graphite (pure carbon) that we find while drilling wells for petroleum.

Organic carbon is usually associated with shales or silty shales, but may be present in relatively clean siltstone, sandstone, and carbonate rocks.

A source rock is a fine grained sediment rich in organic matter that could generate crude oil or natural gas after thermal alteration of kerogen in the Earth's crust. The oil or gas could then migrate from the source rock to more porous and permeable sediments, where ultimately the oil or gas could accumulate to make a commercial oil or gas reservoir.

If a source rock has not been exposed to temperatures of about 100 °C, it is termed a potential source rock. If generation and expulsion of oil or gas have occurred, it is termed an actual source rock. The terms immature and mature are commonly used to describe source rocks and also the current state of the kerogen contained in the rock.


Total organic carbon (TOC) as measured by laboratory techniques historically has been used to assess the quality of source rocks, but now is widely used to help evaluate some unconventional reservoirs (reservoirs that are both source and productive).


Pathways that convert living organisms to organic carbon, from "Bitumens, Asphalts, and Tar Sands" by George V. Chilingar, Teh Fu Yen, 1978.

 

 

 

 


In the lab, it is relatively easy to distinguish kerogen from hydrocarbons:
kerogen is insoluble in organic solvents, oil and bitumen are soluble. Pyrobitumen is not soluble but its hardness is used to identify it from kerogen. Graphite is evident on resistivity logs because of the very low resistivity; all other forms of organic carbon are resistive.

Organic carbon has a density near that of water, so it looks like porosity to conventional porosity logs. High resistivity with some apparent porosity on a log analysis is a good indicator of organic carbon content OR ordinary hydrocarbons OR both.

TYPES OF KEROGEN

Organic material can be classified according to the source of the material, as shown below.


Origin, type, source, and hydrocarbon potential of different kerogens. Organic content in gas shales is usually Type II, as opposed to coals, which contain mostly Type III

The most commonly utilized scheme for classifying organic matter in sediments is based on the relative abundance of elemental carbon, oxygen, and hydrogen plotted graphically as the H/C and O/C ratio on a so called Van Krevelen diagram.

 

The classic Van Krevelen diagram


Rather than plot the elemental ratios it is common to plot indices determined by a pyrolysis technique referred to as Rock Eval. In the pyrolysis techniques two indices are determined: the Hydrogen Index (HI) which is milligrams of pyrolyzable hydrocarbons divided by TOC and the Oxygen Index (OI) which is milligrams of pyrolyzable organic carbon dioxide divided by TOC.

 

Cross-plots of both elemental H/C and O/C ratios or of HI and OI are utilized to discriminate four ‘fields’ which are referred to as Types I, II, III, and IV kerogen.

 

Type I kerogen is hydrogen rich (atomic H/C of 1.4 to 1.6: HI of > 700) and is derived predominantly from zooplankton, phytoplankton, micro-organisms (mainly bacteria) and lipid rich components of higher plants (H/C ratio 1.7 to 1.9).

 

Type II kerogen is intermediate in composition (H/C ≈ 1.2: HI ≈ 600) and derived from mixtures of highly degraded and partly oxidized remnants of higher plants or marine phytoplankton.

 

Type III kerogen is hydrogen poor (H/C ratio 1.3 to 1.5) and oxygen rich and is mainly derived from cellulose and lignin derived from higher plants.

 

Type IV kerogen is hydrogen poor and oxygen rich and essentially inert. This organic matter is mainly derived from charcoal and fungal bodies. Type IV kerogen is not always distinguished but is grouped with Type III.

 

The different types of organic matter are of fundamental importance since the relative abundance of hydrogen, carbon, and oxygen determines what products can be generated from the organic matter upon diagenesis. Since coal is comprised predominantly of Type III kerogen, there is little liquid hydrogen generating capacity. If the coal includes abundant hydrogen rich components (such as spores, pollen, resin, waxes - Type I or II), it will generate some liquid hydrocarbons. Although not common, some oil deposits are thought to be sourced by coals.

 

Note: Portions of the above Section, and the next Section, were taken verbatim (with moderate editing) from CBM Solutions reports.


 

Analyzing TOC IN THE LABORATORY
The total organic carbon content of rocks is obtained by heating the rock in a furnace and combusting the organic matter to carbon dioxide. The amount of carbon dioxide liberated is proportional to the amount of carbon liberated in the furnace, which in turn is related to the carbon content of the rock. The carbon dioxide liberated can be measured several different ways. The most common methods use a thermal conductivity detector or infrared spectroscopy.

Many source rocks also include inorganic sources of carbon such as carbonates and most notably calcite, dolomite, and siderite. These minerals break down at high temperature, generating carbon dioxide and thus their presence must be corrected in order to determine the organic carbon content. Generally, the amount of carbonate is determined by acid digestion (normally 50% HCl) and the carbon dioxide generated is measured and then subtracted from the total carbon dioxide to obtain the organic fraction.

Total organic carbon is often taken to mean the same thing as kerogen, but this is not the case. Kerogen is made up of oxygen, nitrogen, sulphur, and hydrogen, in addition to carbon. The standard pyrolysis lab procedure measures only the carbon, so total organic carbon excludes the other elements.

About 80% of a typical kerogen (by weight) is carbon, so the weight fraction of TOC is  80% of the kerogen weight. The factor is lower for less mature and higher for more mature kerogen:
      1: Wtoc = Wker * KTOC
OR 2: Wker = Wtoc / KTOC

Where:
  Wtoc = weight fraction of organic carbon
  Wker  = weight fraction of kerogen
  KTOC = kerogen correction factor - range = 0.68 to 0.90, default 0.80

Another lab procedure, called RockEval, burns both hydrogen and carbon, so the data needs to be calibrated to the standard method by performing a chemical analysis on the kerogen. Typically the organic carbon needs to be reduced by about 10% (the weight of the hydrogen burned) to match the standard method.

Rock Eval is the trade name for a set of equipment used in the lab to measure organic content of rocks, as well as other properties of the organics that help to identify the kerogen type. Rock-Eval combusts a crushed sample of rock at 600ºC.  Refractory organic matter such as inertinite does not combust readily at 600ºC so most coal samples yield Rock-Eval measured TOC values much lower than actual values because of incomplete combustion. Rock-Eval is not recommended for use with coals or source rocks with significant amounts of Type III and IV kerogen.

A rock sample is crushed finely enough so that 85% falls through a 75 mesh screen. Approximately 100 mg of sample is loaded into a stainless steel crucible capped with a micro mesh filter. To ensure accuracy, standard samples are loaded at the beginning and end of the run. Any drift in data can be detected and the samples rerun if necessary.

The analyzer consists of a flame ionization detector and two IR detector cells. The free hydrocarbons (S1) are determined from an isothermal heating of the sample at 340 degrees Celsius. These hydrocarbons are measured by the flame ionization detector. The temperature is then increased from 340 to 640 degrees Celsius. Hydrocarbons are then released from the kerogen and measured by the flame ionization detector creating the S2 peak. The temperature at which S2 reaches its maximum rate of hydrocarbon generation is referred to as Tmax. The CO2 generated from the oxidation step in the 340 to 580 degrees Celsius is measured by the IR cells and is referred to the S3 peak.

Measured results from a typical Rock Eval study will contain:
  TOC% - Weight percentage of organic carbon
  S1 = amount of free hydrocarbons in sample (mg/g)
  S2 = amount of hydrocarbons generated through thermal
          cracking (mg/g) – provides the quantity of
          hydrocarbons that the rock has the potential to
          produce through diagenesis.
  S3 = amount of CO2 (mg of CO2/g of rock) - reflects the amount of oxygen in the oxidation step.
 
 Ro = vitrinite reflectance (%)
  Tmax = the temperature at which maximum rate of
               generation of hydrocarbons occurs.

Calculated results include:
  Hydrogen index
      1: HI = 100 * S2 / TOC%
  Oxygen index
      2: OI = 100 * S3 / TOC%

  Production index
      3: PI = S1 / (S1 + S2)

Depth (m)

TOC

SRA

Tmax

Meas.

HI

OI

S2/S3

S1/TOC*100

PI

Top

S1

S2

S3

(°C)

% Ro

X025

1.35

0.05

1.72

0.63

444

 

128

47

3

4

0.03

X040

1.18

0.05

1.65

0.57

443

 

140

49

3

4

0.03

X050

0.83

0.03

1.31

0.55

443

 

158

66

2

4

0.02

X065

0.80

0.04

1.00

0.58

440

 

126

73

2

5

0.04

X075

0.75

0.05

1.04

0.72

438

 

138

96

1

7

0.05

X090

1.04

0.09

2.52

0.29

452

 

241

28

9

9

0.03

X110

1.02

0.05

1.16

0.56

441

 

114

55

2

5

0.04

X135

1.05

0.05

1.32

0.57

443

 

125

54

2

5

0.04

Laboratory measured TOC values (weight %) with measured and computed indices


HI versus OI plot example, indicating Type III kerogen

An alternate method for measuring TOC by solution rather than pyrolysis is described below, from a 1980's TOC report from Australia.

"The samples are analyzed for total organic carbon (TOC) according to AS 1038 Part 6. Moisture determinations are made to permit conversion to a dry basis. Carbon occurring as carbonate ion is determined to correct the gross carbon data to give the organic carbon content. This is done by driving off carbonate minerals with HCl acid.

The crushed and sieved (100 mesh) samples are weighed and exhaustively extracted in a Soxhlet apparatus using a benzene-methanol mixture. After removal of methanol by azeotropic distillation with benzene, the residue in benzene is diluted with hexane and the hydrocarbon solution separated by filtration from the brown precipitate. The latter is then dissolved in methanol. The yield of methanol soluble material is determined gravimetrically.

The hexane soluble portion of the extractable organic matter (E.O.M.) is weighed and chromatographed on silica. Elution with hexane gives predominantly alkanes and subsequent elution with hexane/benzene yields mainly monocyclic and polycycllc aromatic hydrocarbons. The eluted hydrocarbons are weighed, and then analyzed by gas chromatography / mass spectrometry."


Geochemical Logs
Measured and calculated indices can be plotted versus depth; the resulting log is called a Geochemical Log.


A geochemical log from offshore East Coast Canada


 

KEROGEN maturity
The hydrocarbon potential of organic carbon depends on the thermal history of the rocks containing the kerogen. Both temperature and the time at that temperature determine the outcome. Medium temperatures (< 175 C) produce mostly oil and a little gas. Warmer temperatures produce mostly gas.

 

Hydrocarbon type versus temperature
defines "oil window" and "gas window",
 with some obvious overlap


Vitrinite reflectance (Ro) is used as an indicator of the level of organic maturity (LOM). Ro values between 0.60 and 0.78 usually represent oil prone intervals. Ro > 0.78 usually indicates gas prone. High values can suggest "sweet spots" for completing gas shale wells.

 

Measurement of vitrinite reflectance was described as follows from the 1980's TOC report.

 

"Sample chips or sidewall core samples are cleaned to remove drilling mud or mud cake and then crushed using a mortar and pestle to a grain-size of less than 3 mm. Samples are mounted in cold-setting resin and polished ''as received", so that whole-rock samples rather than concentrates of organic matter are examined. This method is preferred to the use of demineralized concentrates because of the greater ease of identifying first generation vitrinite and, for cuttings samples, of recognizing cavings. The core samples are mounted and sectioned perpendicular to the bedd1ng.

Vitrinite reflectance measurements are made using immersion oil of refractive index 1.518 at 546 nm and 23°C and spinel and garnet standards of 0.42%, 0.917% and 1.726% reflectance for calibration. Fluorescence-mode observations are made on all samples and provide supplementary evidence concerning organic matter type, and exinite  abundance and maturity. For fluorescence-mode a 3 mm BG-3 excitation filter is used with a TK400 dichroic mirror and a K490 barrier filter."

 

Tmax is also a useful indicator of maturity, higher values being more mature.

 

Graphs of HI vs Ro and HI vs Tmax are used to help refine kerogen type and to assess maturity with respect to the oil and gas "windows". Depth plots of Ro and Tmax are helpful in spotting the top of the oil or gas window in specific wells, and in locating sweet spots for possible production using horizontal wells.

 


                  Crossplots of HI vs Tmax and HI vs Ro determine organic maturity, kerogen type, and whether the rock is in the oil or gas window. Immature and post mature rocks are not overly interesting as possible source or reservoir rocks.

 


Depth plot of Ro to determine trend line and location of oil and gas windows (Ro > 0.55).
Ro is plotted on a logarithmic scale, which makes the trend line relatively straight.

Thermal maturity as indicated by vitrinite reflectance (Ro) versus depth for a Barnett shale, showing "sweet spot" and oil versus gas “windows”.

 

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