Generation and Migration

I. Introduction- Origin of oil

A theory of the origin of the oil must explain a series of facts:

A. Geologic:

(1) Most hydrocarbon deposits occur in sedimentary rocks, most of the sedimentary rocks with oil are marine.

(2)Many hydrocarbon deposits occur in porous and permeable sandstones and carbonate rocks, which are totally enclosed in other impermeable rocks.

(3) Other minor geologic occurances:

B. Chemical

(1) Differences between old and young oils:

(2) Similarities between crude oils and organically produced hydrocarbons

(3) Similar fingerprinting can be done using gas chromatography.

II. Origin- Inorganic vs. Organic

A. Inorganic origin

(1) Extraterrestrial occurances of hydrocarbons used to support theory that hydrocarbons may be inorganic;

(2) If hydrocarbons are abiotic, they should be contained in the mantle and migrate to their positions in the crust. Test of the theory is to look at occurences of hydrocarbons. Would hypothesize an association with igneous rocks, deep crustal structures and faults:

(3) Major test of the abiotic origin of oil.

(4) Summary- there is almost certainly abiotic oil, extraterrestrial and some associated with igneous rocks, but it is not commercial. This leaves us with primarialy a biogenic origin.

III. Organic Origin/processes of preservation

Total carbon on earth surface- 2.65 x 1020 g, ~82% is in CO3 rocks, ~18% is in hydrocarbons.

The reduction of oxidized carbon is caused by photosynethsizing plants and algea. They take energy from the sun and convert CO2 into glucose (C6H12O6).

The glucose molecules are the basis of constructing more complex organic molecules by animals and plants. These complex molecules include:

In most cases, these complex molecules are oxidized to CO2, largely by bacteria. In exceptional cases, the complex organic molecules are preserved, buried, and converted into hydrocarbons.

See Fig. 5.4 in Seeley

A. Preservation of Organic Matter in Ancient Sediments

The distribution and preservation of organic matter in ancient sediments is difficult to predict, but this is what is critical, because it is the fundamental reason why a particular sedimentary basin may or may not be productive.

The oceans have contain diverse and voluminous organism since the precambrian radiation. However, the composition of the organic matter may have changed-

Because marine organisms are the source of oil, it is important to understand their distribution and how they may be preserved. The way to do this is look at the modern distribution and mechanisms of preservation



B. Productivity and preservation of organic matter- modern environments

OM(sediment) = Production/destruction

There is a link between the production and destruction, however- when production increases, the destruction decreases. This means the processes the control the amount of organic matter in the sediment are not linearly related.

i.e. destruction = f(production)

There are large differences between marine and terrestrial environments- discussed separately

Why would you care about these kind of questions in petroleum geology class- because the oil is where the organic matter is.


(1) Marine Organic matter- preservation

"In the sea, as on the land, all organic matter is originally formed by photosynthesis"- NOT TRUE. There are "chemosynthetic" biota that derive their energy from chemical reations rather than photo reactions. But these are relatively minor; they are unlikely to form commercial oil deposits.

a) Production:

Considering only photosynthesis, two important parameters for photosynthesis:

Because of the controls on production, the distribution of organic matter in the world's oceans are not uniform.

Low production:

High production:

These distribution of productivity have to do with oceanic circulation.

b) conditions favorable for preservation

Two important factors (1) sedimentation rate and (2) bottom water oxygen content (oxidation of the organic matter)

(i) Sedimentation rate:

Look at Fig. 5.7

(ii) Bottom water oxygen content:

The amount of oxygen in bottom water controls how much organic matter will be oxidized, but the amount of oxygen in many instances relates to the amount of organic matter produced.

The amount of bottom water oxygen largely depends on the stratification of the water body:

(2) Organic productivity and preservation in Modern Continental Environments

There is little reason to talk about this preservation, because most of continental organic matter is altered to coal, rather than liquid hydrocarbons.

Essentially, the production and preservation depends on availability of water and temperatures. Only sediments that would be preserved are important, and thus upland areas, which are eroded, would not be a place for preservation.

The remaining continental environment is swamps, these produce coal.


IV. Formation of Kerogen

What happens to all the organic matter (i.e. bug guts) as it gets buried? Obviously it is subjected to higher pressure and temperatures. Three major steps. Of course there are gradations between steps, like all things in geology:

(1) Diagenesis

(2) Catagenesis

(3) Metagenesis.

A. Shallow diagenesis of organic matter

With burial into the sediment, the Eh of the pore water continues to decline. The rate at which is declines, and the starting value all relate to the oxygen continent of the overlying water (e.g. well oxygenated or stagnating).

At each level, different species of bacteria use different elements or compounds as the oxidants to oxidyze the organic matter.

This redox reaction is how the bacteria gain energy to live, and the specific compound they use determines the amount of energy they can get from the reaction.

The chemical composition of organic matter is generally taken to contain C, H, O, N, and P. The C/N/P ratio is very constant in marine organic matter and is generally said to be 116/16/1. This is called the Redfield ratio after its discoverer. The ratio is different and more variable in continental organic matter.

(1) Reactions of organic matter:

Look at the reactions on p. 200 and 201

The series of major oxidants are:

(a) Oxygen, this provides 30 kcal/moles of energy

(b) Nitrate (NO3) and Nitrite (NO2). Most of the oxygenated nitrogen species at the pH and Eh of seawater are as nitrate. This reaction provides ~20 kcal/moles

(c) Sulfate This reaction provides 5 kcal/mole of energy

(d) Carbon dioxide. This reaction provides the least amount of energy. ~4 kcal/mole

(e) other oxidants: There are other minor species that can act as oxidants. These include Fe and Mn oxides and Iodate. They are similar in energy produced to the nitrate. In other words, Fe and Mn oxides are reduced at about the same level as the nitrate. This is seen as a rapid increase in the amount of dissolved Fe and Mn in the sediment (Reduced Fe and Mn are very soluble, oxidized Fe and Mn are not).


(2) Inorganic reactions

There are several inorganic reactions that also occur. They are important because they can control the physical properties of the sediment- e.g. the porosity and permeability which are important for migration of hydrocarbons.

(a) Iron minerals- The formation of reactive sulfide and soluble Fe(II) allows the precipitation of pyrite and siderite. Both of these minerals are very common in organic rich (ie. black) shales.

(b) Other carbon minerals- Calcite and dolomite can form at shallowburial depths, but with increased burial, there is a lack of Mg ions and so calcite becomes the major carbonate mineral. The Ca for the calcite comes from the dissolution of biogenic calcite in the sediments. The only source for Mg is from seawater and if sedimentation is fast enough, then it is rapidly depleated.

B. Chemistry of Kerogen

After these shallow diagenetic reactions, the remaining solid organic matter is now kerogen. It is distinguished as being insoluble in organic solvents. There are three types of kerogen depending on the organic matter that was the precursor. These three types generate three different types of oil

(1) Type I- Algal

Higher in H/O ratio than the other kerogens- typically 1.2 to 1.7. The H/C ratio is 1.65 (note, these are all weight ratios). The organic compounds are typically lipids (fats).

(2) Type II- combination algal and zooplankton and phytoplankton

Has intermediate H/C and H/O ratio to those of Type I and Type II

(3) Type III- generally from woody (land) plants- Humic material

Rich in aromatics, but low in aliphatic compounds. It has a very low H/C ratio and higher H/O ratio. Generally undergoes diagenesis to form coal- the only liquid hydrocarbon it produces is methane.

Thus, when evaluating an province it is important to determine the amount, as well as the type of kerogen present.


C. Maturation of kerogen

As the kerogen is subjected to deeper burial and increased P and T, it begins to release HC. The rate and types of hydrocarbons released depend on the rate of heating and the length of time available for heating.

Empirical evidence for the T for oil vs gas generation are:

(1) Kinetics:

Arrhenius equation-

k = Aexp(-E/RT)

Where: k is reaction rate constant (1/m.y.), A is frequency factor (1/m.y.), E is the activation energy (kJ/mol), R is the gas constant (kJ/mol K), and T is the temperature in kelvins.

In general, reaction rates double for every 10°C increase in temperature. But the Arrhenius equation only gives the rate that hydrocarbons are generated. Thus, to calculate the total volume (= $$$$) you also need to know the amount of time that the kerogen has been at the oil generating temperature.

(2) Techniques for determining the quantity of generated hydrocarbons

a) Level of Organic Maturatiy (LOM)

b) Time-temperature index (TTI).

x% = [1-exp(-STTI/100)]*100

(3) Techniques for determining temperature (Paleothermometers)

The major unkown variable in the TTI calculations is the temperature that the organic matter has been subjected to. The problem is that the geothermal gradient may have changed with time, so that the temperature at the bottom of the hole is different from the temperature in the past.

There are a variaty of techniques to determine the temperature that organic matter has reached.

a) Carbon ratio technique Not well calibrated. Compares residual carbon after pyrolysis at 900°C and the total C in the sample. Ratio of Cr/Ct. Idea is that "fresh" OM has more easily removed C than "old and altered" OM. This means the Cr/Ct ratio increases with maturity.

b) Electron spin resonance The number of free electrons vary with maturity and can be measured. There are problems associated with recycling of organic matter and original variations in the organic matter- difficult to calibrate.

c) Pyrolysis The heating of source rocks and detection of the hydrocarbons that are given off. Most common technique is through Rock-Eval machine.

Fig. 10-8, Hunt

d) Gas chromatography There is an evolution of the distribution of n-alkanes. Calibrate the technique.

Fig. 5.18

e) Clay mineral analysis Various clay minerals alter diagenetically to new minerals at specific temperatures:

f) Fluid inclusions

g) Pollen color Spores and pollen are colorless when formed. As they heat up they gradually become darker.

h) Vitrinite reflectance

V. Migration

Many observations indicate that HC found in reservoir beds (porous and permeable) did nt originate there:

Two types of migration:

A. How does primary migration occur?

Major questions still as to how the HC migrate out primary migration occurs.

The problem is that most source rocks are fine grained, and thus generally have low permeability. The porosity of the source rocks is generally low by the time that they are buried into the oil generating window, which implies two things:

(1) there is little additional compaction driven migration of water from the pore space

(2) What little permeability present originally is now gone.

Fig. 5.20

The major problem is a size problem:

Pore throats in shales at 2000 m depth are on the order 50 to 100Å, but individual, large hydrocarbon molecules range from 10 to 100Å. Thus droplets of oil are likely to be too large to pass through the pore throats, particulalry when they are water wet. That is when there is water adhered to the clay that also reduces the size of the throats.

An alternate explanation is that the source beds are not water wet, but have continues oil phase with no water. This may be true in very rich beds, but lean beds it is unlikely to occur.


(1) Release of interstitial water in clay minerals

Although most of the pore water in sediments is removed through compaction by the time oil generation is reached during burial, there is still the bound water (interlayer water) in clay minerals present in the sediment.

This bound water is released from the clays at temperatures that are in the oil window. The depth depends on the geothermal gradient

Fig.5.23


Appears that there is a correspondence between the depth of the release of water from clay mienrals and the maximum number of tops of oil reservoirs. Is this proof that dehydrationof clays is responsible for primary oil migration? What are problems?:

Fig. 5.24

(1) Depth of drilling. Likely that the depth of the maximum will shift downward as more deep wells are drilled and more deep reservoirs are discovered

(2) Correlation does not require causality

(3) Oil migrates in the subsurface, and migration is vertical. Thus, it is likely that the generation of oil occurred at depths below the location where it is found (i.e. the reservoir).

(4) The figure is from the Gulf coast which contains much smectite clays. Other oil producing regions have little clay material.

(2) Interstitial hydrocarbons

Not only water, but hydrocarbons may also be included in the interlayer sites of clay minerals. May provide a mechanism for primary migration- the hydrocarbons will be released along with the water.

(3) Overpressuring

Overpressuring is when the pore fluid pressure are greater than hydrostatic for some reason. Processes include:

(1) dewatering of clays, which provide excess water to the pore space increasing the mass, without necessarily increasing the volume of the pore space.

(2) conversion of solid kerogen to liquid hydrocarbon. There is a volume change with this process where the liquid is greater volume than the original volume taken up by. May drive primary migration (e.g. see Bredehoeft article).

(3) Cementation of porosity reducing volume, without changing the volume of fluids present in the pore space

(4) Rapid loading of sediment, preventing escape of fluids and increasing the lithistatic load on the pore fluids.

B. Explusion Mechanisms

Several theories, none satisfactory:

(1) Protopetroleum

Idea: Petroleum is expelled from source rocks before they have been converted to water insoluble molecules. They are expelled when they are ketones, adics and esters.

Problem: Concentrations of these compounds are low in in source rocks. The compounds are easily adsorbed onto the surfaces of clay minerals. They should not evolve into hydrocarbons in the reservoir bed once they migrate there.

(2) Expulsion at high temperatures

Idea: HC are more soluble at high temperatures than low temperatures, e.g. see Figs. 5.26 and 5.27 for relationship. At T > 150°C, 50 to 200 ppm HC can be soluble in water. This is one to two orders of magnitude greater than at T < 100°C. Also lower weight hydroacrabons (the gases) are faily soluble even at lower T

Problem: These temperatures are greater than the oil generating window. At these higher temperatures, porosity and permeability may be destroyed. Also the hydrocarbons will thermally breakdown

(3) Micelles

Idea: Micelss are "colloidal organic acid soaps". One end is hydrophobic, the other hydrophylic. They can link water molecules with hydrocarbon molecules allowing migration. Hydrocarbon types have different solubilities with different micelles, and it turns out the distribution of these hydrocarbons matches the distribution of micelles.

Problem: For sufficient HC to have migrated requires a very high micelle/HC ratio, but there are only trace quantities of micelles. Also, micelles molecules are larger than pore throats in clays, so they would not fit through the openings.

(4) Gases

Idea: High CO2 concentrations will precipitate calcite, reducing pore volumes and increasing pore pressures. CO2 also lowers the viscosity of oil, allowing it to flow more freely. Also some HC may migrate out of the source bed as gases, and then subsequenty condence.

Problems: precipitation of CO2 will also reduce permeability. Also most CO2 is generated during diagenesis, and before catagenesis, and so may be lost from the system. Primary migration of HC gases can't explain primary migration of the heavier hydrocarbons.