Source rocks, maturation and migration

The organic matter (OM) in rocks is the remains of phytoplankton (tiny floating plants), algae, bacteria and land plants. Almost everything that life produces is oxidised (attacked by oxygen) and eaten while it is still in the water or on the bottom. Only a small part reaches the sediment, and an even smaller part survives. Three conditions make a rock rich in organic matter. First, the water is highly productive (it supports a lot of life). Second, the bottom is anoxic (it has no oxygen), so aerobic bacteria (those that need oxygen) and burrowing animals cannot work there. Third, fine sediment builds up at a moderate rate: fast enough to bury the OM quickly, but not so fast that mineral material dilutes it.

That is why source rocks are almost always fine-grained rocks, such as clay-rich rocks, clay–carbonate rocks or siliceous rocks (rocks rich in silica), and coals. Stagnant water is not the only reason. In fine mud, bacteria quickly use up the oxygen that arrives from above. The sediment has low permeability, so new oxygen cannot get in. Within the first few centimetres below the bottom, the environment becomes reducing (it has no free oxygen).

Well-known marine type II source rocks in Eurasia are the Bazhenov Formation of West Siberia (Upper Jurassic to the very base of the Cretaceous) and the Domanik deposits of the Upper Devonian in the Volga–Urals and Timan–Pechora provinces. These are dark sequences of silica-rich clay rock and of clay–carbonate rock. Their organic carbon content is usually a few per cent, and in places more than 10%.

At the start of burial (diagenesis, the first changes in a buried sediment), bacteria break down part of the biopolymers: proteins, carbohydrates, lipids (fats and waxes) and lignin (the stiff material of wood). The rest joins into a complex substance made of very large molecules. Its main part does not dissolve in organic solvents. This part is called kerogen, and it is usually more than 90% of all the OM in an immature rock. The part that does dissolve is called bitumen. There is little of it in an immature rock. In a mature rock, the hydrocarbons that have formed but not yet left the rock add to it.

Whether kerogen yields oil or gas on heating depends on its structure, above all on how much hydrogen it contains. The long hydrocarbon chains of lipids (the fats and waxes of algae, spores and plant cuticles) turn into oil. The ring-shaped (aromatic) structures in the lignin of wood contain little hydrogen and give mainly gas. Kerogen is divided into types. They were first told apart by the atomic ratios H/C and O/C (the Van Krevelen diagram).

In coals and coaly rocks, we tell the kinds of organic matter apart under the microscope by their macerals, the “minerals” of organic matter. Vitrinite comes from wood and bark and tends to give gas. Liptinite (also called exinite) comes from spores, pollen, resins, cuticles and algae, and it is oil-prone. Inertinite is charred and oxidised remains, and it hardly generates anything. Vitrinite also matters for another reason: we estimate maturity from its reflectance.

Samples are taken from all the shale intervals of exploration wells. They can be cuttings (rock chips brought up by the drilling fluid), core (cylinders of rock cut from the well) or outcrops (rock that shows at the surface). Total organic carbon (TOC; in Russian-language literature $C_\text{org}$) is measured by burning a sample after acid has removed the carbonates. The amount of carbon dioxide released gives the mass fraction of organic carbon. TOC tells us how much OM there is, but not what it will yield on heating.

Pyrolysis answers the part of the question that TOC leaves open. A few tens of milligrams of crushed rock are heated without oxygen on a standard heating programme, and the instrument records what comes off. The first peak, $S_1$ (at about 300 °C), is the free hydrocarbons that have already formed in the rock. The second peak, $S_2$ (while the sample heats from about 300 to 600 °C), is the hydrocarbons made when the kerogen cracks (breaks apart) inside the instrument. It shows the generation potential that is still left. $S_3$ is the carbon dioxide from the oxygen-containing groups of the kerogen. $T_{max}$ is the temperature at which the yield of $S_2$ is greatest. It rises as the rock matures.

As a rock is buried deeper, its organic matter passes through three stages that geochemists call diagenesis, catagenesis and metagenesis. In diagenesis, burial is slight and the temperature is no higher than about 50–60 °C. Bacteria make biogenic methane (methane made by living organisms), and the remains of OM turn into kerogen. In catagenesis, heat breaks the kerogen down. First oil forms, together with gas (the oil window). Then the oil and the heavy components crack into wet gas (gas with some liquid hydrocarbons) and condensate (light liquid hydrocarbons). In metagenesis only dry gas (methane) is left, and the kerogen turns into a carbon residue.

Russian-language literature labels the stages of catagenesis on the coalification scale (a scale of how far buried plant matter has turned towards coal): protocatagenesis (PK), mesocatagenesis (MK1–MK5) and apocatagenesis (AK). The interval where most oil forms is called the main phase of oil formation (MPOF). On the whole it corresponds to the oil window.

Kerogen breaks down through chemical reactions, and temperature sets their speed. Oil starts to form at about 60–100 °C, and most of it forms at about 100–150 °C. The exact figures depend on the kerogen type and on how long the rock was heated. The speed of a reaction grows exponentially with temperature, as the Arrhenius law says:

We cannot calculate maturity from the present temperature alone, because the whole heating history matters. The OM itself “records” that history through changes that cannot be reversed. The main indicator is vitrinite reflectance ($R_o$). It is the share of light that a polished surface of vitrinite particles reflects under a microscope (in immersion oil), given as a percentage. As the rock matures, the ring-shaped (aromatic) structures in vitrinite grow larger and become more ordered, and the vitrinite reflects more and more light. $R_o$ records the highest temperature the rock has reached, with time taken into account. It does not fall when the rock cools.

Vitrinite is not found everywhere. There is little of it in marine shales, and almost none in rocks older than the Devonian, when land plants had not yet spread. In such rocks we assess maturity from $T_{max}$, from the colour of spores and pollen, from the colour of conodonts (microscopic tooth-like fossils of ancient animals) in carbonates, and from the composition of biomarkers (organic molecules that act as chemical fossils).

In a section with no gaps in the rock record, $R_o$ grows with depth roughly exponentially. So on a plot of $\lg R_o$ against depth, the points lie on a straight line. From such a profile we find the depths of the boundaries of the generation windows. If we extend the line upwards, we can estimate how much rock has been eroded: at the surface of fresh sediments $R_o$ is about 0.2%.

Primary migration (expulsion; in Russian-language literature also called emigration) is the exit of hydrocarbons from the source rock. The rock is clay-rich and its permeability is measured in nanodarcies (extremely low), so oil cannot simply flow out of it. First the hydrocarbons that form must fill the pores and use up the kerogen's capacity to hold hydrocarbons on its surface (its sorption capacity). Until then they stay in the rock. So poor rocks (TOC below about 0.5%) give up almost nothing. When kerogen breaks down, the material in the pores takes up more volume, because the products, especially gas, are less dense than kerogen. The pressure rises. When it exceeds the strength of the rock, microfractures open, and the oil escapes through them in pulses. Then the fractures close again. The same mechanism is one of the causes of abnormally high pressures (Abnormal formation pressures: origin, prediction and recognition).

The share of the hydrocarbons formed that has left the source rock is called the expulsion efficiency. It is high in organic-rich rocks (by estimates, up to 60–90%), especially in those interbedded with siltstones (layers of coarser silt), through which the oil leaves more easily. It is low in poor rocks, where the kerogen holds back almost everything that formed.

Secondary migration is the movement of hydrocarbons from the kitchen to the traps along carrier beds and faults. The driving force is buoyancy: oil and gas are lighter than water. The capillary entry pressure of the pore channels works against it (Reservoir and seal): a hydrocarbon needs some pressure to push into a narrow pore. So the hydrocarbons travel through the largest channels, in narrow streams under the top of the carrier bed. Low-permeability layers hold them back until the hydrocarbon column is tall enough to break through. They also leave some oil and gas behind in the pores (residual saturation). Flows of formation water may bend the migration path. Migration distances range from hundreds of metres to tens and even hundreds of kilometres.

All this makes secondary migration inefficient. Most of what was generated stays in the source rock, is spread out along the migration paths, or escapes through imperfect seals (cap rocks that leak). So estimating the charge of a trap is a mass balance, an account of how much there is at each step: how much was generated in the kitchen, how much was expelled, and what fraction reached the traps.

An accumulation is not a sealed tin can. The oil keeps changing, and the engineer meets the result of that whole history in the well (Types of reservoir fluids).

• Thermal cracking. As the accumulation is buried deeper, the oil becomes lighter and richer in gas. Above about 150–160 °C (depending on the time spent there), it slowly cracks (breaks into smaller molecules) into gas and a solid residue called pyrobitumen.
• Deasphalting. When gas enters an oil accumulation, the oil dissolves asphaltenes (the heaviest, tar-like part of oil) less well. The asphaltenes then drop out of the oil (they precipitate), sometimes as a layer at the oil–water contact.
• Water washing. Moving formation waters dissolve and carry away the most soluble light hydrocarbons, above all the aromatic ones (those with ring-shaped molecules).
• Biodegradation. In accumulations cooler than about 80 °C, bacteria that live in the water at the oil–water contact eat first the normal alkanes (straight-chain hydrocarbons) and then other components. The oil becomes heavier, and its viscosity and sulfur content rise. This is how many heavy-oil accumulations were formed. If an accumulation was once heated above about 80–90 °C and then uplifted, it may stay “sterile” (the heat killed its bacteria).

Oil keeps the “fingerprints” of its source. Three things let us match oils with one another and with extracts from source rocks: the pattern of normal alkanes on chromatograms (laboratory charts that separate the oil into its components), the make-up of biomarkers (molecules inherited from the original organisms) and the carbon isotope composition (the ratio of the different forms of carbon atoms). In this way we find which sequence feeds the accumulations, from which side the traps were filled and in what order. For development, we also find where the barriers lie. If the oils of neighbouring blocks of one accumulation differ in composition, there is most likely no communication between the blocks.