2 Key ingredients for petroleum accumulation
2.1 Petroleum charge (continued)
The process of biological, physical and chemical alteration of kerogen into petroleum is known as maturation. Source rocks that experience the right conditions for these processes and can generate petroleum are termed mature. Maturation begins within an organic-rich sedimentary layer while it is being deposited. Here a series of low-temperature reactions that involve anaerobic bacteria reduce the oxygen, nitrogen and sulphur in the kerogen, leading to an increased concentration of hydrocarbon compounds. This stage continues until the source rock reaches about 50 °C. Thereafter the effect of elevated temperatures becomes much more pronounced as the reaction rates and solubility of some of the organic compounds increase.
Since temperature increases with depth in the Earth, heating is naturally achieved by burial of the source rock. The actual temperature reached at a given depth depends on the rate of increase of temperature with depth, the geothermal gradient. Figure 1 shows the relative proportions of crude oil and gas formed from Type II kerogen buried in an area with a geothermal gradient of about 35 °C km−1. Significant amounts of petroleum only begin to form at temperatures over 50 °C and the largest quantity of petroleum is formed as the kerogen is heated to temperatures between 60 and 150 °C. At still higher temperatures oil becomes thermally unstable and breaks down or ‘cracks’ to natural gas. Even after maturation, some of the kerogen still remains unaltered as a carbon-rich residue.
Figure 1: The relationship between depth of burial, temperature and the relative amount of crude oil and natural gas formed from Type II kerogen in an area with a geothermal gradient of about 35 °C km−1.
Look at Figure 1 and estimate the subsurface temperature and depth at which peak oil generation is achieved.
Peak oil generation in a typical Type II kerogen occurs at about 100 °C. In this example, where the geothermal gradient is 35 °C km−1, this corresponds to a depth of about 2850 m.
The most important factors in maturation studies are the amount and type of kerogen, the temperature and time. Maturation rates generally increase exponentially with respect to temperature (up to a point) and linearly with respect to time. Thus crude oil can form in old basins with low geothermal gradients (‘cold’) as well as in young basins where the geothermal gradient is high (‘hot’). However, it cannot form in young, cold basins except in trace amounts. It is usually destroyed in old, hot basins, assuming that subsidence has been continuous, because temperature eventually rises to a point where all kerogen and any crude oil formed earlier has been converted into gas.
To illustrate this point it is useful to examine the burial histories of source rocks in three different sedimentary basins (Figure 2). The source rocks in the Paris Basin, the North Sea Viking Graben and the Los Angeles Basin are different in terms of age and composition, and each has been subjected to differing burial histories. The point at which petroleum generation starts is known as the threshold, and this was reached after 40 million years in the Paris Basin (i.e. about 140 million years ago) when Early Jurassic (175 Ma) source rocks were buried to a depth of 1400 m. In contrast, it took some 80 million years before the Kimmeridgian (150 Ma) source rocks in the Viking Graben started to generate petroleum during early Tertiary times.
Figure 2: Reconstruction of burial histories of rocks from three basins; the Paris Basin in northern France, the Viking Graben in the northern North Sea and the Los Angeles Basin in the USA.
Examine Figure 2 and determine the threshold depth for petroleum generation in the Los Angeles Basin. Then, assuming that this depth equates to a temperature of 120° C, and ignoring surface temperature effects, calculate the geothermal gradient.
The threshold depth is about 2.5 km. At this depth the temperature is said to be 120 °C, so the geothermal gradient is 120 °C/2.5 km=48 °C km−1.
Migration refers to the movement of fluid petroleum through rocks. This process begins with primary migration, i.e. the expulsion of petroleum from the source rock. The driving force for this process is the pressure difference caused by the loading effect of overlying rocks. Overburden loading preferentially compacts mudstones, making it difficult for fluids within them to escape. As a result, pressure builds up in them until it is sufficient to drive the water and petroleum into adjacent rocks that are at a lower pressure because they are more permeable (see Figure 3). In the context of water resources, these rocks would be termed aquifers (Smith, 2005, Chapter 3), and at depth they would inevitably be saturated with water, but in petroleum parlance they are reservoir rocks, which we will discuss in more detail in Section 2.2. Figure 3b shows a potential reservoir rock exposed on land.
Figure 3: (a) A potential Jurassic source rock exposed in Dorset, the Kimmeridge Clay, whose black colour is due to high kerogen content. (b) A potential Jurassic reservoir rock exposed in Dorset, the Bridport Sand. (c) Migration of petroleum out of a source rock and upwards through a reservoir to a trap.
Once expelled from the source rock, buoyancy takes petroleum (both liquid and gas) from depth up towards the surface of the Earth because it is less dense than pore water and ‘floats’ on top of it in the reservoir rock. This is known as secondary migration, and its effectiveness depends on the permeability of the reservoir rocks and the density and viscosity of the petroleum fluids flowing through them. As Figure 3c shows, oil and gas continue to migrate upwards until they are trapped beneath an impermeable rock layer. At that point they segregate according to their density; gas is lighter so it will pool immediately beneath the permeability barrier, whereas oil is heavier and will accumulate beneath the gas. Rocks beneath will be saturated with pore water. Secondary migration serves to concentrate petroleum and by the time it reaches the trap it can occupy more than 90% of the pore volume in the reservoir.
Timing of the petroleum charge relative to the formation of a trap is critical, simply because a trap has to pre-date petroleum migration in order for an accumulation to develop: migration before suitable traps have formed would ultimately result in all petroleum escaping at the Earth's surface. Figure 3c reinforces this point by showing that the horizontal impermeable layer both truncated and sealed the dipping reservoir rocks, creating a trapping configuration, before migration occurred; otherwise the petroleum could not have been trapped.
As discussed above, petroleum generation may occur only a few million years after the source rock was deposited or tens of millions of years later, depending on the rate of burial and the geothermal gradient. An understanding of basin evolution is vital in this context, not only to determine when potential traps were formed, but to assess the degree to which they were subsequently filled, and the chances of petroleum having escaped (see Section 2.4 on traps later in this unit).