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The Petroleum System

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The Petroleum System

The Petroleum System consists of a mature source rock, migration pathway,reservoir rock, trap and seal. Appropriate relative timing of formation of these elements and the processes of generation, migration and accumulation are necessary for hydrocarbons to accumulate and be preserved.

The components and critical timing relationships of a petroleum system can be displayed in a chart that shows geologic time along the horizontal axis and the petroleum system elements along the vertical axis.

Exploration plays and prospects are typically developed in basins or regions in which a complete petroleum system has some likelihood of existing.

Source Rock Hydrocarbon Generation

The formation of hydrocarbon liquids from an organic rich source rock with kerogen and bitumen to accumulates as oil or gas.

Generation depends on three main factors:

    • the presence of organic matter rich enough to yield hydrocarbons,
    •  adequate temperature,
    • and sufficient time to bring the source rock to maturity.
      • Pressure and the presence of bacteria and catalysts also affect generation.
    • Generation is a critical phase in the development of a petroleum system.

Migration

The movement of hydrocarbons from their source into reservoir rocks.

    • The movement of newly generated hydrocarbons out of their source rock is primary migration, also called expulsion.
    • The further movement of the hydrocarbons into reservoir rock in a hydrocarbon trap or other area of accumulation is secondary migration.
    • Migration typically occurs from a structurally low area to a higher area in the subsurface because of the relative buoyancy of hydrocarbons in comparison to the surrounding rock.
      • Migration can be local or can occur along distances of hundreds of kilometres in large sedimentary basins, and is
    • critical to the formation of a viable petroleum system.

Accumulation

The phase in the development of a petroleum system during which hydrocarbons migrate into and remain trapped in a reservoir.

Reservoir

A subsurface body of rock having sufficient porosity and permeability to store and transmit fluids.

    • Sedimentary rocks are the most common reservoir rocks because they have more porosity than most igneous and metamorphic rocks and
      • they form under temperature conditions at which hydrocarbons can be preserved.
    • A reservoir is a critical component of a complete petroleum system.

Seal (cap rock)

An impermeable rock that acts as a barrier to further migration of hydrocarbon liquids.

Rocks that forms a barrier or cap above and around reservoir rock  forming a trap such that fluids cannot migrate beyond the reservoir. The permeability of a seal capable of retaining fluids through geologic time is   ~  10-6 to 10-8 darcies.  commonly

    • shale, mudstone
    • anhydrite 
      • salt, 
    • A seal is a critical component of a complete petroleum system.

Trap

A configuration of rocks suitable for containing hydrocarbons and sealed by a relatively impermeable formation through which hydrocarbons will not migrate.

Traps are described as

    • structural traps
      • Hydrocarbon traps that form in geologic structures such as folds and faults
      • stratigraphic traps
        • Hydrocarbon traps that result from changes in rock type or pinch-outs, unconformities, or other sedimentary features such as reefs or buildups
    • A trap is an essential component of a petroleum system.

Major subdisciplines in petroleum geology

Several major subdisciplines exist in petroleum geology specifically to study the seven key elements discussed above.

Source rock analysis

In terms of source rock analysis, several facts need to be established. Firstly, the question of whether there actually is any source rock in the area must be answered. Delineation and identification of potential source rocks depends on studies of the local stratigraphy, palaeogeography and sedimentology to determine the likelihood of organic-rich sediments having been deposited in the past.

If the likelihood of there being a source rock is thought to be high, the next matter to address is the state of thermal maturity of the source, and the timing of maturation. Maturation of source rocks (see diagenesis and fossil fuels) depends strongly on temperature, such that the majority of oil generation occurs in the 60° to 120°C range. Gas generation starts at similar temperatures, but may continue up beyond this range, perhaps as high as 200°C. In order to determine the likelihood of oil/gas generation, therefore, the thermal history of the source rock must be calculated. This is performed with a combination of geochemical analysis of the source rock (to determine the type of kerogens present and their maturation characteristics) and basin modelling methods, such as back-stripping, to model the thermal gradient in the sedimentary column.

Basin analysis

A full scale basin analysis is usually carried out prior to defining leads and prospects for future drilling. This study tackles the petroleum system and studies source rock (presence and quality); burial history; maturation (timing and volumes); migration and focus; and potential regional seals and major reservoir units (that define carrier beds). All these elements are used to investigate where potential hydrocarbons might migrate towards. Traps and potential leads and prospects are then defined in the area that is likely to have received hydrocarbons.

Exploration stage

Although a basin analysis is usually part of the first study a company conducts prior to moving into an area for future exploration, it is also sometimes conducted during the exploration phase. Exploration geology comprises all the activities and studies necessary for finding new hydrocarbon occurrence. Usually seismic (or 3D seismic) studies are shot, and old exploration data (seismic lines, well logs, reports) are used to expand upon the new studies. Sometimes gravity and magnetic studies are conducted, and oil seeps and spills are mapped to find potential areas for hydrocarbon occurrences. As soon as a significant hydrocarbon occurrence is found by an exploration- or wildcat-well the appraisal stage starts.

Appraisal stage

The Appraisal stage is used to delineate the extent of the discovery. Hydrocarbon reservoir properties, connectivity, hydrocarbon type and gas-oil and oil-water contacts are determined to calculate potential recoverable volumes. This is usually done by drilling more appraisal wells around the initial exploration well. Production tests may also give insight in reservoir pressures and connectivity. Geochemical and petrophysical analysis gives information on the type (viscosity, chemistry, API, carbon content, etc.) of the hydrocarbon and the nature of the reservoir (porosity, permeability, etc.).

Production stage

After a hydrocarbon occurrence has been discovered and appraisal has indicated it is a commercial find the production stage is initiated. This stage focuses on extracting the hydrocarbons in a controlled way (without damaging the formation, within commercial favorable volumes, etc.). Production wells are drilled and completed in strategic positions. 3D seismic is usually available by this stage to target wells precisely for optimal recovery. Sometimes enhanced recovery (steam injection, pumps, etc.) is used to extract more hydrocarbons or to redevelop abandoned fields.

Reservoir analysis

The existence of a reservoir rock (typically, sandstones and fractured limestones) is determined through a combination of regional studies (i.e. analysis of other wells in the area), stratigraphy and sedimentology (to quantify the pattern and extent of sedimentation) and seismic interpretation. Once a possible hydrocarbon reservoir is identified, the key physical characteristics of a reservoir that are of interest to a hydrocarbon explorationist are its bulk rock volume, net-to-gross ratio, porosity and permeability.

Bulk rock volume, or the gross rock volume of rock above any hydrocarbon-water contact, is determined by mapping and correlating sedimentary packages. The net-to-gross ratio, typically estimated from analogues and wireline logs, is used to calculate the proportion of the sedimentary packages that contains reservoir rocks. The bulk rock volume multiplied by the net-to-gross ratio gives the net rock volume of the reservoir. The net rock volume multiplied by porosity gives the total hydrocarbon pore volume i.e. the volume within the sedimentary package that fluids (importantly, hydrocarbons and water) can occupy. The summation of these volumes (see STOIIP and GIIP) for a given exploration prospect will allow explorers and commercial analysts to determine whether a prospect is financially viable.

REFERENCES

  • V. Guerriero; et al. (2011). “Improved statistical multi-scale analysis of fractures in carbonate reservoir analogues”. Tectonophysics. Elsevier. 504: 14–24. Bibcode:2011Tectp.504…14Gdoi:10.1016/j.tecto.2011.01.003.
  • V. Guerriero; et al. (2009). “Quantifying uncertainties in multi-scale studies of fractured reservoir analogues: Implemented statistical analysis of scan line data from carbonate rocks”. Journal of Structural Geology. Elsevier. 32 (9): 1271–1278. Bibcode:2010JSG….32.1271Gdoi:10.1016/j.jsg.2009.04.016
  • http://www.geologyin.com/2014/08/petroleum-system.html#SrKMF6KiqoGjXCyU.99 Follow us: @GeologyTime on Twitter
Cite this article as: Geology Science. (2019). The Petroleum System. [online] Available at: http://geologyscience.com/applied-geology/petroleum-geology/the-petroleum-system/ [5th December 2019 ]
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