12.4: Petroleum - Geosciences

12.4: Petroleum - Geosciences

Petroleum is a naturally occurring, yellow-to-black liquid found in geological formations beneath the Earth’s surface, which is commonly refined into various types of fuels.

Figure 1. Pumpjack pumping an oil well near Lubbock, Texas

It consists of hydrocarbons of various molecular weights and other organic compounds. The name petroleum covers both naturally occurring unprocessed crude oil and petroleum products that are made up of refined crude oil. A fossil fuel, petroleum is formed when large quantities of dead organisms, usually zooplankton and algae, are buried underneath sedimentary rock and subjected to intense heat and pressure.

Petroleum is recovered mostly through oil drilling (natural petroleum springs are rare). This comes after the studies of structural geology (at the reservoir scale), sedimentary basin analysis, reservoir characterization (mainly in terms of the porosity and permeability of geologic reservoir structures). It is refined and separated, most easily by distillation, into a large number of consumer products, from gasoline (petrol) and kerosene to asphalt and chemical reagents used to make plastics and pharmaceuticals. Petroleum is used in manufacturing a wide variety of materials, and it is estimated that the world consumes about 90 million barrels each day.

Concern over the depletion of the earth’s finite reserves of oil, and the effect this would have on a society dependent on it, is a concept known as peak oil. The use of fossil fuels, such as petroleum, has a negative impact on Earth’s biosphere, damaging ecosystems through events such as oil spills and releasing a range of pollutants into the air including ground-level ozone and sulfur dioxide from sulfur impurities in fossil fuels.


In its strictest sense, petroleum includes only crude oil, but in common usage it includes all liquid, gaseous, and solid hydrocarbons. Under surface pressure and temperature conditions, lighter hydrocarbons methane, ethane, propane and butane occur as gases, while pentane and heavier ones are in the form of liquids or solids. However, in an underground oil reservoir the proportions of gas, liquid, and solid depend on subsurface conditions and on the phase diagram of the petroleum mixture.

An oil well produces predominantly crude oil, with some natural gas dissolved in it. Because the pressure is lower at the surface than underground, some of the gas will come out of solution and be recovered (or burned) as associated gas or solution gas. A gas well produces predominantly natural gas. However, because the underground temperature and pressure are higher than at the surface, the gas may contain heavier hydrocarbons such as pentane, hexane, and heptane in the gaseous state. At surface conditions these will condense out of the gas to form natural gas condensate, often shortened to condensate. Condensate resembles gasoline in appearance and is similar in composition to some volatile light crude oils.

The proportion of light hydrocarbons in the petroleum mixture varies greatly among different oil fields, ranging from as much as 97 percent by weight in the lighter oils to as little as 50 percent in the heavier oils and bitumens.

The hydrocarbons in crude oil are mostly alkanes, cycloalkanes and various aromatic hydrocarbons while the other organic compounds contain nitrogen, oxygen and sulfur, and trace amounts of metals such as iron, nickel, copper and vanadium. Many oil reservoirs contain live bacteria. The exact molecular composition varies widely from formation to formation but the proportion of chemical elements vary over fairly narrow limits as follows:

Composition by weight
ElementPercent range
Carbon83 to 85%
Hydrogen10 to 14%
Nitrogen0.1 to 2%
Oxygen0.05 to 1.5%
Sulfur0.05 to 6.0%
Metals< 0.1%

Four different types of hydrocarbon molecules appear in crude oil. The relative percentage of each varies from oil to oil, determining the properties of each oil.

Composition by weight
Alkanes (paraffins)30%15 to 60%
Naphthenes49%30 to 60%
Aromatics15%3 to 30%

Crude oil varies greatly in appearance depending on its composition. It is usually black or dark brown (although it may be yellowish, reddish, or even greenish). In the reservoir it is usually found in association with natural gas, which being lighter forms a gas cap over the petroleum, and saline water which, being heavier than most forms of crude oil, generally sinks beneath it. Crude oil may also be found in semi-solid form mixed with sand and water, as in the Athabasca oil sands in Canada, where it is usually referred to as crude bitumen. In Canada, bitumen is considered a sticky, black, tar-like form of crude oil which is so thick and heavy that it must be heated or diluted before it will flow. Venezuela also has large amounts of oil in the Orinoco oil sands, although the hydrocarbons trapped in them are more fluid than in Canada and are usually called extra heavy oil. These oil sands resources are called unconventional oil to distinguish them from oil which can be extracted using traditional oil well methods. Between them, Canada and Venezuela contain an estimated 3.6 trillion barrels (570×109 m3) of bitumen and extra-heavy oil, about twice the volume of the world’s reserves of conventional oil.

Petroleum is used mostly, by volume, for producing fuel oil and gasoline, both important “primary energy” sources. 84 percent by volume of the hydrocarbons present in petroleum is converted into energy-rich fuels (petroleum-based fuels), including gasoline, diesel, jet, heating, and other fuel oils, and liquefied petroleum gas. The lighter grades of crude oil produce the best yields of these products, but as the world’s reserves of light and medium oil are depleted, oil refineries are increasingly having to process heavy oil and bitumen, and use more complex and expensive methods to produce the products required. Because heavier crude oils have too much carbon and not enough hydrogen, these processes generally involve removing carbon from or adding hydrogen to the molecules, and using fluid catalytic cracking to convert the longer, more complex molecules in the oil to the shorter, simpler ones in the fuels.

Due to its high energy density, easy transportability and relative abundance, oil has become the world’s most important source of energy since the mid-1950s. Petroleum is also the raw material for many chemical products, including pharmaceuticals, solvents, fertilizers, pesticides, and plastics; the 16 percent not used for energy production is converted into these other materials. Petroleum is found in porous rock formations in the upper strata of some areas of the Earth’s crust. There is also petroleum in oil sands (tar sands). Known oil reserves are typically estimated at around 190 km3(1.2 trillion (short scale) barrels) without oil sands, or 595 km3 (3.74 trillion barrels) with oil sands. Consumption is currently around 84 million barrels (13.4×106 m3) per day, or 4.9 km3 per year. Which in turn yields a remaining oil supply of only about 120 years, if current demand remain static.


Petroleum is a fossil fuel derived from ancient fossilized organic materials, such as zooplankton and algae. Vast quantities of these remains settled to sea or lake bottoms, mixing with sediments and being buried under anoxic conditions. As further layers settled to the sea or lake bed, intense heat and pressure build up in the lower regions. This process caused the organic matter to change, first into a waxy material known as kerogen, which is found in various oil shales around the world, and then with more heat into liquid and gaseous hydrocarbons via a process known as catagenesis. Formation of petroleum occurs from hydrocarbon pyrolysis in a variety of mainly endothermic reactions at high temperature and/or pressure.

Figure 2. Natural petroleum spring in Korňa, Slovakia

There were certain warm nutrient-rich environments such as the Gulf of Mexico and the ancient Tethys Sea where the large amounts of organic material falling to the ocean floor exceeded the rate at which it could decompose. This resulted in large masses of organic material being buried under subsequent deposits such as shale formed from mud. This massive organic deposit later became heated and transformed under pressure into oil.

Geologists often refer to the temperature range in which oil forms as an “oil window”—below the minimum temperature oil remains trapped in the form of kerogen, and above the maximum temperature the oil is converted to natural gas through the process of thermal cracking. Sometimes, oil formed at extreme depths may migrate and become trapped at a much shallower level. The Athabasca Oil Sands are one example of this.

An alternative mechanism was proposed by Russian scientists in the mid-1850s, the Abiogenic petroleum origin, but this is contradicted by the geological and geochemical evidence.


Crude Oil Reservoirs

Three conditions must be present for oil reservoirs to form: a source rock rich in hydrocarbon material buried deep enough for subterranean heat to cook it into oil, a porous and permeable reservoir rock for it to accumulate in, and a cap rock (seal) or other mechanism that prevents it from escaping to the surface. Within these reservoirs, fluids will typically organize themselves like a three-layer cake with a layer of water below the oil layer and a layer of gas above it, although the different layers vary in size between reservoirs. Because most hydrocarbons are less dense than rock or water, they often migrate upward through adjacent rock layers until either reaching the surface or becoming trapped within porous rocks (known as reservoirs) by impermeable rocks above. However, the process is influenced by underground water flows, causing oil to migrate hundreds of kilometres horizontally or even short distances downward before becoming trapped in a reservoir. When hydrocarbons are concentrated in a trap, an oil field forms, from which the liquid can be extracted by drilling and pumping.

The reactions that produce oil and natural gas are often modeled as first order breakdown reactions, where hydrocarbons are broken down to oil and natural gas by a set of parallel reactions, and oil eventually breaks down to natural gas by another set of reactions. The latter set is regularly used in petrochemical plants and oil refineries.

Wells are drilled into oil reservoirs to extract the crude oil. “Natural lift” production methods that rely on the natural reservoir pressure to force the oil to the surface are usually sufficient for a while after reservoirs are first tapped. In some reservoirs, such as in the Middle East, the natural pressure is sufficient over a long time. The natural pressure in most reservoirs, however, eventually dissipates. Then the oil must be extracted using “artificial lift” means. Over time, these “primary” methods become less effective and “secondary” production methods may be used. A common secondary method is “waterflood” or injection of water into the reservoir to increase pressure and force the oil to the drilled shaft or “wellbore.” Eventually “tertiary” or “enhanced” oil recovery methods may be used to increase the oil’s flow characteristics by injecting steam, carbon dioxide and other gases or chemicals into the reservoir. In the United States, primary production methods account for less than 40 percent of the oil produced on a daily basis, secondary methods account for about half, and tertiary recovery the remaining 10 percent. Extracting oil (or “bitumen”) from oil/tar sand and oil shale deposits requires mining the sand or shale and heating it in a vessel or retort, or using “in-situ” methods of injecting heated liquids into the deposit and then pumping out the oil-saturated liquid.

Unconventional Oil Reservoirs

Oil-eating bacteria biodegrade oil that has escaped to the surface. Oil sands are reservoirs of partially biodegraded oil still in the process of escaping and being biodegraded, but they contain so much migrating oil that, although most of it has escaped, vast amounts are still present—more than can be found in conventional oil reservoirs. The lighter fractions of the crude oil are destroyed first, resulting in reservoirs containing an extremely heavy form of crude oil, called crude bitumen in Canada, or extra-heavy crude oil in Venezuela. These two countries have the world’s largest deposits of oil sands.

On the other hand, oil shales are source rocks that have not been exposed to heat or pressure long enough to convert their trapped hydrocarbons into crude oil. Technically speaking, oil shales are not always shales and do not contain oil, but are fined-grain sedimentary rocks containing an insoluble organic solid called kerogen. The kerogen in the rock can be converted into crude oil using heat and pressure to simulate natural processes. The method has been known for centuries and was patented in 1694 under British Crown Patent No. 330 covering, “A way to extract and make great quantities of pitch, tar, and oil out of a sort of stone.” Although oil shales are found in many countries, the United States has the world’s largest deposits.


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'Get started'-day – 17th August

Implicit net-to-gross in the petrophysical characterization of thin-layered reservoirs

A new workflow has been devised to characterize the petrophysical properties of two, thin-layered, heterolithic log facies from a turbidite reservoir. The methodology is based on a published modelling technique that enables an extremely accurate reconstruction of the fine-scale lithological and sedimentological reservoir heterogeneities and a thorough integration of petrophysical data from core plugs.

A large number of fine-scale rock models (geometrical grids) are: (1) stochastically generated to investigate the variability of the sedimentological features observed in cores and (2) stochastically populated with porosity and permeability values of the pure lithological components (sandstone, siltstone and mudstone) to generate petrophysical grids. The petrophysical grids are subsequently upscaled using analytical and flow-based techniques, thus providing distributions of porosity, horizontal permeability and vertical permeability that are further analysed to characterize the aforementioned log facies.

The results obtained using this workflow are exhaustive, in the sense that they implicitly take into account all of the possible ranges of variation of ‘net-reservoir’ (sandstone and siltstone) and ‘non-net-reservoir’ (mudstone) lithologies. The use of net-to-gross in petrophysical characterization is thus made redundant.

Three-dimensional modelling of stacked turbidite channels inWest Africa: impact on dynamic reservoir simulations

The examination of production history from hydrocarbon fields composed of turbidite deposits indicates that fluid flow behaviour is often more complex than expected. The cause is commonly linked to the presence of fine-scale sedimentary heterogeneities, which complicate the reservoir. This is especially true in the case of turbiditic submarine channel complexes with final channel-filling stages composed of lateral migration deposits. These fine-scale heterogeneities are usually below seismic resolution and are rarely represented in initial reservoir models designed for such fields. Thus, it is difficult to match the production history or identify methods to improve production and reduce associated risks.

The various depositional patterns recognized in channel migration and aggradation packages from the Oligocene Malembo Formation of the Congo Basin, offshore Angola, exhibit different dynamic responses when modelled in a reservoir simulator. These dynamic differences are related to the different preservation rates of bank collapse sediments within isolated channel bodies, hereafter referred to as ‘elementary channels’. According to these preservation differences, the vertical stacking pattern of channels results in better connectivity than the true lateral migration. This effect has been incorporated into a full-field simulation model by applying petrophysical upscaling methods. The recognition and modelling of detailed sedimentological heterogeneities, and their distribution along full-field models produces a better history match when the inherent uncertainties have been taken into account.

Incorporating all available data and concepts to define reservoir architecture is essential in understanding the impact that fine-scale heterogeneities have on reservoir management. As the lateral extent and areal distribution of heterogeneities is still unknown, our modelling workflow incorporates uncertainty in the form of multiple realizations to identify and measure all uncertainties that might impact dynamic response.

Connectivity of channelized reservoirs: a modelling approach

Connectivity represents one of the fundamental properties of a reservoir that directly affects recovery. If a portion of the reservoir is not connected to a well, it cannot be drained. Geobody or sandbody connectivity is defined as the percentage of the reservoir that is connected, and reservoir connectivity is defined as the percentage of the reservoir that is connected to wells.

Previous studies have mostly considered mathematical, physical and engineering aspects of connectivity. In the current study, the stratigraphy of connectivity is characterized using simple, 3D geostatistical models. Based on these modelling studies, stratigraphic connectivity is good, usually greater than 90%, if the net: gross ratio, or sand fraction, is greater than about 30%. At net: gross values less than 30%, there is a rapid diminishment of connectivity as a function of net: gross. This behaviour between net: gross and connectivity defines a characteristic ‘S-curve’, in which the connectivity is high for net: gross values above 30%, then diminishes rapidly and approaches 0.

Well configuration factors that can influence reservoir connectivity are well density, well orientation (vertical or horizontal horizontal parallel to channels or perpendicular) and length of completion zones. Reservoir connectivity as a function of net: gross can be improved by several factors: presence of overbank sandy facies, deposition of channels in a channel belt, deposition of channels with high width/thickness ratios, and deposition of channels during variable floodplain aggradation rates. Connectivity can be reduced substantially in two-dimensional reservoirs, in map view or in cross-section, by volume support effects and by stratigraphic heterogeneities. It is well known that in two dimensions, the cascade zone for the ‘S-curve’ of net: gross plotted against connectivity occurs at about 60% net: gross. Generalizing this knowledge, any time that a reservoir can be regarded as ‘two-dimensional’, connectivity should follow the 2D ‘S-curve’. For channelized reservoirs in map view, this occurs with straight, parallel channels. This 2D effect can also occur in layered reservoirs, where thin channelized sheets are separated vertically by sealing mudstone horizons. Evidence of transitional 2D to 3D behaviour is presented in this study. As the gross rock volume of a reservoir is reduced (for example, by fault compartmentalization) relative to the size of the depositional element (for example, the channel body), there are fewer potential connecting pathways. Lack of support volume creates additional uncertainty in connectivity and may substantially reduce connectivity. Connectivity can also be reduced by continuous mudstone drapes along the base of channel surfaces, by mudstone beds that are continuous within channel deposits, or muddy inclined heterolithic stratification. Finally, connectivity can be reduced by ‘compensational’ stacking of channel deposits, in which channels avoid amalgamating with other channel deposits. Other factors have been studied to address impact on connectivity, including modelling program type, presence of shale-filled channels and nested hierarchical modelling.

Most of the stratigraphic factors that affect reservoir connectivity can be addressed by careful geological studies of available core, well log and seismic data. Remaining uncertainty can be addressed by constructing 3D geological models.

Petroleum Geosciences

The School of Geosciences has been a leader in petroleum research and education since its founding. We conduct basic and applied research that involves integrated studies of petroleum systems through basin analysis, reservoir characterization and modeling, and 3-D seismic interpretation.

We integrate geological, geochemical, and geophysical data and methods to evaluate the tectonic evolution, thermal maturity, and petroleum potential of sedimentary basins. Faculty and students are interested in the controls that structure, stratigraphy, and sedimentology play in regard to reservoir architecture, lithological and petrophysical-property heterogeneity, and reservoir performance. Our research employs a wide range of interpretation tools and workflows from multiattribute seismic analysis, geostatistics, machine learning, and seismic geomorphology to rock physics modeling.

Below are some of the specific sub-disciplines we are focused on. Please visit the linked faculty pages for specific projects and contact them for more information.

Petroleum Geoscience Jobs

Senior Development Geophysicist

Integration of relevant geophysical data, including interpretations, rock physics models and 4D data, leading to the identification and maturation of in-field and near-field drilling targets and production .

Senior Development Geophysicist

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Integration of relevant geophysical data, including interpretations, rock physics models and 4D data, leading to the identification and maturation of in-field and near-field drilling targets and production .


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Department INFORMATION & COMMUNICATION TECHNOLOGY Title SYSTEMS ENGINEER (SUBSURFACE SOL) Primary Purpose of Job Manages Services and participate in Projects, and Programs, related to Subsurface (Geoscience, .

Geo-modeller (Consultant II-Hal Consulting)

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a. Geological interpretation, seismic interpretation, and mapping. b. Well log analysis and correlations. c. Build structural framework models. d. Build stacked static models that will capture the different .

Well Intervention Engineer

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Well Intervention Engineer MAIN ACTIVITIES: Optimise safe working practices in the development of operational programmes in compliance with Company Rules. Be familiar with derogations, management of change .

Well Intervention Engineer

Optimise safe working practices in the development of operational programmes in compliance with Company Rules. Be familiar with derogations, management of change and company rules. Liaise with the Well .

Subsurface Systems Engineer

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Provide advanced technical support and consulting Landmark Geosciences software, Prepare and propose workflows for reservoir characterization, geology and petrophysical analysis. Conduct technical presentations .

The contribution made to cliff instability by Head deposits in the west Dorset coastal area

In the west Dorset coastal area superficial materials include Head deposits which, by the nature of their origin, are variable in structure and composition. Two broad types are recognized depending on the provenance of the predominant constituent: Cretaceous Head and Lias Head. The Cretaceous Head was probably formed near to or at the end of the Devensian stage of the Late Pleistocene. Where the two types of Head deposit are superimposed, Cretaceous Head always lies above Lias Head.

On many slopes Lias Head has topographic expression as lobate sheet forms which are frequently masked by a blanket of Cretaceous Head. The high permeability of Cretaceous Head together with the low strength of Lias Head produce slopes presenting potentially unstable conditions to depths of up to 4 m below ground surface.

Three minor types of instability are generated in the Head deposits themselves: shallow translational movements, block slides, and shallow rotational slides. In addition, the high permeability of Cretaceous Head permits water to be introduced to undercliff areas, thus facilitating the development of instabilities in the solid formations below. This results in a mechanism of cliff-top retreat which is quite independent of cliff-toe erosion.

The events at sites in Lyme Regis and Charmouth are summarized to illustrate the hazard presented by Head deposits in cliff-top areas.


Taking turbidite lobe deposits as an example, the types and formation mechanisms of sandstone amalgamation were discussed, the indications of sandstone amalgamations to sedimentary environment and stacking pattern of sand bodies were investigated, and “amalgamation ratio” was employed to quantitatively describe the degree of sandstone amalgamation. Sandstone amalgamation is a common sedimentological phenomenon in sand/mud dominated clastic deposits, which generally consists of two processes: erosion of inter-sand mudstone barriers and amalgamation of sandstone beds which were previously separated by the mudstone barriers. Statistics analysis suggests that amalgamation ratio varies greatly in different hierarchical levels. Based on these analyses, three sets of conceptual 3D lobe models with identical NTG (net to gross ratio) and bed sizes but different hierarchies and different amalgamation ratio using an object-based modeling approach. Static connectivity analysis of these models suggests that the more the hierarchical levels involved, the worse connectivity the model has for models with identical hierarchical settings, the higher the amalgamation ratio, the better the connectivity.


1.1.6 Deep-Water Hydrocarbon Geologic Theory

Research on deep marine petroleum geology examines the formation, distribution, and enrichment rules for petroleum in seas with contemporary water depths greater than 300 m, including both ultra-deep-water (>3000 m in depth) and deep-water deposits. Important progress has been made recently in deep petroleum geologic theory with respect to basin type, petroleum system, and petroleum accumulation. The world's deep-water basins can be grouped into four types: basins with ductile beds for which sediments are supplied by large rivers basins with ductile beds for which sediments are supplied by small rivers basins without ductile beds for which sediments are supplied by small rivers and basins hosting nondeep-water reservoirs. To date, about 75% of the world's deep-water petroleum reserves are found in the former two types. Deep-water reservoirs, typically seated in Neozoic deep-water sandstones and featuring high porosity and permeability, poor diagenetic properties, and low continuity, contribute around 90% of the discovered deep-water reserves. They also contain large carbonate reef-bank reservoirs. The oil and gas reservoirs are predominantly tectonic–stratigraphic ones (66%), followed by tectonic (25%) and stratigraphic ones (9%). Mudstone or gypsum caprock is an important prerequisite for preserving these reservoirs. Jurassic and Paleogene rocks are highly efficient principal source rocks. The source rocks of most deep-water basins matured in late years and are mainly characterized by near-source accumulation and vertical migration, favoring the pooling and preservation of oil and gas.

The construction of a deep-water system–sequence stratigraphy model ( Mutti, 1985 Vail et al., 1987 Galloway, 1989 ) a deep-water deposition mechanism ( Posamentier, 1991 Weimer and Link, 1991 ) theories of gravity flow and the deposition process ( Lowe, 1982 Mutti et al., 1999 Kneller and Buckee, 2000 ) development of water channels, sheet sand, submarine fans, massive transport, and submarine landslides in deep-water reservoirs natural levee-filling deposits ( Slatt et al., 1999 ) and deep-water mixed sand ( Hurst et al., 2003 ) boosted the prediction and oil and gas exploration of sedimentary reservoirs in deep-water lowstand tracts.

About 40% of the major discoveries in petroleum since 2000 have occurred in deep-water areas. In the deep-water Santos Basin alone, more than 10 world-class large oil and gas fields totaling a recoverable reserve of more than 50 × 10 8 t have been discovered. The offshore deep-water zones in Brazil, the Gulf of Mexico (the United States), and West Africa have become hotspots for deep-water petroleum exploration and are known as the “golden triangle” for deep-water petroleum exploration. Future deep-water petroleum exploration will chiefly concentrate on continuous exploration in six areas: discovered petroleum basins, undrilled basins with ductile beds, ultra-deep abyssal plains, deep-water continental margins without structures, rifts/transition zones/active continental margins, and deeper drilling zones (Pettingill and Weimer, 2002). The deep-water zone of the South China Sea, which is rich in oil and gas resources, also has the appropriate geologic conditions for hosting large oil and gas fields, with many large deep-water oil and gas fields already having been discovered there. Nevertheless, China remains far behind other countries in terms of both deep-water petroleum technologies and methodologies. Despite our poor understanding of deep-water petroleum accumulation and the limited amount of exploration, deep-water zones represent a strategic future replacement for conventional large oil and gas fields.

Watch the video: Introduction to Petroleum Geology