1Petroleum

Taken from “Petroleum Geoscience� by J Gluyas and R Swarbrick, Blackwell, 2004

Petroleum Petroleum is a mixture of hydrocarbon molecules and lesser quantities of organic molecules containing sulfur, oxygen, nitrogen, and some metals. The term includes both oil and hydrocarbon gas. The density of liquid petroleum (oil) is commonly less than that of water and the oil is naturally buoyant. So-called heavy (high specific gravity) oils and tars may be denser than water. Some light (low specific gravity) oils are less viscous than water, while most oils are more viscous than water.

The source

A source rock is a sedimentary rock that contains sufficient organic matter such that when it is buried and heated it will produce petroleum (oil and gas). High concentrations of organic matter tend to occur in sediments that accumulate in areas of high organic matter productivity and stagnant water. Environments of high productivity can include nutrient rich coastal upwellings, swamps, shallow seas, and lakes. However, much of the dead organic matter generated in such systems is scavenged and recycled within the biological cycle. To preserve organic matter, the oxygen contents of the bottom waters and interstitial waters of the sediment need to be very low or zero. Such conditions can be created by overproduction

of organic matter, or in environments where poor water circulation leads to stagnation. Different sorts of organic matter yield different sorts of petroleum. Organic matter rich in soft and waxy tissues, such as that found in algae, commonly yields oil with associated gas on maturation (heating), while gas alone tends to be derived from the maturation of woody tissues. Even oilprone source rocks yield gas when elevated to high temperatures during burial.

The seal

Oil and gas are less dense than water and, as such, once they migrate from the source rock they tend to rise within the sedimentary rock column. The petroleum fluids will continue to rise under buoyancy until they reach a seal. Seals tend to be fine-grained or crystalline, low-permeability rocks. Typical examples include muds tone/shale, cemented limestones, cherts, anhydrite, and salt (halite). As such, many source rocks may also be high-quality seals. Seals to fluid flow can also develop along fault planes, faulted zones, and fractures. The presence of a seal or seals is critical for the development of accumulations of petroleum in the subsurface. In the absence of seals, petroleum will continue to rise until it reaches the Earth's surface. Here, surface chemical processes including bacterial activity will destroy the petroleum. Although seals are critical for the development of petroleum pools, none are perfect. All leak. This natural phenomenon of petroleum seepage through seals can provide a shortcut to discovering petroleum.

The trap

The term "trap" is simply a description of the geometry of the sealed petroleum-bearing container. Buoyant petroleum rising through a pile of sedimentary rocks will not be trapped even in the presence of seals if the seals are, in gross geometric terms, concave-up. Petroleum will simply flow along the base of the seal until the edge of the seal is reached, and then it will continue upwards toward the surface. A trivial analogy, albeit inverted, is to pour coffee onto an upturned cup. The coffee will flow over but not into the cup. However, if the seal is concavedown it will capture any petroleum that migrates into it. The simplest trapping configurations are domes (four-way dip-closed anticlines) and fault blocks. However, if the distribution of seals is complex, it follows that the trap geometry will also be complex. The mapping and remapping of trap geometry is a fundamental part of petroleum geoscience at the exploration, appraisal and production phases of petroleum exploitation.

The reservoir A reservoir is the rock plus void space contained in a trap. Traps rarely inclose large voids filled with petroleum; oilfilled caves, for example, are uncommon. Instead, the trap contains a porous and permeable reservoir rock. The petroleum together with some water occurs in the pore spaces between the grains (or crystals) in the rock. Reservoir rocks are most commonly coarse-grained sandstones or carbonates. Viable reservoirs occur in many different shapes and sizes, and their internal properties (porosity and permeability) also vary enormously.

The origin of petroleum from living organisms Organic matter The chemical composition of organic matter is diverse because the organisms from which it is derived are complex. The principal biological components of living organisms are proteins, carbohydrates, lipids, and lignin. Animal tissue and enzymes are partly composed of proteins, built from amino acids. Carbohydrates are also found in animal tissue, being a principal source of energy for living organisms. Lipids are fatty organic compounds, insoluble in water, and found in most abundance in algae, pollen, and spores. Lipids are rich in hydrogen, and hence yield high volumes of hydrocarbon molecules on maturation. The lipid group contains a special group of compounds called isoprenoids, which are found in chlorophyll and include pristane and phytane.

These molecules are preserved during petroleum formation. Their abundance and composition in petroleum can be indicative of the depositional environment in which the organic matter accumulated. Under normal conditions, organic matter is very dilute in sediments. In global average terms, claystones and shales (excluding oceanic sediments) contain only 0.99 wt% (weight percent) of organic carbon, compared with 0.33 wt% in carbonate rocks and 0.28 wt% in average sandstones (Hunt 1979). In comparison, most source rocks contain in excess of 1.0 wt% of organic carbon, rich source rocks contain >5.0 wt%, and the value can reach as high as 20 wt%.

Preservation of organic matter The two basic requirements for the generation and preservation of organic matter in sediments are (1) high productivity and (2) oxygen deficiency of the water column and the sea bed. The supply of organic matter to any depositional site is controlled by primary productivity (commonly within the top 50 m of the water column) and the depth of water through which the material must settle. Preservation beneath the sediment/water interface is a function of the rate of burial and oxygenation of the bottom waters. Both productivity and oxygen deficiency at the site of deposition can combine to produce excellent source rock, although some source rocks may result from a dominance of only one control. Environments of high organic

productivity include (1) continental margins, (2) lagoons and restricted seas, (3) deltas in warm latitudes, and (4) lakes. Oceanic waters tend to be stratified, although water circulation from the surface to sea bed also occurs. The stratification results from high organic productivity in the photic zone (i.e., in the top c.50 m of the water column, influenced by sunlight). Periodical overturning of the oxygenated waters from the surface supplies oxygen to organisms whose habitat is the deep ocean, including the ocean floor. Between the periods of overturning, the high biological activity at the surface causes oxygen deficiency in the layer immediately beneath.

Where this anaerobic layer intersects the sea bed on the shelf and upper slope of the continental margin, organic debris is preserved, since there is a relative scarcity of organisms here to scavenge the debris. Along some parts of the continental margins, upwelling of nutrient-rich waters creates a favorable niche for even higher levels of organic productivity; for example, on the western sides of the African and North and South American continents. Periodic algal blooms, which are most frequent in conditions of calm and warmth, can also act to poison the microplankton, leading to high deposition and preservation rates in these settings. Lagoons and restricted seas are favorable for high preservation of organic matter. A lack of circulation of waters from the oxygenated surface layer to the bottom waters induces anoxic (oxygen-deficient) conditions. Dead organisms that sink to the sea bed are not scavenged there. Present-day examples include the Gulf of California and Lake Maracaibo, where the amount of organic matter in the seabed sediments is as high as 10.0 wt%. Landlocked seas such as the Black Sea and the Caspian Sea have similarly high preservation rates of organic matter. Extensive shelf seas created during sea-level highstands are also important sites of organic matter production and preservation. The Liassic (Toarcian) source rocks of the Wessex (UK) and Paris (France) Basins were created under such conditions. Deltas are typified by some of the highest sedimentation rates of any depositional environment. It is this factor that results in some deltaic sediments being source rocks. Rapid deposition leads to quick burial below the zone of organic scavenging near the sea bed. The same rapid deposition and subsidence generate massively thick sediment piles which, in total, contain a great deal of terrestrially derived, organic matter. Today and in the Neogene, the Mississippi and Niger Deltas are, and were, sites of source-rock accumulation.

Freshwater lakes on continents are sites for high productivity and preservation in the anoxic bottom waters that characterize the lake bed. The dominant organisms that create lacustrine oil shales are algae and fungi/bacteria. Some lakes have a low clastic sediment input; producing thick accumulations on the lake bed of slowly deposited, but very organicrich, mud. Ancient examples of lake sediments form the richest petroleum source rocks in the world, including the Green River Shale Formation in the central USA. Lacustrine source rocks are also responsible for generating

much of the oil onshore China, Thailand, and Burma (Case history 3.9). Water depth is not a critical factor. In fact, very shallow waters are often indicated in ancient lacustrine oil shales by the presence of desiccation cracks and an association with evaporite minerals, which are indicative of periods of drying during low lake levels.

3.7.3 Kerogen Organic matter can be usefully divided into two components: bitumen, which is composed of compounds that are soluble in organic solvents; and kerogen, the insoluble components. Bitumen or extractable organic matter includes the indigenous aliphatic, aromatic, and N—S—O compounds, including migrated hydrocarbons generated from elsewhere within the sedimentary sequence. The proportion of the original organic matter that is kerogen is commonly high, about 85-90% in shales.Kerogen is the most abundant organic component on Earth (Brooks et al. 1987) and is the term used for a set of complex organic compounds, the composition of which depends on the original organic source. Kerogen is composed of varying proportions of C, H, and O. Kerogen type Conventionally, kerogen is subdivided into four main "types" on the basis of maceral content; that is, original organic source material. The main maceral groups are liptinite, exinite, vitrinite, and inertinite. It is useful in petroleum geology to be able to identify the depositional environment of the source rock for a number of reasons. First, the kerogen type is dependent on the types of organic material preserved in each sedimentary environment. Secondly, each kerogen type matures under different burial conditions, controlling the timing of petroleum generation and expulsion from the source rock. Finally, each kerogen produces contrasting petroleum products, and in differing yields. The kerogen type or types present in a source rock can be recognized on the basis of optical properties such as color, fluorescence, and reflectance. Liptinite (Type I) has a high hydrogen to carbon ratio but a low oxygen to carbon ratio. It is oil-prone, with a high yield (up to 80%). It is derived mainly from an algal source, rich in lipids, which formed in lacustrine and/or lagoonal environments. Liptinite fluoresces under UV light. Examples of liptinite-rich kerogen are found in the Devonian Orcadian shales of northeast Scotland, the Carboniferous oil shales of the Lothians, southern Scotland, the Eocene Green River Shale Formation of the central USA, and the Upper Permian lacustrine shale of northwest China. Type I kerogen is relatively rare.

Exinite (Type II) has intermediate hydrogen to carbon and oxygen to carbon ratios. It is oil- and gas-prone, with yields of 40—60%. The source is mainly membranous plant debris (spores, pollen, and cuticle), and phytoplankton and bacterial microorganisms in marine sediments.

Exinite fluoresces under UV light. Examples of exinite-dominated source rocks include the Toarcian black shale of the Paris Basin and the Kimmeridge Clay Formation of the North Sea basin. Some exinite-rich kerogen contains a high proportion of sulfur and is termed Type H-S kerogen. The presence of sulfur influences the timing and rate of kerogen maturation. An example of a Type H-S kerogen is found in the coastal Monterey Formation of California. Type II kerogens are the most abundant. Vitrinite (Type III) has a low ratio of hydrogen and high ratio of oxygen relative to carbon, and therefore forms a lowyield kerogen, principally generating gas. The primary source is higher plant debris found in coals and/or coaly sediments. Vitrinite does not fluoresce under UV light; however, it is increasingly reflective at higher levels of maturity and therefore can be used as an indicator of source-rock maturity. Examples of vitrinitedominated source rocks include the Carboniferous Coal Measures of the southern North Sea basin and the Triassic source coals of the Australian North West Shelf. Inertinite (Type IV) is the nonfluorescing product of any of the above kerogens. It is high in carbon and very low in hydrogen, and is often termed "dead-carbon," having no effective potential to yield oil and gas (Brooks et al. 1987).

The quantity and quality of kerogen The environment at the site of deposition of the organic matter controls the quantity and quality of the kerogen found in a source rock. These include the rate of deposition and burial, the ratio of terrestrial to marine plant input, the oxidation state of the depositional environment, and the amount of reworking of the sediment prior to burial. The quantity of kerogen in a rock defines its richness as a source rock, which in turn relates to its petroleum potential in two ways. First, the richer the source rock, the larger is the volume of hydrocarbons that can be generated. Secondly, the higher the proportion of the rock that is organic material, the greater is the efficiency of migration of hydrocarbons out of the source rock. The quantity of kerogen in a source rock is determined from the total organic carbon (TOC) and reported as a weight percentage of the rock (Chapter 1). The quality of kerogen in a rock determines the hydrocarbon yield — that is, the volume of hydrocarbon generated for each volume of source rock—which is usually expressed in kilograms of hydrocarbon per ton of rock (kg HC t"1). A range of techniques is used to evaluate potential source rock samples, including visual inspection of the kerogen type, elemental analysis, and pyrolysis (Chapter 1).

Fig. 2 The maturation of oil from source rock as a function of depth and temperature. The curves show product generation from a source rock with 1 % total organic carbon (TOC) as Type II kerogen. The curve is based on pyrolysis - gas chromatography

Maturation of source rocks: kerogen to oil to gas Kerogen is composed of large hydrocarbon molecules that are stable at low temperatures, but will break down into smaller molecules of liquid and gaseous hydrocarbon compounds with progressive exposure to higher temperatures. In addition, nonhydrocarbon gases such as CO2 and H2O are produced, and a nonreactive residue remains. The transformation to smaller and lighter compounds is controlled by the reaction kinetics; that is, the strength of the bonds between the atoms and thus the energy required to break those bonds. Many studies have shown that the most important control is temperature. Lesser controls are the nature and abundance of the kerogen in the source rock and pressure.

Temperature In sedimentary basins, temperature increases with depth. Average temperature gradients for sedimentary basins fall mainly between 200C km-1 and 400C km-1. There are exceptions: "cool"

basins, with gradients of less than 200C km-1, include the Caspian Sea (as low as 100CkIrT1). The Caspian Sea is experiencing very high active sedimentation rates. "Hot" basins include the Gulf of Thailand (48°Ckm-1), the Rhine Graben (50-8O0C km"1), and central Sumatra (60- 1200C km1

). All of these hot basins are underlain by thinned lithosphere. The source of the heat in the

sediments comes primarily from the basement (i.e., it originates from the center of the Earth), coupled with a local contribution from the decay of radionuclides (commonly in clays). Basement heat flow varies according to the thickness and nature of the lithosphere, and proximity to thermal anomalies in the mantle. In the laboratory, the temperature needed to generate oil from a source rock is around 430-4600C, whereas in a typical sedimentary basin time is expressed in millions of years and temperatures are in the range 80—1500C. In other words, there is a combination of time and temperature that must be integrated if we are to make an assessment of the thermal maturity of a source rock, and determine its petroleum generation history and any remaining potential.

There are a number of ways in which sediments reflect their thermal exposure during basin evolution, which are known as thermal maturity indicators.

The kinetics of hydrocarbon generation The rate at which a kinetically controlled reaction proceeds Oi) is a function of the absolute temperature (T), the activation energy (E1), the gas constant (R), and a constant (A) given by the Arrhenius equation:

k=A exp(-E/RT) In practice, a whole series of parallel reactions is under way simultaneously during source-rock maturation, including secondary cracking of oil to gas at higher temperatures. Determination of the activation energy for each reaction is achieved in the laboratory, and there are now a number of published and widely used kinetic models, including all three main kerogen types as well as a Type H-S kerogen. The narrow spread of activation energies for a Type I kerogen (Green River Shale), coupled with a very high petroleum yield, is compared with the wider profile of activation energies required to generate a lower petroleum yield from a Type II kerogen (Toarcian Black Shale). In practical terms, this difference results in the high-yielding Type I kerogen generating its petroleum over a relatively narrow range of temperatures (and therefore depths) compared with a Type II kerogen.

Reaction products Early alteration of kerogen in the shallow subsurface (generally less than 1.0 km) results in the production of CO2 and H2O. These products are derived from short -COOH side chains that combine with any available oxygen in the sediments. Thereafter, the products are dominated by a

mixture of oils and gases at depths of 2.0 km and greater. There are a number of schemes that depict the main phases of product generation in terms of temperatures and depths of burial. One such scheme is illustrated in Fig. 2, in which there is a peak oil-generation phase followed by a phase of wet gas, and finally peak gas generation from a typical Type II source rock. The product mix will depend on a number of factors. These include the distribution and richness of the kerogen in the original source rock, the rate of temperature increase, the primary migration route for products out of the source rock once maturation commences, and its efficiency, and the distribution of pressure within and outside the source rock. With increasing temperature, the product mix moves increasingly toward dry gas. Gas is derived as a result of direct alteration of kerogen (as the primary product in Type III kerogen, and as a secondary reaction in Types I and II), and by cracking of the remaining oil. Peak production tends to occur at about 1500C. For example, the Jurassic Kimmeridge Clay source rock of the North Sea is immature on the flanks of the basin, generates undersaturated black oil at intermediate depths and gas condensate deeper in the basin, and is thought to be generating dry gas where the source rock is most deeply buried.

The distribution of oil and gas in Jurassic reservoirs (i.e., where great migration distances have not been involved) reflects the maximum temperatures recorded by the source rock, which are also the temperatures recorded today. For gas-prone sources, little fluid is produced and the first major product of maturation is abundant gas, with a low molecular weight.

Maturation in the reservoir Oil that has migrated from the source rock and is subsequently trapped will also be influenced by increases in temperature, ultimately maturing to a mixture of gases, dominated by methane (CH4). Gas cracking in the reservoir is characterized by the occurrence of associated bitumens (pure hydrocarbons with large aromatic ring structures resulting from the loss of hydrogen during methane production; i.e., dehydrogenation).

Figure shows examples of types of petroleum traps.

Strategic Oil Reserve The oil embargo of 1973 made OPEC a household word, and it made many Americans and western Europeans realize the degree to which their societies had become dependent upon oil imports. The United States, recognizing that any future cutoffs of imported oil could create many problems in the American economy, decided to establish an oil reserve that could provide oil as needed. The Strategic Petroleum Reserve was created in 1975 for the express purpose of being a source of oil for the United States if there were any cutoff of imported oil. The goal was to place one billion barrels of oil into storage, enough to supply the country’s import needs for more than 100 days.

Several alternatives were considered, but it was decided that the best storage sites would be cavities within salt domes in Louisiana and Texas. These domes formed over millions of years as salt slowly moved upward through the overlying sediments to create roughly cylindrical bodies up to 5 miles across and 10 miles in height. These salt domes have been the sites of much oil exploration because oil often migrates along upturned beds at the margins of the domes. Furthermore, tests in Germany showed that oil could be stored in salt for years with no deterioration in its quality. Ultimately five salt domes were selected as sites for the development of underground storage cavities; a sixth site was a converted salt mine. The caverns, created by solution mining, are typically cylindrical in shape, about 200 feet (65 meters) in diameter and 2000 feet (650 meters) in height. Each would easily hold the Empire State Building, the New York World Trade Center, or three Washington Monuments on top of one other.

Solution mining began with the drilling of a standard well into the salt dome. Fresh water was pumped into the well to dissolve salt, and the resulting brine was pumped into deep injection wells or into the Gulf of Mexico. Once the cavity expanded to the desired width, a small amount of oil was injected into the cavity to float on the water and to protect the salt roof of the cavern from any additional solutions.

Selective injection of the water was used to increase the size of the cavern and to control its shape.

The individual cavities were designed to ultimately hold between 25 and 220 million barrels of petroleum. Filling of the Strategic Petroleum Reserve began in 1977. By late 1994, it contained approximately 600 million barrels of petroleum and had a total capacity of about 750 million barrels. America hopes that it shall never again be faced with an embargo of imported oil, but if it is, the Strategic Petroleum Reserve will be available to help fill the needs.

An unfortunate footnote to the development of the Strategic Petroleum Reserve has been the report, in October 1995, that one of the caverns has developed a serious leak. This forces costly repairs, extraction of some of the oil, and reconsideration of the entire concept.