OIL AND GAS INDUSTRY GLOBAL: April 2017

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Abiogenic petroleum origin

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From Wikipedia, the free encyclopedia

The abiogenic petroleum origin hypothesis proposes that most of earth's petroleum and natural gas deposits were formed inorganically, commonly known as abiotic oil.[1] Scientific evidence overwhelmingly supports a biogenic origin for most of the world's petroleum deposits.[2][3] Mainstream theories about the formation of hydrocarbons on earth point to an origin from the decomposition of long-dead organisms, though the existence of hydrocarbons on extraterrestrial bodies like Saturn's moon Titan indicates that hydrocarbons are sometimes naturally produced by inorganic means. A historical overview of theories of the abiogenic origins of hydrocarbons has been published.[3]

Thomas Gold's "deep gas hypothesis" proposes that some natural gas deposits were formed out of hydrocarbons deep in the Earth's mantle. Earlier studies of mantle-derived rocks from many places have shown that hydrocarbons from the mantle region can be found widely around the globe. However, the content of such hydrocarbons is in low concentration.[4] While there may be large deposits of abiotic hydrocarbons, globally significant amounts of abiotic hydrocarbons are deemed unlikely.[5]

Overview hypotheses

Some abiogenic hypotheses have proposed that oil and gas did not originate from fossil deposits, but have instead originated from deep carbon deposits, present since the formation of the Earth.[6]

The abiogenic hypothesis regained some support in 2009 when researchers at the KTH Royal Institute of Technology in Stockholm reported they believed they had proven that fossils from animals and plants are not necessary for crude oil and natural gas to be generated.[7][8]

History

An abiogenic hypothesis was first proposed by Georgius Agricola in the 16th century and various additional abiogenic hypotheses were proposed in the 19th century, most notably by Prussian geographer Alexander von Humboldt (1804), the Russian chemist Dmitri Mendeleev (1877)[9] and the French chemist Marcellin Berthelot.[when?] Abiogenic hypotheses were revived in the last half of the 20th century by Soviet scientists who had little influence outside the Soviet Union because most of their research was published in Russian. The hypothesis was re-defined and made popular in the West by astronomer Thomas Gold, a prominent proponent of the abiogenic hypothesis, who developed his theories from 1979 to 1998 and published his research in English.

Abraham Gottlob Werner and the proponents of neptunism in the 18th century regarded basaltic sills as solidified oils or bitumen. While these notions proved unfounded, the basic idea of an association between petroleum and magmatism persisted. Von Humboldt proposed an inorganic abiogenic hypothesis for petroleum formation after he observed petroleum springs in the Bay of Cumaux (Cumaná) on the northeast coast of Venezuela. He is quoted as saying, "the petroleum is the product of a distillation from great depth and issues from the primitive rocks beneath which the forces of all volcanic action lie".[10] Other early prominent proponents of what would become the generalized abiogenic hypothesis included Dmitri Mendeleev[11] and Berthelot.

In 1951, the Soviet geologist Nikolai Alexandrovitch Kudryavtsev proposed the modern abiotic hypothesis of petroleum.[12][13] On the basis of his analysis of the Athabasca Oil Sands in Alberta, Canada, he concluded that no "source rocks" could form the enormous volume of hydrocarbons, and therefore offered abiotic deep petroleum as the most plausible explanation. (Humic coals have since been proposed for the source rocks.)[14] Others who continued Kudryavtsev's work included Petr N. Kropotkin, Vladimir B. Porfir'ev, Emmanuil B. Chekaliuk, Vladilen A. Krayushkin, Georgi E. Boyko, Georgi I. Voitov, Grygori N. Dolenko, Iona V. Greenberg, Nikolai S. Beskrovny, and Victor F. Linetsky.

Following Thomas Gold's death in 2004, Jack Kenney of Gas Resources Corporation has recently come into prominence as a proponent of the theories,[15][16][17] supported by studies by researchers at the Royal Institute of Technology (KTH) in Stockholm, Sweden.[7]

Foundations of abiogenic hypotheses

This section may be unbalanced towards certain viewpoints. Please improve the article or discuss the issue on the talk page. (February 2023)

Within the mantle, carbon may exist as hydrocarbons—chiefly methane—and as elemental carbon, carbon dioxide, and carbonates.[17] The abiotic hypothesis posits that the full suite of hydrocarbons found in petroleum can either be generated in the mantle by abiogenic processes,[17] or by biological processing of those abiogenic hydrocarbons, and that the source-hydrocarbons of abiogenic origin can migrate out of the mantle into the crust until they escape to the surface or are trapped by impermeable strata, forming petroleum reservoirs.

Abiogenic hypotheses generally reject the supposition that certain molecules found within petroleum, known as biomarkers, are indicative of the biological origin of petroleum. They contend that these molecules mostly come from microbes feeding on petroleum in its upward migration through the crust, that some of them are found in meteorites, which have presumably never contacted living material, and that some can be generated abiogenically by plausible reactions in petroleum.[16]

Some of the evidence used to support abiogenic theories includes:

Proponents Item

Gold The presence of methane on other planets, meteors, moons and comets[18][19]

Gold, Kenney Proposed mechanisms of abiotically chemically synthesizing hydrocarbons within the mantle[15][16][17]

Kudryavtsev, Gold Hydrocarbon-rich areas tend to be hydrocarbon-rich at many different levels[6]

Kudryavtsev, Gold Petroleum and methane deposits are found in large patterns related to deep-seated large-scale structural features of the crust rather than to the patchwork of sedimentary deposits[6]

Gold Interpretations of the chemical and isotopic composition of natural petroleum[6]

Kudryavtsev, Gold The presence of oil and methane within non-sedimentary rocks upon the Earth[20]

Gold The existence of methane hydrate deposits[6]

Gold Perceived ambiguity in some assumptions and key evidence used in the conventional understanding of petroleum origin.[6][15]

Gold Bituminous coal creation is based upon deep hydrocarbon seeps[6]

Gold Surface carbon budget and oxygen levels stable over geologic time scales[6]

Kudryavtsev, Gold The biogenic explanation does not explain some hydrocarbon deposit characteristics[6]

Szatmari The distribution of metals in crude oils fits better with upper serpentinized mantle, primitive mantle and chondrite patterns than oceanic and continental crust, and show no correlation with sea water[21]

Gold The association of hydrocarbons with helium, a noble gas[clarification needed][6]

Recent investigation of abiogenic hypotheses

This section may be unbalanced towards certain viewpoints. Please improve the article or discuss the issue on the talk page. (July 2009)

As of 2009, little research is directed towards establishing abiogenic petroleum or methane, although the Carnegie Institution for Science has reported that ethane and heavier hydrocarbons can be synthesized under conditions of the upper mantle.[22] Research mostly related to astrobiology and the deep microbial biosphere and serpentinite reactions, however, continues to provide insight into the contribution of abiogenic hydrocarbons into petroleum accumulations.

Rock porosity and migration pathways for abiogenic petroleum.[23]

Mantle peridotite serpentinization reactions and other natural Fischer–Tropsch analogs.[2]

Primordial hydrocarbons in meteorites, comets, asteroids and the solid bodies of the Solar System.[citation needed]

Primordial or ancient sources of hydrocarbons or carbon in Earth.[24][25]

Primordial hydrocarbons formed from hydrolysis of metal carbides of the iron peak of cosmic elemental abundance (chromium, iron, nickel, vanadium, manganese, cobalt).[26]

Isotopic studies of groundwater reservoirs, sedimentary cements, formation gases and the composition of the noble gases and nitrogen in many oil fields.

Common criticisms include:

If oil was created in the mantle, it would be expected that oil would be most commonly found in fault zones, as that would provide the greatest opportunity for oil to migrate into the crust from the mantle. Additionally, the mantle near subduction zones tends to be more oxidizing than the rest. However, the locations of oil deposits have not been found to be correlated with fault zones, with some exceptions.[27]

Proposed mechanisms of abiogenic petroleum

Primordial deposits

Thomas Gold's work was focused on hydrocarbon deposits of primordial origin. Meteorites are believed to represent the major composition of material from which the Earth was formed. Some meteorites, such as carbonaceous chondrites, contain carbonaceous material. If a large amount of this material is still within the Earth, it could have been leaking upward for billions of years. The thermodynamic conditions within the mantle would allow many hydrocarbon molecules to be at equilibrium under high pressure and high temperature. Although molecules in these conditions may disassociate, resulting fragments would be reformed due to the pressure. An average equilibrium of various molecules would exist depending upon conditions and the carbon-hydrogen ratio of the material.[28]

Creation within the mantle

Russian researchers concluded that hydrocarbon mixes would be created within the mantle. Experiments under high temperatures and pressures produced many hydrocarbons—including n-alkanes through C10H22—from iron oxide, calcium carbonate, and water.[17] Because such materials are in the mantle and in subducted crust, there is no requirement that all hydrocarbons be produced from primordial deposits.

Hydrogen generation

Hydrogen gas and water have been found more than 6,000 metres (20,000 ft) deep in the upper crust in the Siljan Ring boreholes and the Kola Superdeep Borehole. Data from the western United States suggests that aquifers from near the surface may extend to depths of 10,000 metres (33,000 ft) to 20,000 metres (66,000 ft). Hydrogen gas can be created by water reacting with silicates, quartz, and feldspar at temperatures in the range of 25 °C (77 °F) to 270 °C (518 °F). These minerals are common in crustal rocks such as granite. Hydrogen may react with dissolved carbon compounds in water to form methane and higher carbon compounds.[29]

One reaction not involving silicates which can create hydrogen is:[24]

Ferrous oxide + water → magnetite + hydrogen

3FeO + H2O → Fe3O4 + H2

The above reaction operates best at low pressures. At pressures greater than 5 gigapascals (49,000 atm) almost no hydrogen is created.[24]

Thomas Gold reported that hydrocarbons were found in the Siljan Ring borehole and in general increased with depth, although the venture was not a commercial success.[30]

However, several geologists analysed the results and said that no hydrocarbon was found.[31][32][33][34][35]

Serpentinite mechanism

In 1967, the Soviet scientist Emmanuil B. Chekaliuk proposed that petroleum could be formed at high temperatures and pressures from inorganic carbon in the form of carbon dioxide, hydrogen or methane.

This mechanism is supported by several lines of evidence which are accepted by modern scientific literature. This involves synthesis of oil within the crust via catalysis by chemically reductive rocks. A proposed mechanism for the formation of inorganic hydrocarbons[36] is via natural analogs of the Fischer–Tropsch process known as the serpentinite mechanism or the serpentinite process.[21][37]

CH4 + ½ O2 → 2 H2 + CO

(2n+1) H2 + nCO → CnH(2n+2) + n H2O

Serpentinites are ideal rocks to host this process as they are formed from peridotites and dunites, rocks which contain greater than 80% olivine and usually a percentage of Fe-Ti spinel minerals. Most olivines also contain high nickel concentrations (up to several percent) and may also contain chromite or chromium as a contaminant in olivine, providing the needed transition metals.

However, serpentinite synthesis and spinel cracking reactions require hydrothermal alteration of pristine peridotite-dunite, which is a finite process intrinsically related to metamorphism, and further, requires significant addition of water. Serpentinite is unstable at mantle temperatures and is readily dehydrated to granulite, amphibolite, talc–schist and even eclogite. This suggests that methanogenesis in the presence of serpentinites is restricted in space and time to mid-ocean ridges and upper levels of subduction zones. However, water has been found as deep as 12,000 metres (39,000 ft),[38] so water-based reactions are dependent upon the local conditions. Oil being created by this process in intracratonic regions is limited by the materials and temperature.

Serpentinite synthesis

A chemical basis for the abiotic petroleum process is the serpentinization of peridotite, beginning with methanogenesis via hydrolysis of olivine into serpentine in the presence of carbon dioxide.[37] Olivine, composed of Forsterite and Fayalite metamorphoses into serpentine, magnetite and silica by the following reactions, with silica from fayalite decomposition (reaction 1a) feeding into the forsterite reaction (1b).

Reaction 1a:

Fayalite + water → magnetite + aqueous silica + hydrogen

3 Fe2SiO4 + 2 H2O → 2 Fe3O4 + 3 SiO2 + 2 H2

Reaction 1b:

Forsterite + aqueous silica → serpentinite

3 Mg2SiO4 + SiO2 + 4 H2O → 2 Mg3Si2O5(OH)4

When this reaction occurs in the presence of dissolved carbon dioxide (carbonic acid) at temperatures above 500 °C (932 °F) Reaction 2a takes place.

Reaction 2a:

Olivine + water + carbonic acid → serpentine + magnetite + methane

(Fe,Mg)2SiO4 + nH2O + CO2 → Mg3Si2O5(OH)4 + Fe3O4 + CH4

or, in balanced form:

18 Mg2SiO4 + 6 Fe2SiO4 + 26 H2O + CO2 → 12 Mg3Si2O5(OH)4 + 4 Fe3O4 + CH4

However, reaction 2(b) is just as likely, and supported by the presence of abundant talc-carbonate schists and magnesite stringer veins in many serpentinised peridotites;

Reaction 2b:

Olivine + water + carbonic acid → serpentine + magnetite + magnesite + silica

(Fe,Mg)2SiO4 + n H2O + CO2 → Mg3Si2O5(OH)4 + MgCO3 + SiO2

The upgrading of methane to higher n-alkane hydrocarbons is via dehydrogenation of methane in the presence of catalyst transition metals (e.g. Fe, Ni). This can be termed spinel hydrolysis.

Spinel polymerization mechanism

Magnetite, chromite and ilmenite are Fe-spinel group minerals found in many rocks but rarely as a major component in non-ultramafic rocks. In these rocks, high concentrations of magmatic magnetite, chromite and ilmenite provide a reduced matrix which may allow abiotic cracking of methane to higher hydrocarbons during hydrothermal events.

Chemically reduced rocks are required to drive this reaction and high temperatures are required to allow methane to be polymerized to ethane. Note that reaction 1a, above, also creates magnetite.

Reaction 3:

Methane + magnetite → ethane + hematite

n CH4 + n Fe3O4 + n H2O → C2H6 + Fe2O3 + HCO

−

+ H+

Reaction 3 results in n-alkane hydrocarbons, including linear saturated hydrocarbons, alcohols, aldehydes, ketones, aromatics, and cyclic compounds.[37]

Carbonate decomposition

Calcium carbonate may decompose at around 500 °C (932 °F) through the following reaction:[24]

Reaction 5:

Hydrogen + calcium carbonate → methane + calcium oxide + water

4 H2 + CaCO3 → CH4 + CaO + 2 H2O

Note that CaO (lime) is not a mineral species found within natural rocks. Whilst this reaction is possible, it is not plausible.

Evidence of abiogenic mechanisms

Theoretical calculations by J.F. Kenney using scaled particle theory (a statistical mechanical model) for a simplified perturbed hard-chain predict that methane compressed to 30,000 bars (3.0 GPa) or 40,000 bars (4.0 GPa) kbar at 1,000 °C (1,830 °F) (conditions in the mantle) is relatively unstable in relation to higher hydrocarbons. However, these calculations do not include methane pyrolysis yielding amorphous carbon and hydrogen, which is recognized as the prevalent reaction at high temperatures.[16][17]

Experiments in diamond anvil high pressure cells have resulted in partial conversion of methane and inorganic carbonates into light hydrocarbons.[39][8]

Biotic (microbial) hydrocarbons

The "deep biotic petroleum hypothesis", similar to the abiogenic petroleum origin hypothesis, holds that not all petroleum deposits within the Earth's rocks can be explained purely according to the orthodox view of petroleum geology. Thomas Gold used the term "the deep hot biosphere" to describe the microbes which live underground.[6]

This hypothesis is different from biogenic oil in that the role of deep-dwelling microbes is a biological source for oil which is not of a sedimentary origin and is not sourced from surface carbon. Deep microbial life is only a contaminant of primordial hydrocarbons. Parts of microbes yield molecules as biomarkers.

Deep biotic oil is considered to be formed as a byproduct of the life cycle of deep microbes. Shallow biotic oil is considered to be formed as a byproduct of the life cycles of shallow microbes.

Microbial biomarkers

Thomas Gold, in a 1999 book, cited the discovery of thermophile bacteria in the Earth's crust as new support for the postulate that these bacteria could explain the existence of certain biomarkers in extracted petroleum.[6] A rebuttal of biogenic origins based on biomarkers has been offered by Kenney, et al. (2001).[16]

Isotopic evidence

Methane is ubiquitous in crustal fluid and gas.[40] Research continues to attempt to characterise crustal sources of methane as biogenic or abiogenic using carbon isotope fractionation of observed gases (Lollar & Sherwood 2006). There are few clear examples of abiogenic methane-ethane-butane, as the same processes favor enrichment of light isotopes in all chemical reactions, whether organic or inorganic. δ13C of methane overlaps that of inorganic carbonate and graphite in the crust, which are heavily depleted in 12C, and attain this by isotopic fractionation during metamorphic reactions.

One argument for abiogenic oil cites the high carbon depletion of methane as stemming from the observed carbon isotope depletion with depth in the crust. However, diamonds, which are definitively of mantle origin, are not as depleted as methane, which implies that methane carbon isotope fractionation is not controlled by mantle values.[31]

Commercially extractable concentrations of helium (greater than 0.3%) are present in natural gas from the Panhandle-Hugoton fields in the US, as well as from some Algerian and Russian gas fields.[41][42]

Helium trapped within most petroleum occurrences, such as the occurrence in Texas, is of a distinctly crustal character with an Ra ratio of less than 0.0001 that of the atmosphere.[43][44]

Biomarker chemicals

Certain chemicals found in naturally occurring petroleum contain chemical and structural similarities to compounds found within many living organisms. These include terpenoids, terpenes, pristane, phytane, cholestane, chlorins and porphyrins, which are large, chelating molecules in the same family as heme and chlorophyll. Materials which suggest certain biological processes include tetracyclic diterpane and oleanane.[citation needed]

The presence of these chemicals in crude oil is a result of the inclusion of biological material in the oil; these chemicals are released by kerogen during the production of hydrocarbon oils, as these are chemicals highly resistant to degradation and plausible chemical paths have been studied. Abiotic defenders state that biomarkers get into oil during its way up as it gets in touch with ancient fossils. However a more plausible explanation is that biomarkers are traces of biological molecules from bacteria (archaea) that feed on primordial hydrocarbons and die in that environment. For example, hopanoids are just parts of the bacterial cell wall present in oil as a contaminant.[6]

Trace metals

Nickel (Ni), vanadium (V), lead (Pb), arsenic (As), cadmium (Cd), mercury (Hg) and others metals frequently occur in oils. Some heavy crude oils, such as Venezuelan heavy crude have up to 45% vanadium pentoxide content in their ash, high enough that it is a commercial source for vanadium. Abiotic supporters argue that these metals are common in Earth's mantle, but relatively high contents of nickel, vanadium, lead and arsenic can be usually found in almost all marine sediments.

Analysis of 22 trace elements in oils correlate significantly better with chondrite, serpentinized fertile mantle peridotite, and the primitive mantle than with oceanic or continental crust, and shows no correlation with seawater.[21]

Reduced carbon

Sir Robert Robinson studied the chemical makeup of natural petroleum oils in great detail, and concluded that they were mostly far too hydrogen-rich to be a likely product of the decay of plant debris, assuming a dual origin for Earth hydrocarbons.[28] However, several processes which generate hydrogen could supply kerogen hydrogenation which is compatible with the conventional explanation.[45] Olefins, the unsaturated hydrocarbons, would have been expected to predominate by far in any material that was derived in that way. He also wrote: "Petroleum ... [seems to be] a primordial hydrocarbon mixture into which bio-products have been added."

This hypothesis was later demonstrated to have been a misunderstanding by Robinson, related to the fact that only short duration experiments were available to him. Olefins are thermally very unstable (which is why natural petroleum normally does not contain such compounds) and in laboratory experiments that last more than a few hours, the olefins are no longer present.[citation needed]

The presence of low-oxygen and hydroxyl-poor hydrocarbons[clarification needed] in natural living media is supported by the presence of natural waxes (n=30+), oils (n=20+) and lipids in both plant matter and animal matter, for instance fats in phytoplankton, zooplankton and so on. These oils and waxes, however, occur in quantities too small to significantly affect the overall hydrogen/carbon ratio of biological materials. However, after the discovery of highly aliphatic biopolymers in algae, and that oil generating kerogen essentially represents concentrates of such materials, no theoretical problem exists anymore.[citation needed] Also, the millions of source rock samples that have been analyzed for petroleum yield by the petroleum industry have confirmed the large quantities of petroleum found in sedimentary basins.

Empirical evidence

Occurrences of abiotic petroleum in commercial amounts in the oil wells in offshore Vietnam are sometimes cited, as well as in the Eugene Island block 330 oil field, and the Dnieper-Donets Basin. However, the origins of all these wells can also be explained with the biotic theory.[2] Modern geologists think that commercially profitable deposits of abiotic petroleum could be found, but no current deposit has convincing evidence that it originated from abiotic sources.[2]

The Soviet school of thought saw evidence of their[clarification needed] hypothesis in the fact that some oil reservoirs exist in non-sedimentary rocks such as granite, metamorphic or porous volcanic rocks. However, opponents noted that non-sedimentary rocks served as reservoirs for biologically originated oil expelled from nearby sedimentary source rock through common migration or re-migration mechanisms.[2]

The following observations have been commonly used to argue for the abiogenic hypothesis, however each observation of actual petroleum can also be fully explained by biotic origin:[2]

Lost City hydrothermal vent field

The Lost City hydrothermal field was determined to have abiogenic hydrocarbon production. Proskurowski et al. wrote, "Radiocarbon evidence rules out seawater bicarbonate as the carbon source for FTT reactions, suggesting that a mantle-derived inorganic carbon source is leached from the host rocks. Our findings illustrate that the abiotic synthesis of hydrocarbons in nature may occur in the presence of ultramafic rocks, water, and moderate amounts of heat."[46]

Siljan Ring crater

The Siljan Ring meteorite crater, Sweden, was proposed by Thomas Gold as the most likely place to test the hypothesis because it was one of the few places in the world where the granite basement was cracked sufficiently (by meteorite impact) to allow oil to seep up from the mantle; furthermore it is infilled with a relatively thin veneer of sediment, which was sufficient to trap any abiogenic oil, but was modelled as not having been subjected to the heat and pressure conditions (known as the "oil window") normally required to create biogenic oil. However, some geochemists concluded by geochemical analysis that the oil in the seeps came from the organic-rich Ordovician Tretaspis shale, where it was heated by the meteorite impact.[47]

In 1986–1990 The Gravberg-1 borehole was drilled through the deepest rock in the Siljan Ring in which proponents had hoped to find hydrocarbon reservoirs. It stopped at the depth of 6,800 metres (22,300 ft) due to drilling problems, after private investors spent $40 million.[32] Some eighty barrels of magnetite paste and hydrocarbon-bearing sludge were recovered from the well; Gold maintained that the hydrocarbons were chemically different from, and not derived from, those added to the borehole, but analyses showed that the hydrocarbons were derived from the diesel fuel-based drilling fluid used in the drilling.[32][33][34][35] This well also sampled over 13,000 feet (4,000 m) of methane-bearing inclusions.[48]

In 1991–1992, a second borehole, Stenberg-1, was drilled a few miles away to a depth of 6,500 metres (21,300 ft), finding similar results.

Bacterial mats

Direct observation of bacterial mats and fracture-fill carbonate and humin of bacterial origin in deep boreholes in Australia are also taken as evidence for the abiogenic origin of petroleum.[49]

Examples of proposed abiogenic methane deposits

Panhandle-Hugoton field (Anadarko Basin) in the south-central United States is the most important gas field with commercial helium content. Some abiogenic proponents interpret this as evidence that both the helium and the natural gas came from the mantle.[43][44][50][51]

The Bạch Hổ oil field in Vietnam has been proposed as an example of abiogenic oil because it is 4,000 m of fractured basement granite, at a depth of 5,000 m.[52] However, others argue that it contains biogenic oil which leaked into the basement horst from conventional source rocks within the Cửu Long basin.[20][53]

A major component of mantle-derived carbon is indicated in commercial gas reservoirs in the Pannonian and Vienna basins of Hungary and Austria.[54]

Natural gas pools interpreted as being mantle-derived are the Shengli Field[55] and Songliao Basin, northeastern China.[56][57]

The Chimaera gas seep, near Çıralı, Antalya (southwest Turkey), has been continuously active for millennia and it is known to be the source of the first Olympic fire in the Hellenistic period. On the basis of chemical composition and isotopic analysis, the Chimaera gas is said to be about half biogenic and half abiogenic gas, the largest emission of biogenic methane discovered; deep and pressurized gas accumulations necessary to sustain the gas flow for millennia, posited to be from an inorganic source, may be present.[58] Local geology of Chimaera flames, at exact position of flames, reveals contact between serpentinized ophiolite and carbonate rocks.[citation needed] Fischer–Tropsch process can be suitable reaction to form hydrocarbon gases.

Geological arguments

Incidental arguments for abiogenic oil

Given the known occurrence of methane and the probable catalysis of methane into higher atomic weight hydrocarbon molecules, various abiogenic theories consider the following to be key observations in support of abiogenic hypotheses:

the serpentinite synthesis, graphite synthesis and spinel catalysation models prove the process is viable[21][37]

the likelihood that abiogenic oil seeping up from the mantle is trapped beneath sediments which effectively seal mantle-tapping faults[36]

outdated[citation needed] mass-balance calculations[when?] for supergiant oilfields which argued that the calculated source rock could not have supplied the reservoir with the known accumulation of oil, implying deep recharge.[12][13]

the presence of hydrocarbons encapsulated in diamonds [59]

The proponents of abiogenic oil also use several arguments which draw on a variety of natural phenomena in order to support the hypothesis:

the modeling of some researchers shows the Earth was accreted at relatively low temperature, thereby perhaps preserving primordial carbon deposits within the mantle, to drive abiogenic hydrocarbon production[citation needed]

the presence of methane within the gases and fluids of mid-ocean ridge spreading centre hydrothermal fields.[36][8]

the presence of diamond within kimberlites and lamproites which sample the mantle depths proposed as being the source region of mantle methane (by Gold et al.).[28]

Incidental arguments against abiogenic oil

Oil deposits are not directly associated with tectonic structures.

Arguments against chemical reactions, such as the serpentinite mechanism, being a source of hydrocarbon deposits within the crust include:

the lack of available pore space within rocks as depth increases.[citation needed]

this is contradicted by numerous studies which have documented the existence of hydrologic systems operating over a range of scales and at all depths in the continental crust.[60]

the lack of any hydrocarbon within the crystalline shield[clarification needed] areas of the major cratons, especially around key deep-seated structures which are predicted to host oil by the abiogenic hypothesis.[31] See Siljan Lake.

lack of conclusive proof[clarification needed] that carbon isotope fractionation observed in crustal methane sources is entirely of abiogenic origin (Lollar et al. 2006)[40]

drilling of the Siljan Ring failed to find commercial quantities of oil,[31] thus providing a counter example to Kudryavtsev's Rule[clarification needed][32] and failing to locate the predicted abiogenic oil.

helium in the Siljan Gravberg-1 well was depleted in 3He and not consistent with a mantle origin[61]

The Gravberg-1 well only produced 84 barrels (13.4 m3) of oil, which later was shown to derive from organic additives, lubricants and mud used in the drilling process.[32][33][34]

Kudryavtsev's Rule has been explained for oil and gas (not coal)—gas deposits which are below oil deposits can be created from that oil or its source rocks. Because natural gas is less dense than oil, as kerogen and hydrocarbons are generating gas the gas fills the top of the available space. Oil is forced down, and can reach the spill point where oil leaks around the edge(s) of the formation and flows upward. If the original formation becomes completely filled with gas then all the oil will have leaked above the original location.[62]

ubiquitous diamondoids in natural hydrocarbons such as oil, gas and condensates are composed of carbon from biological sources, unlike the carbon found in normal diamonds.[31]

Field test evidence

Prognostic map of Andes of South America published in 1986. Red and green circles - sites predicted as future discoveries of giant oil/gas fields. Red circles - where giants were really discovered. Green ones are still underdeveloped.

What unites both theories of oil origin is the low success rate in predicting the locations of giant oil/gas fields: according to the statistics discovering a giant demands drilling 500+ exploration wells. A team of American-Russian scientists (mathematicians, geologists, geophysicists, and computer scientists) developed an Artificial Intelligence software and the appropriate technology for geological applications, and used it for predicting places of giant oil/gas deposits.[63][64][65][66] In 1986 the team published a prognostic map for discovering giant oil and gas fields at the Andes in South America[67] based on abiogenic petroleum origin theory. The model proposed by Prof. Yury Pikovsky (Moscow State University) assumes that petroleum moves from the mantle to the surface through permeable channels created at the intersection of deep faults.[68] The technology uses 1) maps of morphostructural zoning, which outlines the morphostructural nodes (intersections of faults), and 2) pattern recognition program that identify nodes containing giant oil/gas fields. It was forecast that eleven nodes, which had not been developed at that time, contain giant oil or gas fields. These 11 sites covered only 8% of the total area of all the Andes basins. 30 years later (in 2018) was published the result of comparing the prognosis and the reality.[27] Since publication of the prognostic map in 1986 six giant oil/gas fields were discovered in the Andes region: Caño Limón oilfield, Cusiana, Capiagua,[69] Colombia, and Volcanera (Llanos basin, Colombia), Camisea (Ukayali basin, Peru), and Incahuasi (Chaco basin, Bolivia). All discoveries were made in places shown on the 1986 prognostic map as promising areas.[27]

During the 1960s, Donald Hings was issued numerous patents for developing practical methods for locating likely locations of the deep morphological nodes most likely to indicate the presence of abiogenic hydrocarbons. His methods and technologies are used to this day by geophysicists to locate deep hydrocarbon deposits.

Extraterrestrial argument

The presence of methane on Saturn's moon Titan and in the atmospheres of Jupiter, Saturn, Uranus and Neptune is cited as evidence of the formation of hydrocarbons without biological intermediate forms,[2] for example by Thomas Gold.[6] (Terrestrial natural gas is composed primarily of methane). Some comets contain massive amounts of organic compounds, the equivalent of cubic kilometers of such mixed with other material;[70] for instance, corresponding hydrocarbons were detected during a probe flyby through the tail of Comet Halley in 1986.[71]

Drill samples from the surface of Mars taken in 2015 by the Curiosity rover's Mars Science Laboratory have found organic molecules of benzene and propane in 3 billion year old rock samples in Gale Crater.[72]

Hydrocarbon exploration

Hydrocarbon exploration (or oil and gas exploration) is the search by petroleum geologists and geophysicists for hydrocarbon deposits, particularly petroleum and natural gas, in the Earth's crust using petroleum geology.

Exploration methods

Visible surface features such as oil seeps, natural gas seeps, pockmarks (underwater craters caused by escaping gas) provide basic evidence of hydrocarbon generation (be it shallow or deep in the Earth). However, most exploration depends on highly sophisticated technology to detect and determine the extent of these deposits using exploration geophysics. Areas thought to contain hydrocarbons are initially subjected to a gravity survey, magnetic survey, passive seismic or regional seismic reflection surveys to detect large-scale features of the sub-surface geology. Features of interest (known as leads) are subjected to more detailed seismic surveys which work on the principle of the time it takes for reflected sound waves to travel through matter (rock) of varying densities and using the process of depth conversion to create a profile of the substructure. Finally, when a prospect has been identified and evaluated and passes the oil company's selection criteria, an exploration well is drilled in an attempt to conclusively determine the presence or absence of oil or gas. In Offshore operations the risk can be reduced by using electromagnetic survey methods (EM)[1]

Oil exploration is an expensive, high-risk operation. Offshore and remote area exploration is generally only undertaken by very large corporations or national governments. Typical shallow shelf oil wells (e.g. North Sea) cost US$10 – 30 million, while deep water wells can cost up to US$100 million plus. Hundreds of smaller companies search for onshore hydrocarbon deposits worldwide, with some wells costing as little as US$100,000.

Elements of a petroleum prospect

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A petroleum prospect is a potential trap which geologists believe may contain hydrocarbons. A significant amount of geological, structural and seismic investigation and analysis must first be completed to define the potential hydrocarbon drill location from a lead to a prospect. Four geological factors have to be present for a prospect to work and if any of them fail neither oil nor gas will be present.

Source rock

When an organic-rich rock such as oil shale or coal is subjected to high pressure and temperature over an extended period of time, hydrocarbons is formed.

Migration

Migration is the movement of petroleum from the source rock to the reservoir. The hydrocarbons are expelled from source rock by three density-related mechanisms: the newly matured hydrocarbons are less dense than their precursors, which causes over-pressure; the hydrocarbons are lighter, and so migrate upwards due to buoyancy, and the fluids expand as further burial causes increased heating. Most hydrocarbons migrate to the surface as oil seeps, but some will get trapped.

Reservoir

The hydrocarbons are contained in a reservoir rock. This is commonly a porous sandstone or limestone. The oil collects in the pores within the rock although open fractures within non-porous rocks (e.g. fractured granite) may also store hydrocarbons. The reservoir must also be permeable so that the hydrocarbons will flow to surface during production.

Trap

The hydrocarbons are buoyant and have to be trapped within a structural (e.g. Anticline, fault block) or stratigraphic trap. The hydrocarbon trap has to be covered by an impermeable rock known as a seal or cap-rock in order to prevent hydrocarbons escaping to the surface.

Exploration risk

Onshore drilling rig

Seismic reflection survey being conducted in Saudi Arabia, circa 1960. A controlled explosion generates seismic waves that are detected by geophones.

Mud log in process, a common way to study the rock types when drilling oil wells.

Oil exploration expenditures are greatest when crude oil prices are high

Hydrocarbon exploration is a high risk investment and risk assessment is paramount for successful project portfolio management. Exploration risk is a difficult concept and is usually defined by assigning confidence to the presence of the imperative geological factors, as discussed above. This confidence is based on data and/or models and is usually mapped on Common Risk Segment Maps (CRS Maps). High confidence in the presence of imperative geological factors is usually coloured green and low confidence coloured red.[2] Therefore, these maps are also called Traffic Light Maps, while the full procedure is often referred to as Play Fairway Analysis (PFA).[3] The aim of such procedures is to force the geologist to objectively assess all different geological factors. Furthermore, it results in simple maps that can be understood by non-geologists and managers to base exploration decisions on.

Terms used in petroleum evaluation

Bright spot

On a seismic section, coda that have high amplitudes due to a formation containing hydrocarbons.

Chance of success

An estimate of the chance of all the elements (see above) within a prospect working, described as a probability.

Dry hole

A boring that does not contain commercial hydrocarbons. See also Dry-hole clause

Flat spot

Possibly an oil-water, gas-water or gas-oil contact on a seismic section; flat due to gravity.

Full Waveform Inversion

A supercomputer technique recently use in conjunction with seismic sensors to explore for petroleum deposits offshore.[4]

Hydrocarbon in place

Amount of hydrocarbon likely to be contained in the prospect. This is calculated using the volumetric equation - GRV x N/G x Porosity x Sh / FVF

Gross rock volume (GRV)

Amount of rock in the trap above the hydrocarbon water contact

Net sand

Part of GRV that has the lithological capacity for being a productive zone; i.e. less shale contaminations.[5]

Net reserve

Part of net sand that has the minimum reservoir qualities; i.e. minimum porosity and permeability values.[5]

Net/gross ratio (N/G)

Proportion of the GRV formed by the reservoir rock (range is 0 to 1)

Porosity

Percentage of the net reservoir rock occupied by pores (typically 5-35%)

Hydrocarbon saturation (Sh)

Some of the pore space is filled with water - this must be discounted

Formation volume factor (FVF)

Oil shrinks and gas expands when brought to the surface. The FVF converts volumes at reservoir conditions (high pressure and high temperature) to storage and sale conditions

Lead

Potential accumulation is currently poorly defined and requires more data acquisition and/or evaluation in order to be classified as a prospect.[6]

Play

An area in which hydrocarbon accumulations or prospects of a given type occur. For example, the shale gas plays in North America include the Barnett, Eagle Ford, Fayetteville, Haynesville, Marcellus, and Woodford, among many others.[7]

Prospect

A lead which has been more fully evaluated.

Recoverable hydrocarbons

Amount of hydrocarbon likely to be recovered during production. This is typically 10-50% in an oil field and 50-80% in a gas field.

Licensing

Petroleum resources are typically owned by the government of the host country. In the United States, most onshore (land) oil and gas rights (OGM) are owned by private individuals, in which case oil companies must negotiate terms for a lease of these rights with the individual who owns the OGM. Sometimes this is not the same person who owns the land surface. In most nations the government issues licences to explore, develop and produce its oil and gas resources, which are typically administered by the oil ministry. There are several different types of licence. Oil companies often operate in joint ventures to spread the risk; one of the companies in the partnership is designated the operator who actually supervises the work.

Tax and Royalty

Companies would pay a royalty on any oil produced, together with a profits tax (which can have expenditure offset against it). In some cases there are also various bonuses and ground rents (license fees) payable to the government - for example a signature bonus payable at the start of the licence. Licences are awarded in competitive bid rounds on the basis of either the size of the work programme (number of wells, seismic etc.) or size of the signature bonus.

Production Sharing contract (PSA)

A PSA is more complex than a Tax/Royalty system - The companies bid on the percentage of the production that the host government receives (this may be variable with the oil price), There is often also participation by the Government owned National Oil Company (NOC). There are also various bonuses to be paid. Development expenditure is offset against production revenue.

Service contract

This is when an oil company acts as a contractor for the host government, being paid to produce the hydrocarbons.

Reserves and resources

Resources are hydrocarbons which may or may not be produced in the future. A resource number may be assigned to an undrilled prospect or an unappraised discovery. Appraisal by drilling additional delineation wells or acquiring extra seismic data will confirm the size of the field and lead to project sanction. At this point the relevant government body gives the oil company a production licence which enables the field to be developed. This is also the point at which oil reserves and gas reserves can be formally booked.

Oil and gas reserves

Oil and gas reserves are defined as volumes that will be commercially recovered in the future. Reserves are separated into three categories: proved, probable, and possible. To be included in any reserves category, all commercial aspects must have been addressed, which includes government consent. Technical issues alone separate proved from unproved categories. All reserve estimates involve some degree of uncertainty.

Proved reserves are the highest valued category. Proved reserves have a "reasonable certainty" of being recovered, which means a high degree of confidence that the volumes will be recovered. Some industry specialists refer to this as P90, i.e., having a 90% certainty of being produced. The SEC provides a more detailed definition:

Proved oil and gas reserves are those quantities of oil and gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible—from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations—prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time.[8]

Probable reserves are volumes defined as "less likely to be recovered than proved, but more certain to be recovered than Possible Reserves". Some industry specialists refer to this as P50, i.e., having a 50% certainty of being produced.

Possible reserves are reserves which analysis of geological and engineering data suggests are less likely to be recoverable than probable reserves. Some industry specialists refer to this as P10, i.e., having a 10% certainty of being produced.

The term 1P is frequently used to denote proved reserves; 2P is the sum of proved and probable reserves; and 3P the sum of proved, probable, and possible reserves. The best estimate of recovery from committed projects is generally considered to be the 2P sum of proved and probable reserves. Note that these volumes only refer to currently justified projects or those projects already in development.[9]

Reserve booking

Oil and gas reserves are the main asset of an oil company. Booking is the process by which they are added to the balance sheet.

In the United States, booking is done according to a set of rules developed by the Society of Petroleum Engineers (SPE). The reserves of any company listed on the New York Stock Exchange have to be stated to the U.S. Securities and Exchange Commission. Reported reserves may be audited by outside geologists, although this is not a legal requirement.

In Russia, companies report their reserves to the State Commission on Mineral Reserves (GKZ).[citation needed]

Friday, April 21, 2017

Oil and gas reserves and resource quantification

Oil and gas reserves denote discovered quantities of crude oil and natural gas from known fields that can be profitably produced/recovered from an approved development. Oil and gas reserves tied to approved operational plans filed on the day of reserves reporting are also sensitive to fluctuating global market pricing. The remaining resource estimates (after the reserves have been accounted) are likely sub-commercial and may still be under appraisal with the potential to be technically recoverable once commercially established. Natural gas is frequently associated with oil directly and gas reserves are commonly quoted in barrels of oil equivalent (BOE). Consequently, both oil and gas reserves, as well as resource estimates, follow the same reporting guidelines, and are referred to collectively hereinafter as oil & gas.[1]

Quantification

An oil well in Canada

As with other mineral resource estimation, detailed classification schemes have been devised by industry specialists to quantify volumes of oil and gas accumulated underground (known as subsurface). These schemes provide management and investors with the means to make quantitative and relative comparisons between assets,[a] before underwriting the significant cost of exploring for, developing and extracting those accumulations.[2] Classification schemes are used to categorize the uncertainty in volume estimates of the recoverable oil and gas and the chance that they exist in reality (or risk that they do not) depending on the resource maturity.[b] Potential subsurface oil and gas accumulations identified during exploration are classified and reported as prospective resources. Resources are re-classified as reserves following appraisal, at the point when a sufficient accumulation of commercial oil and/or gas are proven by drilling, with authorized and funded development plans to begin production within a recommended five years.[3]

Reserve estimates are required by authorities and companies, and are primarily made to support operational or investment decision-making by companies or organisations involved in the business of developing and producing oil and gas. Reserve volumes are necessary to determine the financial status of the company, which may be obliged to report those estimates to shareholders and "resource holders"[c] at the various stages of resource maturation.[d][4]

Currently, the most widely accepted classification and reporting methodology is the 2018 petroleum resources management system (PRMS), which summarizes a consistent approach to estimating oil and gas quantities within a comprehensive classification framework, jointly developed by the Society of Petroleum Engineers (SPE), the World Petroleum Council (WPC), the American Association of Petroleum Geologists (AAPG), the Society of Petroleum Evaluation Engineers (SPEE) and the Society of Economic Geologists (SEG).[e][5] Public companies that register securities in the U.S. market must report proved reserves under the Securities and Exchange Commission (SEC) reporting requirements which shares many elements with PRMS.[f] Attempts have also been made to standardize more generalized methodologies for the reporting of national or basin level oil and gas resource assessments.[6]

Reserves and resource reporting

An oil or gas resource refers to known (discovered fields) or potential accumulations of oil and/or gas (i.e undiscovered prospects and leads) in the subsurface of the Earth's crust. All reserve and resource estimates involve uncertainty in volume estimates (expressed below as Low, Mid or High uncertainty), as well as a risk or chance to exist in reality,[g] depending on the level of appraisal or resource maturity that governs the amount of reliable geologic and engineering data available and the interpretation of those data.[h]

TABLE I:Classification summary featuring volumes uncertainty (low, mid or high) with increasing chance for an accumulation to exist and be commercial upwards reflecting greater resource maturity

RESOURCE CLASS LOW MID HIGH

Reserves 1P 2P 3P

Contingent Resources 1C 2C 3C

Prospective Resources 1U 2U 3U

Estimating and monitoring of reserves provides an insight into, for example, a company's future production and a country's oil & gas supply potential. As such, reserves are an important means of expressing value and longevity of resources.

In the PRMS, the terms 'Resources' and 'Reserves' have distinct and specific meaning with respect to oil & gas accumulations and hydrocarbon exploration in general. However, the level of rigor required in applying these terms varies depending on the resource maturity which informs reporting requirements.[i] Oil & gas reserves are resources that are, or are reasonably certain to be, commercial (i.e. profitable). Reserves are the main asset of an oil & gas company; booking is the process by which they are added to the balance sheet. Contingent and prospective resource estimates are much more speculative and are not booked with the same degree of rigor, generally for internal company use only, reflecting a more limited data set and assessment maturity. If published externally, these volumes add to the perception of asset value, which in turn can influence oil & gas company share or stock value.[7] The PRMS provides a framework for a consistent approach to the estimation process to comply with reporting requirements of particularly, listed companies.[8][j] Energy companies may employ specialist, independent, reserve valuation consultants to provide third party reports as part of SEC filings for either reserves or resource booking.[k]

Reserves

Reserves reporting of discovered accumulations is regulated by tight controls for informed investment decisions to quantify differing degrees of uncertainty in recoverable volumes. Reserves are defined in three sub-categories according to the system used in the PRMS: Proven (1P), Probable and Possible. Reserves defined as Probable and Possible are incremental (or additional) discovered volumes based on geological and/or engineering criteria similar to those used in estimating Proven reserves. Though not classified as contingent, some technical, contractual, or regulatory uncertainties preclude such reserves being classified as Proven. The most accepted definitions of these are based on those originally approved by the SPE and the WPC in 1997, requiring that reserves are discovered, recoverable, commercial and remaining based on rules governing the classification into sub-categories and the declared development project plans applied.[9] Probable and Possible reserves may be used internally by oil companies and government agencies for future planning purposes but are not routinely or uniformly compiled.

Proven reserves

Main article: Proven reserves

Proven reserves are discovered volumes claimed to have a reasonable certainty of being recoverable under existing economic and political conditions, and with existing technology. Industry specialists refer to this category as "P90" (that is, having a 90% certainty of producing or exceeding the P90 volume on the probability distribution).[l] Proven reserves are also known in the industry as 1P.[10][11] Proven reserves may be referred to as proven developed (PD) or as proven undeveloped (PUD).[11][12] PD reserves are reserves that can be produced with existing wells and perforations, or from additional reservoirs where minimal additional investment (operating expense) is required (e.g. opening a set of perforations already installed).[12] PUD reserves require additional capital investment (e.g., drilling new wells) to bring the oil and/or gas to the surface.[10][12]

Accounting for production is an important exercise for businesses. Produced oil or gas that has been brought to surface (production) and sold on international markets or refined in-country are no longer reserves and are removed from the booking and company balance sheets. Until January 2010, "1P" proven reserves were the only type the U.S. SEC allowed oil companies to report to investors. Companies listed on U.S. stock exchanges may be called upon to verify their claims confidentially, but many governments and national oil companies do not disclose verifying data publicly. Since January 2010 the SEC now allows companies to also provide additional optional information declaring 2P (both proven and probable) and 3P (proven plus probable plus possible)[m] with discretionary verification by qualified third party consultants, though many companies choose to use 2P and 3P estimates only for internal purposes.[10]

Probable and possible reserves

An example of a Volume Uncertainty Distribution, with the P10, P50 and P90 volumes indicated (created using a probabilistic calculation method)

Probable additional reserves are attributed to known accumulations and the probabilistic, cumulative sum of proven and probable reserves (with a probability of P50), also referred to in the industry as "2P" (Proven plus Probable)[13] The P50 designation means that there should be at least a 50% chance that the actual volumes recovered will be equal to or will exceed the 2P estimate.

Possible additional reserves are attributed to known accumulations that have a lower chance of being recovered than probable reserves.[1] Reasons for assigning a lower probability to recovering Possible reserves include varying interpretations of geology, uncertainty due to reserve infill (associated with variability in seepage towards a production well from adjacent areas) and projected reserves based on future recovery methods. The probabilistic, cumulative sum of proven, probable and possible reserves is referred to in the industry as "3P" (proven plus probable plus possible) where there is a 10% chance of delivering or exceeding the P10 volume.(ibid)

Resource estimates

Resource estimates are undiscovered volumes, or volumes that have not yet been drilled and flowed to surface. A non-reserve resource, by definition, does not have to be technically or commercially recoverable and can be represented by a single, or an aggregate of multiple potential accumulations, e.g. an estimated geological basin resource.[14]

Schematic graph illustrating petroleum volumes and probabilities. Curves represent categories of oil in assessment. There is a 95% chance i.e., probability, (P95 and often referred to in the industry as F95) of at least volume V1 of economically recoverable oil, and there is a 5% chance (P05 or F05) of at least volume V2 of economically recoverable oil.[15]

There are two non-reserve resource categories:

Contingent resources

Once a discovery has been made, prospective resources can be reclassified as contingent resources. Contingent resources are those accumulations or fields that are not yet considered mature enough for commercial development, where development is contingent on one or more conditions changing.[n] The uncertainty in the estimates for recoverable oil & gas volumes is expressed in a probability distribution and is sub-classified based on project maturity and/or economic status (1C, 2C, 3C, ibid) and in addition are assigned a risk, or chance, to exist in reality (POS or COS).[g]

Prospective resources

Prospective resources, being undiscovered, have the widest range in volume uncertainties and carry the highest risk or chance to be present in reality (POS or COS).[g] At the exploration stage (before discovery) they are categorized by the wide range of volume uncertainties (typically P90-P50-P10).[16] In the PRMS the range of volumes is classified by the abbreviations 1U, 2U and 3U again reflecting the degrees of uncertainty.[o] Companies are commonly not required to report publicly their views of prospective resources but may choose to do so voluntarily.[p][17]

Estimation techniques

The total estimated quantity (volumes) of oil and/or gas contained in a subsurface reservoir, is called oil or gas initially in place (STOIIP or GIIP respectively).[12] However, only a fraction of this oil & gas in place can be brought to the surface (recoverable),[q] and it is only this producible fraction that is considered to be either reserves or a resource of any kind.[18] The ratio between oil and gas in place and recoverable volumes is known as the recovery factor (RF), which is determined by a combination of subsurface geology and the technology applied to extraction.[13] When reporting oil & gas volumes, in order to avoid confusion, it should be clarified whether they are oil in place or recoverable volumes.

The appropriate technique for resource estimations is determined by resource maturity. There are three main categories of technique, which are used through resource maturation to differing degrees: analog (substitution), volumetric (static) and performance-based (dynamic), which are combined to help fill gaps in knowledge or data. Both probabilistic and deterministic calculation methods are commonly used to calculate resource volumes, with deterministic methods predominantly applied to reserves estimation (low uncertainty) and probabilistic methods applied to general resource estimation (high uncertainty).[19]

TABLE II:Estimation techniques applied with decreasing resource maturity to the right

Method Technique 1P 2P 3P 1C 2C 3C 1U 2U 3U

Analog YTF (No segment production) ☉ ☉ ☉

YTF (With segment production) ☉ ☉ ☉

Volumetric Deterministic ☉ ☉ ☉ ☉ ☉ ☉ ☉ ☉ ☉

Probabilistic models ☉ ☉ ☉ ☉ ☉ ☉ ☉ ☉ ☉

Static reservoir models ☉ ☉ ☉ ☉ ☉ ☉

Performance-based Dynamic reservoir simulation ☉ ☉ ☉ ☉

Material balance ☉ ☉

Decline curve analysis ☉ ☉

Unconventional reservoir Pilot (rate transient) ☉ ☉ ☉ ☉ ☉ ☉ ☉ ☉ ☉

The combination of geological, geophysical and technical engineering constraints means that the quantification of volumes is usually undertaken by integrated technical, and commercial teams composed primarily of geoscientists and subsurface engineers, surface engineers and economists. Because the geology of the subsurface cannot be examined directly, indirect techniques must be used to estimate the size and recoverability of the resource. While new technologies have increased the accuracy of these estimation techniques, significant uncertainties still remain, which are expressed as a range of potential recoverable oil & gas quantities using probabilistic methods.[r] In general, most early estimates of the reserves of an oil or gas field (rather than resource estimates) are conservative and tend to grow with time.[20] This may be due to the availability of more data and/or the improved matching between predicted and actual production performance.

Appropriate external reporting of resources and reserves is required from publicly traded companies, and is an accounting process governed by strict definitions and categorisation administered by authorities regulating the stock market and complying with governmental legal requirements.[21] Other national or industry bodies may voluntarily report resources and reserves but are not required to follow the same strict definitions and controls.[22]

Analog (YTF) method

Analogs are applied to prospective resources in areas where there are little, or sometimes no, existing data available to inform analysts about the likely potential of an opportunity or play segment.[1] Analog-only techniques are called yet-to-find (YTF), and involve identifying areas containing producing assets that are geologically similar to those being estimated and substituting data to match what is known about a segment.[14][s] The opportunity segment can be scaled to any level depending on the specific interest of the analyst, whether at a global, country, basin, structural domain, play, license or reservoir level.[t][23] YTF is conceptual and is commonly used as a method for scoping potential in frontier areas where there is no oil or gas production or where new play concepts are being introduced with perceived potential. However, analog content can also be substituted for any subsurface parameters where there are gaps in data in more mature reserves or resource settings (below).[24]

Volumetric method

Oil & gas volumes in a conventional reservoir can be calculated using a volume equation:

Recoverable volume = Gross Rock Volume[D 1] * Net/Gross[D 2] * Porosity[D 3] * Oil or Gas Saturation[D 4] * Recovery Factor[D 5] / Formation Volume Factor[D 6][25][26]

Deterministic volumes are calculated when single values are used as input parameters to this equation, which could include analog content. Probabilistic volumes are calculations when uncertainty distributions are applied as input to all or some of the terms of the equation (see also Copula (probability theory)), which preserve dependencies between parameters. These geostatistical methods are most commonly applied to prospective resources that still need to be tested by the drill bit. Contingent resources are also characterized by volumetric methods with analog content and uncertainty distributions before significant production has occurred, where spatial distribution information may be preserved in a static reservoir model.[1] Static models and dynamic flow models can be populated with analog reservoir performance data to increase the confidence in forecasting as the amount and quality of static geoscientific and dynamic reservoir performance data increase.[27]

Performance-based methods

Once production has commenced, production rates and pressure data allow a degree of prediction on reservoir performance, which was previously characterized by substituting analog data. Analog data can still be substituted for expected reservoir performance where specific dynamic data may be missing, representing a "best technical" outcome.[24]

Reservoir simulation

Main article: Reservoir simulation

Reservoir simulation is an area of reservoir engineering in which computer models are used to predict the flow of fluids (typically, oil, water, and gas) through porous media. The amount of oil & gas recoverable from a conventional reservoir is assessed by accurately characterising the static recoverable volumes and history matching that to dynamic flow.[u] Reservoir performance is important because the recovery changes as the physical environment of the reservoir adjusts with every molecule extracted; the longer a reservoir has been flowing, the more accurate the prediction of remaining reserves. Dynamic simulations are commonly used by analysts to update reserves volumes, particularly in large complex reservoirs. Daily production can be matched against production forecasts to establish the accuracy of simulation models based on actual volumes of recovered oil or gas. Unlike analogs or volumetric methods above, the degree of confidence in the estimates (or the range of outcomes) increases as the amount and quality of geological, engineering and production performance data increase. These must then be compared with previous estimates, whether derived from analog, volumetric or static reservoir modelling before reserves can be adjusted and booked.[27]

Materials balance method

The materials balance method for an oil or gas field uses an equation that relates the volume of oil, water and gas that has been produced from a reservoir and the change in reservoir pressure to calculate the remaining oil & gas. It assumes that, as fluids from the reservoir are produced, there will be a change in the reservoir pressure that depends on the remaining volume of oil & gas. The method requires extensive pressure-volume-temperature analysis and an accurate pressure history of the field. It requires some production to occur (typically 5% to 10% of ultimate recovery), unless reliable pressure history can be used from a field with similar rock and fluid characteristics.[13]

Production decline curve method

Example of a production decline curve for an individual well

The decline curve method is an extrapolation of known production data to fit a decline curve and estimate future oil & gas production. The three most common forms of decline curves are exponential, hyperbolic, and harmonic. It is assumed that the production will decline on a reasonably smooth curve, and so allowances must be made for wells shut in and production restrictions. The curve can be expressed mathematically or plotted on a graph to estimate future production. It has the advantage of (implicitly) conflating all reservoir characteristics. It requires a sufficient production history to establish a statistically significant trend, ideally when production is not curtailed by regulatory or other artificial conditions.[13]

Reserves growth

Experience shows that initial estimates of the size of newly discovered oil & gas fields are usually too low. As years pass, successive estimates of the ultimate recovery of fields tend to increase. The term reserve growth refers to the typical increases (but narrowing range) of estimated ultimate recovery that occur as oil & gas fields are developed and produced.[20] Many oil-producing nations do not reveal their reservoir engineering field data and instead provide unaudited claims for their oil reserves. The numbers disclosed by some national governments are suspected of being manipulated for political reasons.[28][29] In order to achieve international goals for decarbonisation, the International Energy Agency said in 2021 that countries should no longer expand exploration or invest in projects to expand reserves to meet climate goals set by the Paris Agreement.[30]

Unconventional reservoirs

Main article: Unconventional (oil & gas) reservoir

The categories and estimation techniques outlined in the PRMS above apply only to conventional reservoirs, where oil & gas accumulations are controlled by hydrodynamic interactions between the buoyancy of oil & gas in water versus capillary forces.[1] Oil or gas in unconventional reservoirs are much more tightly bound to rock matrices in excess of capillary forces and therefore require different approaches to both extraction and resource estimation. Unconventional reservoirs or accumulations also require different means of identification and include coalbed methane (CBM), basin-centered gas (low permeability), low permeability tight gas (including shale gas) and tight oil (including shale oil), gas hydrates, natural bitumen (very high viscosity oil), and oil shale (kerogen) deposits. Ultra low permeability reservoirs exhibit a half slope on a log-plot of flow-rates against time believed to be caused by drainage from matrix surfaces into adjoining fractures.[31] Such reservoirs are commonly believed to be regionally pervasive that may be interrupted by regulatory or ownership boundaries with the potential for large oil & gas volumes, which are very hard to verify. Non-unique flow characteristics in unconventional accumulations means that commercial viability depends on the technology applied to extraction. Extrapolations from a single control point, and thereby resource estimation, are dependent on nearby producing analogs with evidence of economic viability. Under these circumstances, pilot projects may be needed to define reserves.[1] Any other resource estimates are likely to be analog-only derived YTF volumes, which are speculative.

Thursday, April 20, 2017

Oil refinery

An oil refinery or petroleum refinery is an industrial process plant where petroleum (crude oil) is transformed and refined into products such as gasoline (petrol), diesel fuel, asphalt base, fuel oils, heating oil, kerosene, liquefied petroleum gas and petroleum naphtha.[1][2][3] Petrochemical feedstock like ethylene and propylene can also be produced directly by cracking crude oil without the need of using refined products of crude oil such as naphtha.[4][5] The crude oil feedstock has typically been processed by an oil production plant. There is usually an oil depot at or near an oil refinery for the storage of incoming crude oil feedstock as well as bulk liquid products. In 2020, the total capacity of global refineries for crude oil was about 101.2 million barrels per day.[6]

Oil refineries are typically large, sprawling industrial complexes with extensive piping running throughout, carrying streams of fluids between large chemical processing units, such as distillation columns. In many ways, oil refineries use many different technologies and can be thought of as types of chemical plants. Since December 2008, the world's largest oil refinery has been the Jamnagar Refinery owned by Reliance Industries, located in Gujarat, India, with a processing capacity of 1.24 million barrels (197,000 m3) per day.

Oil refineries are an essential part of the petroleum industry's downstream sector.[7]

History

The Chinese were among the first civilizations to refine oil.[8] As early as the first century, the Chinese were refining crude oil for use as an energy source.[9][8] Between 512 and 518, in the late Northern Wei dynasty, the Chinese geographer, writer and politician Li Daoyuan introduced the process of refining oil into various lubricants in his famous work Commentary on the Water Classic.[10][9][8]

Crude oil was often distilled by Persian chemists, with clear descriptions given in handbooks such as those of Muhammad ibn Zakarīya Rāzi (c. 865–925).[11] The streets of Baghdad were paved with tar, derived from petroleum that became accessible from natural fields in the region. In the 9th century, oil fields were exploited in the area around modern Baku, Azerbaijan. These fields were described by the Arab geographer Abu al-Hasan 'Alī al-Mas'ūdī in the 10th century, and by Marco Polo in the 13th century, who described the output of those wells as hundreds of shiploads.[12] Arab and Persian chemists also distilled crude oil in order to produce flammable products for military purposes. Through Islamic Spain, distillation became available in Western Europe by the 12th century.[13]

In the Northern Song dynasty (960–1127), a workshop called the "Fierce Oil Workshop", was established in the city of Kaifeng to produce refined oil for the Song military as a weapon. The troops would then fill iron cans with refined oil and throw them toward the enemy troops, causing a fire – effectively the world's first "fire bomb". The workshop was one of the world's earliest oil refining factories where thousands of people worked to produce Chinese oil-powered weaponry.[14]

Prior to the nineteenth century, petroleum was known and utilized in various fashions in Babylon, Egypt, China, Philippines, Rome and Azerbaijan. However, the modern history of the petroleum industry is said to have begun in 1846 when Abraham Gessner of Nova Scotia, Canada devised a process to produce kerosene from coal. Shortly thereafter, in 1854, Ignacy Łukasiewicz began producing kerosene from hand-dug oil wells near the town of Krosno, Poland.

Romania was registered as the first country in world oil production statistics, according to the Academy Of World Records.[15][16]

In North America, the first oil well was drilled in 1858 by James Miller Williams in Oil Springs, Ontario, Canada.[17] In the United States, the petroleum industry began in 1859 when Edwin Drake found oil near Titusville, Pennsylvania.[18] The industry grew slowly in the 1800s, primarily producing kerosene for oil lamps. In the early twentieth century, the introduction of the internal combustion engine and its use in automobiles created a market for gasoline that was the impetus for fairly rapid growth of the petroleum industry. The early finds of petroleum like those in Ontario and Pennsylvania were soon outstripped by large oil "booms" in Oklahoma, Texas and California.[19]

Samuel Kier established America's first oil refinery in Pittsburgh on Seventh Avenue near Grant Street, in 1853.[20] Polish pharmacist and inventor Ignacy Łukasiewicz established an oil refinery in Jasło, then part of the Austro-Hungarian Empire (now in Poland) in 1854.

The first large refinery opened at Ploiești, Romania, in 1856–1857.[15] It was in Ploiesti that, 51 years later, in 1908, Lazăr Edeleanu, a Romanian chemist of Jewish origin who got his PhD in 1887 by discovering amphetamine, invented, patented and tested on industrial scale the first modern method of liquid extraction for refining crude oil, the Edeleanu process. This increased the refining efficiency compared to pure fractional distillation and allowed a massive development of the refining plants. Successively, the process was implemented in France, Germany, U.S. and in a few decades became worldwide spread. In 1910 Edeleanu founded "Allgemeine Gesellschaft für Chemische Industrie" in Germany, which, given the success of the name, changed to Edeleanu GmbH, in 1930. During Nazi's time, the company was bought by the Deutsche Erdöl-AG and Edeleanu, being of Jewish origin, moved back to Romania. After the war, the trademark was used by the successor company EDELEANU Gesellschaft mbH Alzenau (RWE) for many petroleum products, while the company was lately integrated as EDL in the Pörner Group. The Ploiești refineries, after being taken over by Nazi Germany, were bombed in the 1943 Operation Tidal Wave by the Allies, during the Oil Campaign of World War II.

Another close contender for the title of hosting the world's oldest oil refinery is Salzbergen in Lower Saxony, Germany. Salzbergen's refinery was opened in 1860.

At one point, the refinery in Ras Tanura, Saudi Arabia owned by Saudi Aramco was claimed to be the largest oil refinery in the world. For most of the 20th century, the largest refinery was the Abadan Refinery in Iran. This refinery suffered extensive damage during the Iran–Iraq War. Since 25 December 2008, the world's largest refinery complex is the Jamnagar Refinery Complex, consisting of two refineries side by side operated by Reliance Industries Limited in Jamnagar, India with a combined production capacity of 1,240,000 barrels per day (197,000 m3/d). PDVSA's Paraguaná Refinery Complex in Paraguaná Peninsula, Venezuela, with a capacity of 940,000 bbl/d (149,000 m3/d) but effective run rates have been dramatically lower due to the impact of 20 years of sanctions[citation needed], and SK Energy's Ulsan in South Korea with 840,000 bbl/d (134,000 m3/d) are the second and third largest, respectively.

Prior to World War II in the early 1940s, most petroleum refineries in the United States consisted simply of crude oil distillation units (often referred to as atmospheric crude oil distillation units). Some refineries also had vacuum distillation units as well as thermal cracking units such as visbreakers (viscosity breakers, units to lower the viscosity of the oil). All of the many other refining processes discussed below were developed during the war or within a few years after the war. They became commercially available within 5 to 10 years after the war ended and the worldwide petroleum industry experienced very rapid growth. The driving force for that growth in technology and in the number and size of refineries worldwide was the growing demand for automotive gasoline and aircraft fuel.

In the United States, for various complex economic and political reasons, the construction of new refineries came to a virtual stop in about the 1980s. However, many of the existing refineries in the United States have revamped many of their units and/or constructed add-on units in order to: increase their crude oil processing capacity, increase the octane rating of their product gasoline, lower the sulfur content of their diesel fuel and home heating fuels to comply with environmental regulations and comply with environmental air pollution and water pollution requirements.

Baton Rouge Refinery (the sixth-largest in the United States)[21]

United States

Main article: Petroleum refining in the United States

Refinery, Bayport Industrial Complex, Harris County, Texas

In the 19th century, refineries in the U.S. processed crude oil primarily to recover the kerosene. There was no market for the more volatile fraction, including gasoline, which was considered waste and was often dumped directly into the nearest river. The invention of the automobile shifted demand to gasoline and diesel, which remain the primary refined products today.[22]

Today, national and state legislation require refineries to meet stringent air and water cleanliness standards. In fact, oil companies in the U.S. perceive obtaining a permit to build a modern refinery to be so difficult and costly that no new refineries were built (though many have been expanded) in the U.S. from 1976 until 2014 when the small Dakota Prairie Refinery in North Dakota began operation.[23] More than half the refineries that existed in 1981 are now closed due to low utilization rates and accelerating mergers.[24] As a result of these closures total US refinery capacity fell between 1981 and 1995, though the operating capacity stayed fairly constant in that time period at around 15,000,000 barrels per day (2,400,000 m3/d).[25] Increases in facility size and improvements in efficiencies have offset much of the lost physical capacity of the industry. In 1982 (the earliest data provided), the United States operated 301 refineries with a combined capacity of 17.9 million barrels (2,850,000 m3) of crude oil each calendar day. In 2010, there were 149 operable U.S. refineries with a combined capacity of 17.6 million barrels (2,800,000 m3) per calendar day.[26] By 2014 the number of refinery had reduced to 140 but the total capacity increased to 18.02 million barrels (2,865,000 m3) per calendar day. Indeed, in order to reduce operating costs and depreciation, refining is operated in fewer sites but of bigger capacity.

In 2009 through 2010, as revenue streams in the oil business dried up and profitability of oil refineries fell due to lower demand for product and high reserves of supply preceding the economic recession, oil companies began to close or sell the less profitable refineries.[27]

Operation

Neste Oil refinery in Porvoo, Finland

Raw or unprocessed crude oil is not generally useful in industrial applications, although "light, sweet" (low viscosity, low sulfur) crude oil has been used directly as a burner fuel to produce steam for the propulsion of seagoing vessels. The lighter elements, however, form explosive vapors in the fuel tanks and are therefore hazardous, especially in warships. Instead, the hundreds of different hydrocarbon molecules in crude oil are separated in a refinery into components that can be used as fuels, lubricants, and feedstocks in petrochemical processes that manufacture such products as plastics, detergents, solvents, elastomers, and fibers such as nylon and polyesters.

Petroleum fossil fuels are burned in internal combustion engines to provide power for ships, automobiles, aircraft engines, lawn mowers, dirt bikes, and other machines. Different boiling points allow the hydrocarbons to be separated by distillation. Since the lighter liquid products are in great demand for use in internal combustion engines, a modern refinery will convert heavy hydrocarbons and lighter gaseous elements into these higher-value products.[28]

The oil refinery in Haifa, Israel, is capable of processing about 9 million tons (66 million barrels) of crude oil a year. Its two cooling towers are landmarks of the city's skyline.

Oil can be used in a variety of ways because it contains hydrocarbons of varying molecular masses, forms and lengths such as paraffins, aromatics, naphthenes (or cycloalkanes), alkenes, dienes, and alkynes.[29] While the molecules in crude oil include different atoms such as sulfur and nitrogen, the hydrocarbons are the most common form of molecules, which are molecules of varying lengths and complexity made of hydrogen and carbon atoms, and a small number of oxygen atoms. The differences in the structure of these molecules account for their varying physical and chemical properties, and it is this variety that makes crude oil useful in a broad range of several applications.

Once separated and purified of any contaminants and impurities, the fuel or lubricant can be sold without further processing. Smaller molecules such as isobutane and propylene or butylenes can be recombined to meet specific octane requirements by processes such as alkylation, or more commonly, dimerization. The octane grade of gasoline can also be improved by catalytic reforming, which involves removing hydrogen from hydrocarbons producing compounds with higher octane ratings such as aromatics. Intermediate products such as gasoils can even be reprocessed to break a heavy, long-chained oil into a lighter short-chained one, by various forms of cracking such as fluid catalytic cracking, thermal cracking, and hydrocracking. The final step in gasoline production is the blending of fuels with different octane ratings, vapor pressures, and other properties to meet product specifications. Another method for reprocessing and upgrading these intermediate products (residual oils) uses a devolatilization process to separate usable oil from the waste asphaltene material. Certain cracked streams are particularly suitable to produce petrochemicals includes polypropylene, heavier polymers, and block polymers based on the molecular weight and the characteristics of the olefin specie that is cracked from the source feedstock.[30]

Oil refineries are large-scale plants, processing about a hundred thousand to several hundred thousand barrels of crude oil a day. Because of the high capacity, many of the units operate continuously, as opposed to processing in batches, at steady state or nearly steady state for months to years. The high capacity also makes process optimization and advanced process control very desirable.

Major products

Crude oil is separated into fractions by fractional distillation. The fractions at the top of the fractionating column have lower boiling points than the fractions at the bottom. The heavy bottom fractions are often cracked into lighter, more useful products. All of the fractions are processed further in other refining units.

A breakdown of the products made from a typical barrel of US oil[31]

Petroleum products are materials derived from crude oil (petroleum) as it is processed in oil refineries. The majority of petroleum is converted to petroleum products, which includes several classes of fuels.[32]

Oil refineries also produce various intermediate products such as hydrogen, light hydrocarbons, reformate and pyrolysis gasoline. These are not usually transported but instead are blended or processed further on-site. Chemical plants are thus often adjacent to oil refineries or a number of further chemical processes are integrated into it. For example, light hydrocarbons are steam-cracked in an ethylene plant, and the produced ethylene is polymerized to produce polyethene.

To ensure both proper separation and environmental protection, a very low sulfur content is necessary in all but the heaviest products. The crude sulfur contaminant is transformed to hydrogen sulfide via catalytic hydrodesulfurization and removed from the product stream via amine gas treating. Using the Claus process, hydrogen sulfide is afterward transformed to elementary sulfur to be sold to the chemical industry. The rather large heat energy freed by this process is directly used in the other parts of the refinery. Often an electrical power plant is combined into the whole refinery process to take up the excess heat.

According to the composition of the crude oil and depending on the demands of the market, refineries can produce different shares of petroleum products. The largest share of oil products is used as "energy carriers", i.e. various grades of fuel oil and gasoline. These fuels include or can be blended to give gasoline, jet fuel, diesel fuel, heating oil, and heavier fuel oils. Heavier (less volatile) fractions can also be used to produce asphalt, tar, paraffin wax, lubricating and other heavy oils. Refineries also produce other chemicals, some of which are used in chemical processes to produce plastics and other useful materials. Since petroleum often contains a few percent sulfur-containing molecules, elemental sulfur is also often produced as a petroleum product. Carbon, in the form of petroleum coke, and hydrogen may also be produced as petroleum products. The hydrogen produced is often used as an intermediate product for other oil refinery processes such as hydrocracking and hydrodesulfurization.[33]

Petroleum products are usually grouped into four categories: light distillates (LPG, gasoline, naphtha), middle distillates (kerosene, jet fuel, diesel), heavy distillates, and residuum (heavy fuel oil, lubricating oils, wax, asphalt). These require blending various feedstocks, mixing appropriate additives, providing short-term storage, and preparation for bulk loading to trucks, barges, product ships, and railcars. This classification is based on the way crude oil is distilled and separated into fractions.[2]

Gaseous fuel such as liquified petroleum gas and propane, stored and shipped in liquid form under pressure.

Lubricants (produces light machine oils, motor oils, and greases, adding viscosity stabilizers as required), usually shipped in bulk to an offsite packaging plant.

Paraffin wax, used in the candle industry, among others. May be shipped in bulk to a site to prepare as packaged blocks. Used for wax emulsions, candles, matches, rust protection, vapor barriers, construction board, and packaging of frozen foods.

Sulfur (or sulfuric acid), byproducts of sulfur removal from petroleum which may have up to a couple of percent sulfur as organic sulfur-containing compounds. Sulfur and sulfuric acid are useful industrial materials. Sulfuric acid is usually prepared and shipped as the acid precursor oleum.

Bulk tar shipping for offsite unit packaging for use in tar-and-gravel roofing.

Asphalt used as a binder for gravel to form asphalt concrete, which is used for paving roads, lots, etc. An asphalt unit prepares bulk asphalt for shipment.

Petroleum coke, used in specialty carbon products like electrodes or as solid fuel.

Petrochemicals are organic compounds that are the ingredients for the chemical industry, ranging from polymers and pharmaceuticals, including ethylene and benzene-toluene-xylenes ("BTX") which are often sent to petrochemical plants for further processing in a variety of ways. The petrochemicals may be olefins or their precursors, or various types of aromatic petrochemicals.

Gasoline

Naphtha

Kerosene and related jet aircraft fuels

Diesel fuel and fuel oils

Heat

Electricity

Over 6,000 items are made from petroleum waste by-products, including fertilizer, floor coverings, perfume, insecticide, petroleum jelly, soap, and vitamin capsules.[34]

Sample of crude oil (petroleum)

Cylinders of liquified petroleum gas

Sample of gasoline

Sample of kerosene

Sample of diesel fuel

Motor oil

Pile of asphalt-covered aggregate for formation into asphalt concrete

Sulphur

Chemical processes

Storage tanks and towers at Shell Puget Sound Refinery (Shell Oil Company), Anacortes, Washington

Desalter unit washes out salt, and other water soluble contaminants, from the crude oil before it enters the atmospheric distillation unit.[35][36][37]

Pre-flash and/or pre-distillation which is found in most atmospheric crude oil units of more than 100,000 bpsd in capacity.[38]

Crude oil distillation unit distills the incoming crude oil into various fractions for further processing in other units. See continuous distillation.[39][40][41][42][43]

Vacuum distillation further distills the residue oil from the bottom of the crude oil distillation unit. The vacuum distillation is performed at a pressure well below atmospheric pressure.[39][40][41][42][43]

Naphtha hydrotreater unit uses hydrogen to desulfurize naphtha from atmospheric distillation. Naphtha must be desulfurized before sending it to a catalytic reformer unit.[1][44]

Catalytic reformer converts the desulfurized naphtha molecules into higher-octane molecules to produce reformate (reformer product). The reformate has higher content of aromatics and cyclic hydrocarbons which is a component of the end-product gasoline or petrol. An important byproduct of a reformer is hydrogen released during the catalyst reaction. The hydrogen is used either in the hydrotreaters or the hydrocracker.[45][46]

Distillate hydrotreater desulfurizes distillates (such as diesel) after atmospheric distillation. Uses hydrogen to desulfurize the naphtha fraction from the crude oil distillation or other units within the refinery.[1][44] Distillate hydrotreaters that operate above 700 psi are also capable of removing nitrogen contaminants from feedstocks if given adequate liquid hourly space velocity.[47]

Fluid catalytic cracker (FCC) upgrades the heavier, higher-boiling fractions from the crude oil distillation by converting them into lighter and lower boiling, more valuable products.[48][3][49]

Hydrocracker uses hydrogen to upgrade heavy residual oils from the vacuum distillation unit by thermally cracking them into lighter, more valuable reduced viscosity products.[50][51]

Merox desulfurize LPG, kerosene or jet fuel by oxidizing mercaptans to organic disulfides.

Alternative processes for removing mercaptans are known, e.g. doctor sweetening process and caustic washing.

Coking units (delayed coker, fluid coker, and flexicoker) process very heavy residual oils into gasoline and diesel fuel, leaving petroleum coke as a residual product.

Alkylation unit uses sulfuric acid or hydrofluoric acid to produce high-octane components for gasoline blending. The "alky" unit converts light end isobutane and butylenes from the FCC process into alkylate, a very high-octane component of the end-product gasoline or petrol.[52]

Dimerization unit converts olefins into higher-octane gasoline blending components. For example, butenes can be dimerized into isooctene which may subsequently be hydrogenated to form isooctane. There are also other uses for dimerization. Gasoline produced through dimerization is highly unsaturated and very reactive. It tends spontaneously to form gums. For this reason, the effluent from the dimerization needs to be blended into the finished gasoline pool immediately or hydrogenated.

Isomerization converts linear molecules such as normal pentane to higher-octane branched molecules for blending into gasoline or feed to alkylation units. Also used to convert linear normal butane into isobutane for use in the alkylation unit.

Steam reforming converts natural gas into hydrogen for the hydrotreaters and/or the hydrocracker.

Liquified gas storage vessels store propane and similar gaseous fuels at pressure sufficient to maintain them in liquid form. These are usually spherical vessels or "bullets" (i.e., horizontal vessels with rounded ends).

Amine gas treater, Claus unit, and tail gas treatment convert hydrogen sulfide from hydrodesulfurization into elemental sulfur. The large majority of the 64,000,000 metric tons of sulfur produced worldwide in 2005 was byproduct sulfur from petroleum refining and natural gas processing plants.[53][54]

Sour water stripper uses steam to remove hydrogen sulfide gas from various wastewater streams for subsequent conversion into end-product sulfur in the Claus unit.[37]

Cooling towers circulate cooling water, boiler plants generates steam for steam generators, and instrument air systems include pneumatically operated control valves and an electrical substation.

Wastewater collection and treating systems consist of API separators, dissolved air flotation (DAF) units and further treatment units such as an activated sludge biotreater to make water suitable for reuse or for disposal.[55]

Solvent refining uses solvent such as cresol or furfural to remove unwanted, mainly aromatics from lubricating oil stock or diesel stock.

Solvent dewaxing removes the heavy waxy constituents petrolatum from vacuum distillation products.

Storage tanks for storing crude oil and finished products, usually vertical, cylindrical vessels with some sort of vapor emission control and surrounded by an earthen berm to contain spills.

Flow diagram of typical refinery

The image below is a schematic flow diagram of a typical oil refinery that depicts the various unit processes and the flow of intermediate product streams that occurs between the inlet crude oil feedstock and the final end products. The diagram depicts only one of the literally hundreds of different oil refinery configurations. The diagram also does not include any of the usual refinery facilities providing utilities such as steam, cooling water, and electric power as well as storage tanks for crude oil feedstock and for intermediate products and end products.[1][56][57][58]

Schematic flow diagram of a typical oil refinery

There are many process configurations other than that depicted above. For example, the vacuum distillation unit may also produce fractions that can be refined into end products such as spindle oil used in the textile industry, light machine oil, motor oil, and various waxes.

Crude oil distillation unit

The crude oil distillation unit (CDU) is the first processing unit in virtually all petroleum refineries. The CDU distills the incoming crude oil into various fractions of different boiling ranges, each of which is then processed further in the other refinery processing units. The CDU is often referred to as the atmospheric distillation unit because it operates at slightly above atmospheric pressure.[1][2][41] Below is a schematic flow diagram of a typical crude oil distillation unit. The incoming crude oil is preheated by exchanging heat with some of the hot, distilled fractions and other streams. It is then desalted to remove inorganic salts (primarily sodium chloride).

Following the desalter, the crude oil is further heated by exchanging heat with some of the hot, distilled fractions and other streams. It is then heated in a fuel-fired furnace (fired heater) to a temperature of about 398 °C and routed into the bottom of the distillation unit.

The cooling and condensing of the distillation tower overhead is provided partially by exchanging heat with the incoming crude oil and partially by either an air-cooled or water-cooled condenser. Additional heat is removed from the distillation column by a pumparound system as shown in the diagram below.

As shown in the flow diagram, the overhead distillate fraction from the distillation column is naphtha. The fractions removed from the side of the distillation column at various points between the column top and bottom are called sidecuts. Each of the sidecuts (i.e., the kerosene, light gas oil, and heavy gas oil) is cooled by exchanging heat with the incoming crude oil. All of the fractions (i.e., the overhead naphtha, the sidecuts, and the bottom residue) are sent to intermediate storage tanks before being processed further.

Schematic flow diagram of a typical crude oil distillation unit as used in petroleum crude oil refineries

Location of refineries

A party searching for a site to construct a refinery or a chemical plant needs to consider the following issues:

The site has to be reasonably far from residential areas.

Infrastructure should be available for the supply of raw materials and shipment of products to markets.

Energy to operate the plant should be available.

Facilities should be available for waste disposal.

Factors affecting site selection for oil refinery:

Availability of land

Conditions of traffic and transportation

Conditions of utilities – power supply, water supply

Availability of labours and resources

Refineries that use a large amount of steam and cooling water need to have an abundant source of water. Oil refineries, therefore, are often located nearby navigable rivers or on a seashore, nearby a port. Such location also gives access to transportation by river or by sea. The advantages of transporting crude oil by pipeline are evident, and oil companies often transport a large volume of fuel to distribution terminals by pipeline. A pipeline may not be practical for products with small output, and railcars, road tankers, and barges are used.

Petrochemical plants and solvent manufacturing (fine fractionating) plants need spaces for further processing of a large volume of refinery products, or to mix chemical additives with a product at source rather than at blending terminals.

Safety and environment

Fire-extinguishing operations after the Texas City refinery explosion

The refining process releases a number of different chemicals into the atmosphere (see AP 42 Compilation of Air Pollutant Emission Factors) and a notable odor normally accompanies the presence of a refinery. Aside from air pollution impacts there are also wastewater concerns,[55] risks of industrial accidents such as fire and explosion, and noise health effects due to industrial noise.[59]

Many governments worldwide have mandated restrictions on contaminants that refineries release, and most refineries have installed the equipment needed to comply with the requirements of the pertinent environmental protection regulatory agencies. In the United States, there is strong pressure to prevent the development of new refineries, and no major refinery has been built in the country since Marathon's Garyville, Louisiana facility in 1976. However, many existing refineries have been expanded during that time. Environmental restrictions and pressure to prevent the construction of new refineries may have also contributed to rising fuel prices in the United States.[60] Additionally, many refineries (more than 100 since the 1980s) have closed due to obsolescence and/or merger activity within the industry itself.[61]

Environmental and safety concerns mean that oil refineries are sometimes located some distance away from major urban areas. Nevertheless, there are many instances where refinery operations are close to populated areas and pose health risks.[62][63] In California's Contra Costa County and Solano County, a shoreline necklace of refineries, built in the early 20th century before this area was populated, and associated chemical plants are adjacent to urban areas in Richmond, Martinez, Pacheco, Concord, Pittsburg, Vallejo and Benicia, with occasional accidental events that require "shelter in place" orders to the adjacent populations. A number of refineries are located in Sherwood Park, Alberta, directly adjacent to the City of Edmonton, which has a population of over 1,000,000 residents.[64]

NIOSH criteria for occupational exposure to refined petroleum solvents have been available since 1977.[65]

Worker health

Background

Modern petroleum refining involves a complicated system of interrelated chemical reactions that produce a wide variety of petroleum-based products.[66][67] Many of these reactions require precise temperature and pressure parameters.[68] The equipment and monitoring required to ensure the proper progression of these processes is complex, and has evolved through the advancement of the scientific field of petroleum engineering.[69][70]

The wide array of high pressure and/or high temperature reactions, along with the necessary chemical additives or extracted contaminants, produces an astonishing number of potential health hazards to the oil refinery worker.[71][72] Through the advancement of technical chemical and petroleum engineering, the vast majority of these processes are automated and enclosed, thus greatly reducing the potential health impact to workers.[73] However, depending on the specific process in which a worker is engaged, as well as the particular method employed by the refinery in which he/she works, significant health hazards remain.[74]

Although occupational injuries in the United States were not routinely tracked and reported at the time, reports of the health impacts of working in an oil refinery can be found as early as the 1800s. For instance, an explosion in a Chicago refinery killed 20 workers in 1890.[75] Since then, numerous fires, explosions, and other significant events have from time to time drawn the public's attention to the health of oil refinery workers.[76] Such events continue in the 21st century, with explosions reported in refineries in Wisconsin and Germany in 2018.[77]

However, there are many less visible hazards that endanger oil refinery workers.

Chemical exposures

Given the highly automated and technically advanced nature of modern petroleum refineries, nearly all processes are contained within engineering controls and represent a substantially decreased risk of exposure to workers compared to earlier times.[73] However, certain situations or work tasks may subvert these safety mechanisms, and expose workers to a number of chemical (see table above) or physical (described below) hazards.[78][79] Examples of these scenarios include:

System failures (leaks, explosions, etc.).[80][81]

Standard inspection, product sampling, process turnaround, or equipment maintenance/cleaning activities.[78][79]

A 2021 systematic review associated working in the petrochemical industry with increased risk of various cancers, such as mesothelioma. It also found reduced risks of other cancers, such as stomach and rectal. The systematic review did mention that several of the associations were not due to factors directly related to the petroleum industry, rather were related to lifestyle factors such as smoking. Evidence for adverse health effects for nearby residents was also weak, with the evidence primarily centering around neighborhoods in developed countries.[82]

BTX stands for benzene, toluene, xylene. This is a group of common volatile organic compounds (VOCs) that are found in the oil refinery environment, and serve as a paradigm for more in depth discussion of occupational exposure limits, chemical exposure and surveillance among refinery workers.[83][84]

The most important route of exposure for BTX chemicals is inhalation due to the low boiling point of these chemicals. The majority of the gaseous production of BTX occurs during tank cleaning and fuel transfer, which causes offgassing of these chemicals into the air.[85] Exposure can also occur through ingestion via contaminated water, but this is unlikely in an occupational setting.[86] Dermal exposure and absorption is also possible, but is again less likely in an occupational setting where appropriate personal protective equipment is in place.[86]

In the United States, the Occupational Safety and Health Administration (OSHA), National Institute for Occupational Safety and Health (NIOSH), and American Conference of Governmental Industrial Hygienists (ACGIH) have all established occupational exposure limits (OELs) for many of the chemicals above that workers may be exposed to in petroleum refineries.[87][88][89]

Occupational exposure limits for BTX chemicals

OSHA PEL (8-hour TWA) CalOSHA PEL (8-hour TWA) NIOSH REL (10-hour TWA) ACGIH TLV (8-hour TWA)

Benzene 10 ppm 1 ppm 0.1 ppm 0.5 ppm

Toluene 200 ppm 10 ppm 100 ppm 20 ppm

Xylene 100 ppmx 100 ppm 100 ppm 100 ppm

Sources:[90][91][92][87][93]

Benzene, in particular, has multiple biomarkers that can be measured to determine exposure. Benzene itself can be measured in the breath, blood, and urine, and metabolites such as phenol, t,t-muconic acid (t,tMA) and S-phenylmercapturic acid (sPMA) can be measured in urine.[94] In addition to monitoring the exposure levels via these biomarkers, employers are required by OSHA to perform regular blood tests on workers to test for early signs of some of the feared hematologic outcomes, of which the most widely recognized is leukemia. Required testing includes complete blood count with cell differentials and peripheral blood smear "on a regular basis".[95] The utility of these tests is supported by formal scientific studies.[96]

Potential chemical exposure by process

Process Potential chemical exposure[97] Common health concerns[98]

Solvent extraction and dewaxing Phenol[99] Neurologic symptoms, muscle weakness, skin irritation.

Furfural[100] Skin irritation

Glycols Central nervous system depression, weakness, irritation of the eyes, skin, nose, throat.

Methyl ethyl ketone[101] Airway irritation, cough, dyspnea, pulmonary edema.

Thermal cracking Hydrogen sulfide[102] Irritation of the respiratory tract, headache, visual disturbances, eye pain.

Carbon monoxide[103] Electrocardiogram changes, cyanosis, headache, weakness.

Ammonia[104] Respiratory tract irritation, dyspnea, pulmonary edema, skin burns.

Catalytic cracking Hydrogen sulfide[102] Irritation of the respiratory tract, headache, visual disturbances, eye pain.

Carbon monoxide[103] Electrocardiogram changes, cyanosis, headache, weakness.

Phenol[99] Neurologic symptoms, muscle weakness, skin irritation.

Ammonia[104] Respiratory tract irritation, dyspnea, pulmonary edema, skin burns.

Mercaptan[105][106] Cyanosis and narcosis, irritation of the respiratory tract, skin, and eyes.

Nickel carbonyl[107] Headache, teratogen, weakness, chest/abdominal pain, lung and nasal cancer.

Catalytic reforming Hydrogen sulfide[102] Irritation of the respiratory tract, headache, visual disturbances, eye pain.

Benzene[108] Leukemia, nervous system effects, respiratory symptoms.

Isomerization Hydrochloric acid Skin damage, respiratory tract irritation, eye burns.

Hydrogen chloride Respiratory tract irritation, skin irritation, eye burns.

Polymerization Sodium hydroxide[109] Irritation of the mucous membranes, skin, pneumonitis.

Phosphoric acid Skin, eye, respiratory irritation.

Alkylation Sulfuric acid Eye and skin burns, pulmonary edema.

Hydrofluoric acid Bone changes, skin burns, respiratory tract damage.

Sweetening and treating Hydrogen sulfide[102] Irritation of the respiratory tract, headache, visual disturbances, eye pain.

Sodium hydroxide[109] Irritation of the mucous membranes, skin, pneumonitis.

Unsaturated gas recovery Monoethanolamine (MEA) Drowsiness, irritation of the eyes, skin, and respiratory tract.

Diethanolamine (DEA) Corneal necrosis, skin burns, irritation of the eyes, nose, throat.

Amine treatment Monoethanolamine (MEA) Drowsiness, irritation of the eyes, skin, and respiratory tract.

Diethanolamine (DEA) Corneal necrosis, skin burns, irritation of the eyes, nose, throat.

Hydrogen sulfide[102] Irritation of the respiratory tract, headache, visual disturbances, eye pain.

Carbon dioxide Headache, dizziness, paresthesia, malaise, tachycardia.

Saturated gas extraction Hydrogen sulfide[102] Irritation of the respiratory tract, headache, visual disturbances, eye pain.

Carbon dioxide[110] Headache, dizziness, paresthesia, malaise, tachycardia.

Diethanolamine Corneal necrosis, skin burns, irritation of the eyes, nose, throat.

Sodium hydroxide[109] Irritation of the mucous membranes, skin, pneumonitis.

Hydrogen production Carbon monoxide[103] Electrocardiogram changes, cyanosis, headache, weakness.

Carbon dioxide[110] Headache, dizziness, paresthesia, malaise, tachycardia.

Physical hazards

Workers are at risk of physical injuries due to a large number of high-powered machines in the relatively close proximity of the oil refinery. The high pressure required for many of the chemical reactions also presents the possibility of localized system failures resulting in blunt or penetrating trauma from exploding system components.[111]

Heat is also a hazard. The temperature required for the proper progression of certain reactions in the refining process can reach 1,600 °F (870 °C).[73] As with chemicals, the operating system is designed to safely contain this hazard without injury to the worker. However, in system failures, this is a potent threat to workers' health. Concerns include both direct injury through a heat illness or injury, as well as the potential for devastating burns should the worker come in contact with super-heated reagents/equipment.[73]

Noise is another hazard. Refineries can be very loud environments, and have previously been shown to be associated with hearing loss among workers.[112] The interior environment of an oil refinery can reach levels in excess of 90 dB.[113][59] In the United States, an average of 90 dB is the permissible exposure limit (PEL) for an 8-hour work-day.[114] Noise exposures that average greater than 85 dB over an 8-hour require a hearing conservation program to regularly evaluate workers' hearing and to promote its protection.[115] Regular evaluation of workers' auditory capacity and faithful use of properly vetted hearing protection are essential parts of such programs.[116]

While not specific to the industry, oil refinery workers may also be at risk for hazards such as vehicle-related accidents, machinery-associated injuries, work in a confined space, explosions/fires, ergonomic hazards, shift-work related sleep disorders, and falls.[117]

Hazard controls

The theory of hierarchy of controls can be applied to petroleum refineries and their efforts to ensure worker safety.

Elimination and substitution are unlikely in petroleum refineries, as many of the raw materials, waste products, and finished products are hazardous in one form or another (e.g. flammable, carcinogenic).[97][118]

Examples of engineering controls include a fire detection/extinguishing system, pressure/chemical sensors to detect/predict loss of structural integrity,[119] and adequate maintenance of piping to prevent hydrocarbon-induced corrosion (leading to structural failure).[80][81][120][121] Other examples employed in petroleum refineries include the post-construction protection of steel components with vermiculite to improve heat/fire resistance.[122] Compartmentalization can help to prevent a fire or other systems failure from spreading to affect other areas of the structure, and may help prevent dangerous reactions by keeping different chemicals separate from one another until they can be safely combined in the proper environment.[119]

Administrative controls include careful planning and oversight of the refinery cleaning, maintenance, and turnaround processes. These occur when many of the engineering controls are shut down or suppressed and may be especially dangerous to workers. Detailed coordination is necessary to ensure that maintenance of one part of the facility will not cause dangerous exposures to those performing the maintenance, or to workers in other areas of the plant. Due to the highly flammable nature of many of the involved chemicals, smoking areas are tightly controlled and carefully placed.[78]

Personal protective equipment (PPE) may be necessary depending on the specific chemical being processed or produced. Particular care is needed during sampling of the partially-completed product, tank cleaning, and other high-risk tasks as mentioned above. Such activities may require the use of impervious outerwear, acid hood, disposable coveralls, etc.[78] More generally, all personnel in operating areas should use appropriate hearing and vision protection, avoid clothes made of flammable material (nylon, Dacron, acrylic, or blends), and full-length pants and sleeves.[78]

Regulations

United States

Worker health and safety in oil refineries is closely monitored at a national level by both the Occupational Safety and Health Administration (OSHA) and National Institute for Occupational Safety and Health (NIOSH).[123][124] In addition to federal monitoring, California's CalOSHA has been particularly active in protecting worker health in the industry, and adopted a policy in 2017 that requires petroleum refineries to perform a "Hierarchy of Hazard Controls Analysis" (see above "Hazard controls" section) for each process safety hazard.[125] Safety regulations have resulted in a below-average injury rate for refining industry workers. In a 2018 report by the US Bureau of Labor Statistics, they indicate that petroleum refinery workers have a significantly lower rate of occupational injury (0.4 OSHA-recordable cases per 100 full-time workers) than all industries (3.1 cases), oil and gas extraction (0.8 cases), and petroleum manufacturing in general (1.3 cases).[126]

Below is a list of the most common regulations referenced in petroleum refinery safety citations issued by OSHA:[127]

Flammable and Combustible Liquids (29 CFR 1910.106)

The Hazard Communication (HazCom) standard (29 CFR 1910.1200)

Permit-Required Confined Spaces (29 CFR 1910.146)

Hazardous (Classified) Locations (29 CFR 1910.307)

The Personal Protective Equipment (PPE) standard (29 CFR 1910.132)

The Control of Hazardous Energy (Lockout/Tagout) standard (29 CFR 1910.147)

Corrosion

Refinery of Slovnaft in Bratislava

Oil refinery in Iran

Corrosion of metallic components is a major factor of inefficiency in the refining process. Because it leads to equipment failure, it is a primary driver for the refinery maintenance schedule. Corrosion-related direct costs in the U.S. petroleum industry as of 1996 were estimated at US$3.7 billion.[121][128]

Corrosion occurs in various forms in the refining process, such as pitting corrosion from water droplets, embrittlement from hydrogen, and stress corrosion cracking from sulfide attack.[129] From a materials standpoint, carbon steel is used for upwards of 80 percent of refinery components, which is beneficial due to its low cost. Carbon steel is resistant to the most common forms of corrosion, particularly from hydrocarbon impurities at temperatures below 205 °C, but other corrosive chemicals and environments prevent its use everywhere. Common replacement materials are low alloy steels containing chromium and molybdenum, with stainless steels containing more chromium dealing with more corrosive environments. More expensive materials commonly used are nickel, titanium, and copper alloys. These are primarily saved for the most problematic areas where extremely high temperatures and/or very corrosive chemicals are present.[130]

Corrosion is fought by a complex system of monitoring, preventative repairs, and careful use of materials. Monitoring methods include both offline checks taken during maintenance and online monitoring. Offline checks measure corrosion after it has occurred, telling the engineer when equipment must be replaced based on the historical information they have collected. This is referred to as preventative management.

Online systems are a more modern development and are revolutionizing the way corrosion is approached. There are several types of online corrosion monitoring technologies such as linear polarization resistance, electrochemical noise and electrical resistance. Online monitoring has generally had slow reporting rates in the past (minutes or hours) and been limited by process conditions and sources of error but newer technologies can report rates up to twice per minute with much higher accuracy (referred to as real-time monitoring). This allows process engineers to treat corrosion as another process variable that can be optimized in the system. Immediate responses to process changes allow the control of corrosion mechanisms, so they can be minimized while also maximizing production output.[120] In an ideal situation having on-line corrosion information that is accurate and real-time will allow conditions that cause high corrosion rates to be identified and reduced. This is known as predictive management.

Materials methods include selecting the proper material for the application. In areas of minimal corrosion, cheap materials are preferable, but when bad corrosion can occur, more expensive but longer-lasting materials should be used. Other materials methods come in the form of protective barriers between corrosive substances and the equipment metals. These can be either a lining of refractory material such as standard Portland cement or other special acid-resistant cement that is shot onto the inner surface of the vessel. Also available are thin overlays of more expensive metals that protect cheaper metal against corrosion without requiring much material.[131]