ME 463 Petroleum Engineering Petroleum Petroleum Formation Petroleum Migration Petroleum Accumulation What is petroleum Petroleum is a mineral substance composed of hydrocarbons and produced from the natural accumulations of organic matter of a faunal and/or floral provenance. Petroleum is a gaseous, liquid or semisolid substance, present in the pore space of porous rocks, referred to as reservoir rocks. Gases: Liquids: Solids: Visco-plastic solids: Methane, ethane, propane, butane + others Oil, Crude oil Refined to derive petroleum products such as gasoline, diesel fuel. Coal, Kerogen, Gas hydrates (ices of gas) Tar The Conversion of Organic Matter to Petroleum ▪ ▪ ▪ ▪ ▪ ▪ When an organism (plant or animal) dies, organic matter is buried and remains buried under anoxic conditions for 100-400 millions years. Over the years, layers of silt, sand and other sediments settled over the buried organic matter resulting increase of pressure and temperature. The organic matter in sediments, subjected to increased temperature and pressure is converted into petroleum hydrocarbons. Not all of the organic carbon (OC) in sedimentary rocks converted into petroleum HC. A portion of the Total Organic Carbon (TOC) consists of Kerogen. The composition of the organic matter strongly influences whether the organic matter can produce coal, oil or gas. Basic components of organic matter in sediments • PROTEINS • CARBOHYDRATES • LIPIDS (Fats) • LIGNIN All of these + Time + Temperature + Pressure = KEROGEN The Conversion of Organic Matter to Petroleum ▪ Organic matter was buried before decomposition takes place. The lack of oxygen (anoxic conditions) is an essential factor since it prevents the decomposition of the organic matter which is then transformed to oil. ▪ The only elements essential to the transformation of organic matter (OM) into petroleum are hydrogen and carbon. Thus the nitrogen and oxygen contained in the OM must somehow be removed while at the same time preserving the hydrogen-rich organic residue. The amount of organic matter in the source rock is important as 75% of organic matter is converted in to petroleum. ▪ Once the organic material is buried within the sea floor, transformation begins. Tissot (1977) defined three major consecutive phases in the evolution of organic matter in response to burial: ▪ Diagenesis ▪ Catagenesis ▪ Metagenesis Diagenesis o This phase occurs in the shallow subsurface at near normal temperatures and pressures. This is a process of compaction under mild conditions of temperature and pressure. It takes place at depths from shallow to perhaps as deep as 1,000 meters and at temperatures ranging from near normal to less than 60oC. o It includes both biogenic decay, aided by bacteria, and abiogenic reactions. When organic aquatic sediments (proteins, lipids, carbohydrates) are deposited, they are very saturated with water and rich in minerals. o Through chemical reaction, compaction, and microbial action during burial, water is forced out and proteins and carbohydrates break down to form new structures that comprise a waxy material known as “kerogen” and a black tar like substance called “bitumen”. o The net result of the diagenesis of organic matter is the reduction of its oxygen content, leaving the hydrogen : carbon ratio largely unaltered. o All of this occurs within the first several hundred meters of burial. Catagenesis o This phase occurs in the deeper subsurface as burial continues and temperature and pressure increase. As temperatures and pressures increase (deeper burial) the process of catagenesis begins, which is the thermal degradation of kerogen to form hydrocarbon chains. o Importantly, the process of catagenesis is catalyzed by the minerals that are deposited and persist through marine diagenesis. o The conditions of catagenesis determine the product, such that higher temperature and pressure lead to more complete “cracking” of the kerogen and progressively lighter and smaller hydrocarbons. The Catagenesis phase becomes dominant in the deeper subsurface as burial (1,000 - 6,000 m), heating (60 - 175oC), and deposition continues. o Petroleum formation, then, requires a specific window of conditions; too hot and the product will favor natural gas (small hydrocarbons), but too cold and the plankton will remain trapped as kerogen. o Petroleum is released from kerogen during catagenesis—first oil and later gas. The hydrogen: carbon ratio declines, with no significant change in the oxygen:carbon ratio. Metagenesis o This third phase occurs at even higher temperatures and pressures verging on metamorphism. o The last hydrocarbons, generally only methane, are expelled. o The hydrogen : carbon ratio declines until only carbon is left in the form of graphite. o Porosity and permeability are now negligible. Petroleum Formation Process Flow Maturation of Kerogen ▪ On average, the composition of organic matter in sediment is as follows: ▪ 40% Proteins ▪ 40% Carbohydrates ▪ 10% Lipids ▪ 10% Lignin ▪ These materials are supplied by: Trees, Herbaceous plants, Fungi, Algae, Protozoa, Bacteria, and Faeces ▪ All of these + Time + Temperature + Pressure = KEROGEN Kerogen Classification • The extreme types of disseminated organic matter correspond to the class of Kerogen formed. It can be classified based on the ratios of H/C and O/C as follows:. • Type I kerogen • Type II kerogen • Type III kerogen • Type IV kerogen Maturation of Kerogen Type I Kerogen ▪ Rich in lipids particularly aliphatic chains with derivates of oils, fats, & Waxes ▪ Derived from algae present in fresh water lakes & lagoons. ▪ High proportion of H:C ratio (1.6- 1.8) and low O:C ratio (0.06) ▪ Oil prone; yields high (up to 80%). Type II Kerogen ▪ Most prolific global source rocks ▪ Rich in lipid ▪ It is an admixture of ▪ Marine material - phytoplanktons , zooplanktons, algae ▪ Terrestrial (plant) material- spores, pollen, and cuticle ▪ Intermediate H:C (about 1.3) & intermediate O:C (0.1) ▪ Oil & gas prone; yields 40—60% Maturation of Kerogen Type III Kerogen ▪ Rich in lignin derived from woody land plant debris ▪ The debris occurs abundantly in coals ▪ Low H:C ratio (< 1.0) & high O:C ratio (0.15) ▪ Low yield for oil but gas prone ▪ Low in aliphatic compounds but rich in aromatic compounds Type IV Kerogen ▪ High in carbon and very low in hydrogen ▪ Often termed “dead-carbon” ▪ No effective potential to generate petroleum Hydrogen Index: mg of HC/g TOC Oxygen Index: mg of CO2/g TOC Maturity Parameter of Kerogen ▪ Temperature, is the first most important factor for thermal maturation and determines the resultant hydrocarbon type. ▪ Time is the second most important factor for thermal maturation. ▪ Maturation Indicators are important: • To recognize and evaluate potential source rocks for oil and gas by measuring their contents in organic carbon and their thermal maturities • To correlate oil types with probable source beds through their geochemical characteristics and the optical properties of kerogen in the source beds • To determine the time of hydrocarbon generation, migration and accumulation • To estimate the volumes of hydrocarbons generated and thus to assess possible reserves and losses of hydrocarbons in the system. Maturity Parameter of Kerogen ▪ Petroleum geologist use several maturation indicators to evaluate potential hydrocarbon accumulations. ▪ SCI (Spore Coloration Index) and TAI (Thermal Alteration Index) are maturation indicators that measure the color of palynomorphs. Color changes as a function of maturity. ▪ Vitrinite Reflectance (Ro) is a measure of the percentage of incident light reflected from the surface of vitrinite particles in a sedimentary rock as referred %Ro. Formation of Petroleum from Organic Matter Migration of Petroleum Hydrocarbons Preconditions for Petroleum Accumulation As a general rule, the origin of petroleum is never in the reservoir accumulation from which it is produced. Instead, petroleums have experienced a long series of processes prior to accumulation in the reservoir. Petroleum accumulation forms in sedimentary basins and can be discovered by exploration, if the following geological conditions are met: ▪ Occurrence of Source Rocks which generate petroleum's under proper subsurface temperature conditions. ▪ Sediment Compaction leading to expulsion of petroleum from the source and into the reservoir rocks (primary migration). ▪ Occurrence of Reservoir rocks of sufficient porosity and permeability allowing flow of petroleum through the pore system (secondary migration). Preconditions for Petroleum Accumulation ▪ Structural configurations of sedimentary strata whereby the reservoir rocks form traps, i.e. closed containers in the subsurface for the accumulation of petroleum. ▪ Traps are sealed above by impermeable sediment layers (cap rocks) in order to keep petroleum accumulations in place. ▪ Correct timing with respect to the sequence by which the processes of petroleum generation/migration and trap formation have occurred during the history of a sedimentary basin. ▪ Favorable conditions for the preservation of petroleum accumulation during extended periods of geologic time, i.e. absence of destructive, such as the fracturing of cap rocks leading to dissipation of petroleum accumulations, or severe heating resulting in the cracking of oil into gas. Fig. 1. Main geological conditions and geochemical processes required for the formation of petroleum accumulations in sedimentary basins: 1) petroleum generation in source rocks; 2) primary migration of petroleum; 3) secondary migration of petroleum; 4) accumulation of petroleum in a reservoir trap; 5) seepage of petroleum at the Earth’s surface as a consequence of a fractured cap rock. Petroleum Migration Evidence ▪ Oil and gas do not generally originate in the rocks in which they are found. Oil and gas migrate into reservoir rocks at depth some time after burial and HC generation: ▪ Oil and gas is often found in solution pores and fractures that must have formed after the burial and lithification of the host rock (i.e., during Diagenesis). ▪ Oil and gas are trapped in the highest structural culmination, or stratigraphic pinch out of a permeable rock unit, which implies upward and lateral migration. ▪ Oil, gas and water occur as stratified bodies according to their densities in porous and permeable reservoir rock. This implies they were free to migrate laterally and vertically. Petroleum Source Rocks Petroleum source rocks/beds are fine grained, clay-rich siliclastic rocks (mudstones, shales) or dark coloured carbonate rocks (limestones, marlstones), which have generated and effectively expelled hydrocarbons. A petroleum source rock is characterized by three essential conditions: ▪ It must have a sufficient content of finely dispersed organic matter of biological origin; ▪ This organic matter must be of a specific composition, i.e. hydrogen-rich; and ▪ The source rock must be buried at certain depths and subjected to proper subsurface temperatures in order to initiate the process of petroleum generation by the thermal degradation of kerogen. • Based on empirical evidence, minimum concentration levels of 1.5% and 0.5% total organic carbon (TOC) in source rocks of siliclastic and carbonate lithologies respectively. • This minimum concentration of organic carbon in source rocks is controlled by the relationship between the quantity of petroleum generated and the internal storage capacity of the rocks in terms of their porosity. If too little organic matter is present, the small quantities of petroleum generated will not exceed the storage capacity of the rock, i.e. no petroleum expulsion will take place. • Most source rocks which have effectively generated and expelled commercial quantities of petroleum have TOC concentrations in the order of 2-10%. Table: Organic Richness of Source Rock Fig. 2. Petroleum source rocks of siliclastic lithologies often display a well expressed fine stratification and lamination: A, seen in an outcrop view B, seen in a thin section under a microscope Petroleum Migration Classification Primary Migration: ▪ Mature hydrocarbons first have to migrate out of the source rock which is in general a fine-grained rock having low permeability. ▪ During burial, this rock gets compacted and its interstitial fluid become overpressured with respect to surrounding rocks that have higher permeabilities and from which fluids can migrate with greater ease upwards. ▪ Therefore, a fluid pressure gradient develops between the source rock and the surrounding, more permeable rocks called reservoir rocks. ▪ This causes the fluids - the water and the hydrocarbons - to migrate along the pressure gradient, usually upwards, although a downward migration is possible. This process is called primary migration, and it generally takes place across the stratification. Primary Migration Mechanisms 1. Migration by Diffusion. Because of differing concentrations of the fluids in the source rock and the surrounding rock there is a tendency to diffuse. 2. Migration by molecular Saturation: Saturated hydrocarbons are preferentially expelled, while NSO compounds that is unsaturated remain preferentially within the pore space of the source rock. 3. Migration along microfractures in the source rock. During compaction the fluid pressures in the source rock may become so large that spontaneous “hydrofracing” occurs. 4. Oil-phase migration. OM in the source rock provides a continuous oil-wet migration path along which the hydrocarbons diffuse along pressure and concentration gradient. 5. An additional mechanism to provide pressure for the expulsion of petroleum is due to some volume expansion with conversion of solid labile kerogen into liquid and gaseous hydrocarbons plus residual inert kerogen. Secondary Migration Primary Mechanism ▪ As soon as the petroleum has crossed the source/reservoir bed contact and entered the reservoir rock, quite different physical conditions prevail. ▪ Significantly higher porosities, permeabilities and pore sizes allow for the formation of oil droplets and small continuous oil stringers, i.e. a network of interconnected oil-filled pores. ▪ Their movement occurs as a discrete oil phase controlled by the interplay of driving and counteracting resisting forces (England et al., 1987). The main driving force is buoyancy which is due to the density contrast between petroleum hydrocarbons and water. Oil densities can vary between 0.5 and 1.0 g/cm3) natural gas densities are much less than 0.5 g/cm3 while pore waters have densities varying between 1.00 and 1.20 g/cm3 depending on their salinity. Secondary Migration ▪ A second driving mechanism can be hydrodynamic forces. If pore waters are flowing actively, the passage of oil droplets through bottle necks in the pores is facilitated. The resisting force of capillary pressures counteracts these driving forces. If a rock has very narrow pore throats, capillary displacement pressures get so high that they cannot be exceeded by the buoyancy of the oil stringer or gas bubble, and entrapment occurs. ▪ Distances and directions of secondary petroleum migration vary depending on the type and configuration of the sedimentary basin and the spatial relationships between interbedded sandstones and shales, as well as the abundance of fractures and faults. ▪ Short migration distances occur in sedimentary sequences with intensive interbedding of source rock-type shales and reservoir sandstones. Lateral migration distances of kilometres or tens of kilometres are common (the Eastern Venezuela Basin), where longest migration distance known worldwide is the Western Canada Basin (1000 km). ▪ A statistical study of hundreds of oil fields from locations worldwide has shown that about 60% of them migrated vertically from source to reservoir, while about 40% involved considerable lateral movement Direction of fluid migration on the flank of an anticline into the highest possible place of the reservoir layer Direction of fluid migration into stratigraphic - or better: combined - traps Fluid migration in an interbedded sand/shale sequence Petroleum Hydrocarbon Accumulation ▪ The updip migration of petroleum along inclined carrier beds continues as long as it does not encounter structural configurations where the reservoir strata form traps. ▪ Traps are containers in the subsurface where petroleum accumulates. ▪ The most common traps are culminations of folds called anticlines. ▪ As petroleum is lighter than water due to buoyancy within its environment of water-filled pore spaces the subsurface container is filled with petroleum from the top downwards. ▪ Petroleum displaces the pore water there, starting from the top of the culmination and expanding into the flanks of the anticline. ▪ The contact between the oil-saturated and the watersaturated pore spaces is always sharp and, in most cases, horizontal. ▪ Provided that the incoming petroleum has an adequate gas/oil ratio and favorable pressure conditions, gas desorption will occur and a free gas phase will separate from the oil which accumulates in the apex of the structure due to the highest buoyancy forming a so-called gas cap. ▪ The gas-oil contact is equally sharp and horizontal as oilwater contact ▪ Most petroleum fields consist of an oil zone, the thickness of which is referred to as the oil leg or oil column, overlain by a gas cap. In these cases, the gas is called associated gas. ▪ Non-associated gas denotes an accumulation of gas without an oil leg, i.e. a natural gas field. ▪ There are also oil fields without gas caps. In these cases, the solubility of gas in oil under the prevailing pressure regime is not exceeded, i.e. the gas remains dissolved in oil Petroleum System ▪ Of the total amount of petroleum generated in the source rocks at great depths in hypothetical sedimentary basin, 75% is expelled in the course of primary migration into nearby high- porosity/permeability carrier beds. ▪ During secondary migration, about 50% of the petroleum which has entered the carrier beds remains in the form of impregnations. ▪ About 40% has, at an earlier stage in the history of this sedimentary basin, accumulated in reservoir traps, while the remaining 10% is on its secondary migration route bypassing all traps and eventually leaking out at the Earth’s surface. This process is called petroleum seepage. ▪ About 25% of the original petroleum accumulated gets lost by cap rock leakage occurring at a slow rate over long periods of geologic time. Of the remaining petroleum, another 25% gets lost in the course of chemical, physico-chemical and bacterial processes. ▪ In summary, only about 10% of the petroleum generated in the source rocks of this hypothetical basin can be discovered by exploration and produced for economic usage. For example: the La Luna-Misoa petroleum system of Venezuela and the Arabian/Iranian Basin in the Middle East. More common cases are even less such as in the order of 2-5%, such as several petroliferous basins in the USA and Australia. Petroleum System Petroleum Alteration Those petroleum accumulations which are discovered and produced by the oil industry have survived extended periods of geologic time. During these periods, the physical and chemical conditions of the accumulation in the reservoir can have changed. Since petroleum is thermodynamically metastable under geological conditions, it responds to these changing conditions by adjusting its composition, i.e. the original composition is altered. Geological processes which lead to compositional alteration, and their effects on oil density, expressed in degrees according to the rule formulated by the API (American Petroleum Institute), are schematically illustrated in the following fig. Changes in petroleum composition due to Biodegradation In areas where there are high hydraulic head conditions (groundwater recharge areas at high altitudes), meteoric waters penetrate along high porosity/high permeability strata deeply into sedimentary basins. They are oxygenated and carry bacteria. Wherever these waters flow past petroleum accumulations, they cause biodegradation and water washing effects. Compounds which have higher solubilities in water, such as benzene and toluene, are preferentially removed. Several species of bacteria degrade and consume petroleum hydrocarbons in a very specific way. Depending on favorable microbial growth conditions, the molecular composition of reservoir petroleum is altered to an increasing extent. With increasing degrees of biodegradation, the following effects are observed: • Decreasing concentrations of wet gas and gasoline in favor of kerosene-range components • Decreasing wax contents due to removal of long- chain n-alkanes. • Decreasing gas/oil-ratios (GOR). • Decreasing API gravities (increasing densities). • Increasing concentrations of asphaltenes. • Increasing contents of sulphur and nitrogen. • Increasing viscosities. Changes in petroleum composition due to thermal alteration Petroleums like kerogen react sensitively to increasing thermal conditions. Reservoir oils which get buried deeper and exposed to higher thermal regimes undergo compositional changes with maturation. The overall trend concerns a progressive increase in the proportion of low molecular weight components at the expense of their heavier counterparts. This compositional evolution with rising subsurface temperatures is mainly achieved by cracking reactions. Mediumgravity oils are converted into light oils and condensates and ultimately into natural gas accumulations Gas Hydrates ▪ ▪ Very special cases of gas accumulations occur in the form of so-called gas hydrates. These are solid, ice-like compounds whereby water molecules are arranged in crystal lattices forming cages. Methane molecules are arranged inside these cages. 1 m3 of gas hydrate contains 164 m3 of methane. ▪ Gas hydrates form in high pressure, low temperature environments where sufficient gas and water are present. The hydrate formation requirements restrict the occurrence of natural gas hydrates to two types of geologic locations: ▪ under permafrost in the polar continental shelves and ▪ in sediment beneath the ocean floor. ▪ The blue sections in the generic curves illustrate regions in permafrost and oceanic sediment where the pressure and temperature conditions and the concentration of methane gas are within the hydrate formation and stability zone. These curves are based on pressure-temperature phase equilibrium data ▪ There is a general consensus that the origin of the methane concentrated in naturally occurring hydrates is either microbial (generated by anaerobic decomposition of organic matter) or thermogenic (generated by thermal decomposition of organic matter). ▪ Predictions are that gas hydrates will indeed become an important energy resource in the future when conventional oil and gas resources have much declined. This assumption is based on estimates of enormous quantities of gas hydrates hidden under the deep ocean floors and in arctic permafrost regions. It is estimated that more energy resources are present on Earth in the form of methane hydrates, than exist from the sum of all of the presently known fossil fuel resources (oil, gas, and coal). ▪ Optimistic estimates claim that there is twice as much methane available from gas hydrates ▪ Two of the main challenges to utilizing methane hydrates as an energy resource are recovery and production. In order to exploit the large volumes of trapped gas within gas hydrates, hydratebearing sediment must first be made accessible by drilling deep wells into the oceanic and permafrost reservoirs. Following drilling, methane production can be accomplished by thermal stimulation, depressurization, or inhibitor injection (injection of inhibitors such as methanol to destabilize the hydrate). After hydrate dissociation, the released gas must be isolated and collected. ▪ To date, large-scale production of methane from gas hydrates has not been demonstrated due to economic and safety issues. In order for the potential of methane hydrates to be fully recognized, improvements in hydrate technology must be achieved. Hydrate research groups in the United States and Japan expect to have made these advances by 2016.
