3.Organic Matter, Kerogen and Petroleum Generation.pdf

Petroleum Generation, Maturation & Accumulation C.D. Adenutsi, Ph.D. Department of Petroleum Engineering, KNUST Office: Petroleum Building, PB 318 June, 2022  Introduction Some geochemists have suggested that petroleum could come from purely abiogenic processes deep in the lower crus...

Petroleum Generation, Maturation & Accumulation C.D. Adenutsi, Ph.D. Department of Petroleum Engineering, KNUST Office: Petroleum Building, PB 318 June, 2022  Introduction Some geochemists have suggested that petroleum could come from purely abiogenic processes deep in the lower crust or mantle. Processes such as Fischer–Tropsch reactions, as shown in Fig. 1, where carbon monoxide could combine with hydrogen to form hydrocarbons, were suggested as possible mechanisms. Fig. 1 The Fischer–Tropsch reaction for producing hydrocarbons  Introduction After much study, most geochemists feel these reactions cannot account for the volumes of petroleum observed in sedimentary basins or the diversity in the molecular structure and molecular weight range observed in petroleum. The prevailing theory, embraced by the majority of geochemists, is that petroleum is derived from the transformation of preexisting organic matter of biological origin that has been incorporated into sediments  Incorporating Organic Matter Into Sediments Source rocks are fine-grained sedimentary rocks containing relatively high concentrations of organic matter deposited in aqueous depositional settings. In the schematic of a marine depositional environment in Fig. 2., organic matter in sediments can come from three primary sources. Fig. 2 A schematic of transport mechanisms introducing organic matter to a marine deposition environment  Incorporating Organic Matter Into Sediments Autochthonous organic matter is the product of biological activity in the water column above the depositional site. It is primarily the product of photosynthetic organisms such as algae and phytoplankton in the photic zone in the upper part of the water column. These primary producers can be consumed by zooplankton and other organisms in the water column that Fig. 2 A schematic of transport mechanisms introducing organic matter to a marine deposition environment may also contribute to the sediment.  Incorporating Organic Matter Into Sediments Allochthonous organic matter has been transported some lateral distance from where it formed before being incorporated into the sediments. It is often the product of terrestrial higher plants contributing biomass to fluvial system that carry this organic matter to the depositional environment. A small portion may also be Fig. 2 A schematic of transport mechanisms introducing organic matter to a marine deposition environment delivered to aqueous depositional systems by eolian processes  Incorporating Organic Matter Into Sediments The third source is recycled or reworked organic matter. This is preexisting sedimentary organic matter derived from the erosion and redeposition of older sedimentary rocks. Fig. 2 A schematic of transport mechanisms introducing organic matter to a marine deposition environment  Incorporating Organic Matter Into Sediments Of these three types, the autochthonous and allochthonous contributions are important in the development of source rocks. The reworked organic matter is nearly always degraded to the point where it has little or no capacity for being converted into oil and gas Fig. 2 A schematic of transport mechanisms introducing organic matter to a marine deposition environment  Incorporating Organic Matter Into Sediments The autochthonous and allochthonous organic matter need to make their way to the sediment–water interface, become buried in sediment, and converted into a stable form in order to become part of a source rock. Transport through the water column needs to be quick. The longer the organic matter takes to reach the sediment–water interface, the more opportunity it has to be degraded by Fig.3 Formation of source rocks. inorganic chemical processes such as oxidation, or consumed by organisms.  Incorporating Organic Matter Into Sediments One mechanism for rapidly transporting autochthonous organic matter to the seafloor is by fecal pellets. Phytoplankton in the photic zone can be consumed by zooplankton and excreted in fecal pellets. The zooplankton is typically not a very efficient digester and much of the organic matter from the phytoplankton is conserved. Fig.3 Formation of source rocks.  Incorporating Organic Matter Into Sediments The fecal pellets are denser, more ballistic than the original phytoplankton and will rapidly settle to the seafloor as a component of marine snow. Once at the sediment–water interface, preservation of organic matter is a function of the amount of oxidant available, the consumer organism population, and the burial (sedimentation) rate Fig.3 Formation of source rocks.  Incorporating Organic Matter Into Sediments With respect to the amount of oxidant available, preservation of the organic matter is dependent on the location of the oxic/anoxic boundary with respect to the sediment–water interface. If the oxic/anoxic boundary is substantially below the sediment– water interface, oxidative processes, as well as aerobic biological activity, can consume any organic matter at the sediment surface. This condition will also encourage bioturbation that will consume more of the organic matter and further oxygenating the sediments.  Incorporating Organic Matter Into Sediments If the organic matter is left at or near the sediment–water interface long enough (slow sedimentation rates), it can be highly degraded or totally destroyed. If the oxic/anoxic boundary is at or just below the sediment–water interface, oxidation and biologic activity may be limited if the sedimentation rate is high enough to minimize the residence time of the organic matter at the interface. This provides a better opportunity for preservation.  Incorporating Organic Matter Into Sediments However, when the oxic/anoxic boundary is somewhere in the water column above the sediment–water interface (anoxic bottom waters), conditions for organic matter preservation are optimal. Not only are oxidative processes halted, but the anoxic bottom waters limit the biological activity to less efficient anaerobic organisms. Therefore, the best depositional environments for the preservation of organic matter and the formation of source rocks have an anoxic water column.  Incorporating Organic Matter Into Sediments Grain size is important for organic matter preservation. Coarser grained sediment, such as sands and silt, can allow the circulation of bottom waters into the sediments. This circulation from the water column can replenish oxygen in the interstitial waters allowing oxidative processes to continue below the sediment–water interface and encourage aerobic Fig. 4 Comparison of preservation in fine- biological activity. grained sediments versus coarse-grained sediments  Incorporating Organic Matter Into Sediments In finer grained sediments, such as fine clays and carbonate muds, circulation of bottom waters into the sediments is highly restricted. This encourages the development of localized anaerobic environments in the sediment’s interstitial spaces, promoting preservation and limiting biological activity that may consume the organic matter. Fig. 4 Comparison of preservation in fine- grained sediments versus coarse-grained sediments  Incorporating Organic Matter Into Sediments How quickly the organic matter becomes buried in the sediment is also a significant factor in preservation. As shown in Fig. 5, if sedimentation rates are too low, the residence time for the organic matter at the sediment–water interface will be longer and allow degradation processes to continue and provide more opportunity for consumption by bottom grazing organisms. Fig. 5 The influence of sedimentation rate on the preservation of organic matter  Incorporating Organic Matter Into Sediments If the sedimentation rates are too high, the organic matter may become diluted by the sediment and its concentration may not be high enough for a source rock to develop. From studies of source rock occurrences, a sedimentation rate of approximately 1 mm/year appears to be most conducive for source rock development. Fig. 5 The influence of sedimentation rate on the preservation of organic matter  Kerogen Formation The organic matter that initially goes into the sediment may have experienced some amount of alteration. But once this organic matter is incorporated into the sediment, it begins a major transformation from biological organic matter into geological organic matter. Chemical processes such as hydrolysis, reduction, and oxidation as well as microbial activity begin to break down the large molecules and biopolymers into smaller organic compounds.  Kerogen Formation These compounds can then follow one of two main pathways, forming either solvent-soluble or solvent-insoluble sedimentary organic materials, as shown in Fig. 6. A small portion of the biological organic matter may go through additional alteration by reduction, dehydration, and decarboxylation to form an initial preserved bitumen. Fig. 6 Schematic of the diagenetic conversion of biological organic matter to geological organic matter The bulk of this organic material undergoes diagenetic condensation and polymerization to form kerogen Kerogen Formation Kerogen is a complex material with a variable composition and structure that may be converted into oil and gas under the proper subsurface conditions. The variability in the composition and structure of the kerogen is controlled by the type of organisms that contributed to the sediments and by how well the organic matter was preserved. As a result, not all kerogens are created equal. Some kerogens will be capable of generating oil while other kerogens may only be able to generate gas or, in some cases, nothing at all (inert kerogen). Kerogen Formation What controls whether a kerogen will be oil-prone or gas-prone is its hydrogen content and the type of structures (chemical moieties) it contains. In order to be oil-prone, kerogen must be rich in hydrogen and contain the structures within the kerogen that can give rise to the large, complex molecules observed in crude oil. In contrast, gas-prone kerogen is less rich in hydrogen and only needs to contain small, simple structure to make the compounds found in natural gas. Kerogen Formation The nature of the kerogen is controlled by both the type of organisms that contributed organic matter to the sediments and by how well the organic matter was preserved. Biological organic matter rich in hydrogen includes hydrocarbons, waxes, fats, and lipids. This hydrogen-rich organic matter is generally thought to be the results of contributions from algae, bacteria, leaf cuticle, spores, and pollen to the sediments. Hydrogen-poor organic matter comes from materials like cellulose and lignin that makes up the structural or woody tissue in the vascular parts of higher plants. Kerogen Formation If the organic matter is deposited under anoxic conditions, the hydrogen content of the organic matter will be preserved as introduced into the sediments. If hydrogen-rich organic matter is poorly preserved under oxic conditions, the hydrogen content will be reduced. This can result in organic matter that might have been oil-prone actually becoming gas-prone or even inert kerogen. Similarly, hydrogen-poor organic matter that could have become gas-prone kerogen can be degraded by poor preservation under oxic conditions resulting in a reduced gas generating capacity or an inert kerogen. Kerogen Formation Fig. 7 The relationship between the type of organic matter incorporated into the sediment and preservation conditions in determining the type of hydrocarbon generating potential the resulting kerogen will have.  Kerogen Recovery From Rocks Because of its resistance to strong oxidising acids kerogen can be recovered from sedimentary rocks by dissolving most of the rock away with HCl or HF. It is also possible to separate kerogen by a density method, using heavy liquids, because kerogen is lighter than minerals. The resulting concentrate of kerogen can be studied microscopically using transmitted and reflected normal light, to identify the biological origin and the degree of thermal alteration. These phases of altered organic material are called macerals  Types of Kerogen Being a complex of very large molecules (polymer), kerogen is difficult to analyse. However, upon heating to 350–450˚C in an inert atmosphere (pyrolysis) it will break down into smaller components which can then be analysed by means of gas chromatography and mass spectrometry. Kerogen may be classified into 4 main types which may be plotted as a function of the H/C ratio and the O/C ratio Type I Type II Type III Type IV Fig. 8 Types of Kerogen  Types of Kerogen Type I Type one kerogen is also referred to as sapropelic or algal/alginite kerogen This type of kerogen is characterized by having a high initial hydrogen to carbon atomic ratio (H/C) of 1.5 or more, and a low oxygen to carbon atomic ratio (O/C) of less than 0.1. Type I kerogen has a hydrogen index greater than 300 and an oxygen index less than 50. Fig. 8 Types of Kerogen (van Krevelen diagram)  Types of Kerogen Its primary source is from algal sediments, such as lacustrine deposits. Type I kerogen contains high concentrations of alkanes and fatty acids. It is the best source for oil-prone maturation, but unfortunately it is very rare. Fig. 8 Types of Kerogen (van Krevelen diagram)  Types of Kerogen Type II This type of kerogen has a relatively high H/C ratio (1.0 to 1.4) and a low O/C ratio (0.09 to 1.5). Type II kerogen has a hydrogen index between 200 and 300, and an oxygen index between 50 and 100. Fig. 8 Types of Kerogen (van Krevelen diagram)  Types of Kerogen It consists of abundant moderate length aliphatic chains and naphthenic rings. Ester bonds are common and sulfur is present in substantial amounts. Fig. 8 Types of Kerogen (van Krevelen diagram)  Types of Kerogen Type III Type III kerogens are also known as humic kerogens. This type of kerogen has a relatively low H/C ratio (usually < 1.0) and low O/C ratio (0.2 to 0.3). Type III kerogen has a hydrogen index below 300 and an oxygen index above 100. Aliphatic groups are a minor constituent, usually consisting of longer chains originating from higher-order plant waxes. Fig. 8 Types of Kerogen (van Krevelen diagram)  Types of Kerogen The main source of this type of kerogen are continental plants found in thick detrital sedimentation along continental margins. It is less favorable for oil generation, but will provide a source rock for gas. Fig. 8 Types of Kerogen (van Krevelen diagram)  Types of Kerogen Type IV These are inert or residual kerogens. This type contains mainly reworked organic debris and highly oxidized material of various origins. They are generally considered to have no HC source potential. Type IV has the lowest H content and mainly polycyclic aromatic systems Fig. 8 Types of Kerogen (van Krevelen diagram)  Types of Kerogen Table 1The four types of kerogen, the macerals that they are composed of and their organic precursors. Maceral Kerogen Type Original Organic Matter Alginite I Fresh-water algae Exinite II Pollen, spores Cutinite II Land plant cuticle Resinite II Land plant resins Liptinite II All land plant , lipids, marine algae Vitrinite III Woody and cellulosic material from land plant Ineptinite IV Charcoal, highly oxidized or reworked material of any origin  Source Rock Deposition The optimum conditions for source rock deposition begins with high primary biological productivity in and around the depositional environment. This organic matter should be rich in hydrogen with major contributions from algal/bacterial material, spores, pollen, and leaf cuticle. Oxic/anoxic boundary in the depositional environment should be near or above the sediment–water interface to promote good organic matter preservation.  Source Rock Deposition And the sediments being deposited should be fine-grained sediments, such as very fine silt to clay or carbonate muds ( 200˚C) The metagenesis stage is reached at great depths, or in areas of high geothermal gradients at shallower depths. Metagenesis usually begins at depths of approximately 4,000 meters. At this stage, kerogen has very little hydrogen remaining and is forming methane as its only hydrocarbon product. Towards the end of metagenesis, virtually no hydrocarbons are being generated from the kerogen  Stages of Kerogen Maturation Throughout metagenesis, the residual carbon network takes on an increasingly ordered structure, where aromatic kerogen rings are condensed into parallel plates, as in graphite. The H/C ratio and hydrogen index decrease only slightly during metagenesis, since most of the hydrocarbons have already been generated. The completion of metagenesis occurs at vitrinite reflectance values around 4% and Tmax values above 510˚oC. Stages of Kerogen Maturation Fig. 17 General scheme for HC generation  The Oil Window The formation of oil from kerogen depends on the amount and type of source material present in the sediments and the thermal history of the kerogen. It has been conclusively determined that temperature is the most important factor affecting the generation of oil and gas from organic matter. During the generation of petroleum from kerogen, both temperature and time play key roles.  The Oil Window Kerogen, exposed to relatively high temperatures for a short period of time, will mature to about the same extent as kerogen which is exposed to relatively low temperatures for a longer period of time. Thus, the time and temperature history of a kerogen determines occurrence and depth at which kerogen generates oil or gas or both. The depth range over which oil generation occurs is known as the “oil window”. This oil window is usually different for most sedimentary basins. It may cover several thousand meters or may be confined to less than a thousand meters  The Oil Window The determination of the oil window is best performed by geochemical means using Tmax, bitumen extraction, gas chromatography and optical methods such as vitrinite reflectance. In the search for petroleum reservoirs, accurate determination of the oil window is important, because if an organically rich, oil-prone, source rock has not reached the oil window range of temperatures, it will not generate oil.  The Oil Window Determination of the geologic time at which oil was generated within a reservoir is an important factor in evaluating the possibility of the presence of suitable structures to accumulate and trap the oil. If the generation of oil occurred prior to the formation of suitable reservoirs and traps, the likelihood of finding commercial quantities of oil is less certain, than if the reservoir and trap existed prior to the generation and migration of the oil.  The Oil Window Petroleum is found from the Precambrian to the Pleistocene, but is increasingly abundant in younger sediments. There are several reasons for this, the most notable are: 1. Older oil fields are increasingly destroyed over time. 2. The continental split during the Jurassic caused an increase in continental margins and restricted basins. Petroleum Migration The process of migrating the generated petroleum from the source rock to the reservoir/trap begins with part of the generated petroleum from the interstitial spaces (pores) in the source rock moving toward a porous and permeable carrier system. The carrier system may consist of a porous sediment, such as sand or silt, or may be a fault or fracture zone. This process is often referred to as primary migration or expulsion. Petroleum Migration Many ideas were put forth to explain this phenomenon including having the petroleum move by diffusion, in water solution, as a colloidal (micellar) solution, and in gas phase. However, after much study, it is generally believed that oil is expelled from the source rock and moves as a liquid phase. Petroleum Migration The basic concept for liquid-phase primary migration, summarized in Fig. 18. As oil and gas are generated, they move out into the pore spaces of the source rock displacing the pore water. At some point, a minimum saturation threshold is reached where the areas of oil saturation coalesce and begin to form a contiguous oil-wet migration pathway. Fig. 18 A conceptual model for the development of contiguous oil-w migration pathway for hydrocarbon expulsion from source rocks Petroleum Migration As petroleum generation continues, the amount of material above this threshold saturation is available for movement along this pathway, termed expulsion. If this oil-wet migration pathway eventually connects a carrier system, the migrating petroleum may eventually travel to a reservoir/trap and form an accumulation. Fig. 18 A conceptual model for the development of contiguous oil-w migration pathway for hydrocarbon expulsion from source rocks Petroleum Migration Once the hydrocarbons have left the source rock and entered into a carrier system, their continued movement in the subsurface is referred to as secondary migration. The main processes governing secondary migration are buoyancy and capillary pressure. The carrier system may consist of a porous sediment (e.g., sandstone or porous carbonate) or intergranular space associated with a fault or fracture zone. Petroleum Migration Hydrocarbons entering the carrier system begin to accumulate and are held in place by the capillary forces associated with these water- wet intergranular spaces. The buoyancy force is a result of the density contrast between the hydrocarbons and intergranular water. As more hydrocarbons accumulate, the buoyancy force increases and eventually exceeds the capillary pressure in the carrier system allowing the hydrocarbons to move upward.  Petroleum Migration This vertical movement of hydrocarbons forms a continuous oil-wet pathway, similar to the pathways formed in the source rock. When the carrier system enters a reservoir rock, hydrocarbon movement continues along restricted pathways, as shown in Fig. 19 Fig. 19 Cross section and map view of oil migration in a simple Initial movement of the anticlinal stricture hydrocarbons will be vertical until a permeability barrier is encountered  Petroleum Accumulation and Remigration The process of accumulation, or trap filling, is shown in Fig. 20. Hydrocarbons will at first be confined to zones of the highest porosity and permeability. Filling may proceed episodically, with pulses of petroleum moving along Fig. 20 Schematic of the reservoir/trap filling process. (A) shows the established migration pathways. the structure at the beginning of filling, the box indicates the focus area shown in (B–D), (B) is a detailed look at early filling along limited migration pathways, (C) illustrates the coalescing of oil migration pathways, and (D) shows the reservoir filling nearing completion. Note the isolated water saturated zones remaining in (D)  Petroleum Accumulation and Remigration As filling progresses, hydrocarbons eventually will occupy areas of lower porosity and permeability in the sediments. This progressive filling of high to low porous and permeability may result in isolated water-filled regions within the reservoir. In the final stages of filling, most of Fig. 20 Schematic of the reservoir/trap filling process. (A) shows the structure at the beginning of filling, the box indicates the the formation water has been focus area shown in (B–D), (B) is a detailed look at early filling displaced and the oil-water contact along limited migration pathways, (C) illustrates the coalescing of oil migration pathways, and (D) shows the reservoir filling nearing becomes more uniform. completion. Note the isolated water saturated zones remaining in (D)  Petroleum Accumulation and Remigration Once a reservoir is filled if any of the oil and gas leaves the trap and migrates to another trap, this is called remigration. Two scenarios for remigration have been proposed by Schowalter (1979), as illustrated in Fig. 21. In structural traps, this may occur when the trap is filled to the spill Fig. 21 Two models of remigration and differential point. entrapment: fill to spill in structural traps and facies change in stratigraphic traps  Petroleum Accumulation and Remigration Additional oil and gas entering the trap will displace hydrocarbons already present, spilling them updip to the next trap. If a gas cap is present, the spilled hydrocarbons will be oil. Fig. 21 Two models of remigration and differential entrapment: fill to spill in structural traps and facies change in stratigraphic traps  Petroleum Accumulation and Remigration In stratigraphic traps, remigration might take place due a semipermeable seal. Thin or silt-rich zones may be permeable to gas while retaining oil. In these cases, gas may be preferentially leaked updip. Fig. 21 Two models of remigration and differential entrapment: fill to spill in structural traps and facies change in stratigraphic traps Petroleum Accumulation and Remigration All seals are imperfect and leak to some extent. As a result, some leakage of reservoired hydrocarbons toward the surface should be expected. This leakage is often referred to as tertiary migration, or seepage, and is classified according to the amount of hydrocarbon that makes it to the surface or near-surface sediments. Petroleum Accumulation and Remigration Low-concentration (just above background) hydrocarbon seepage is usually called microseepage. Microseepage is difficult to detect with any certainty. In contrast, macroseepage is characterized by high concentration of oil and/or gas in near-surface sediments or obvious surface expressions of the leakage, such as visible seepage.