Maturation Processes

(adsbygoogle = window.adsbygoogle || []).push({}); Maturation processes refer to the natural physical and chemical changes that occur in organic matter over time as it is buried deeper and subjected to higher temperatures and pressures. These processes are important in petroleum geology because they can lead to the formation of hydrocarbons (oil and gas) from organic-rich source rocks. Kerogen Maturation https://youtu.be/S6FGgfrT9MQ (adsbygoogle = window.adsbygoogle || []).push({}); Let’s consider the chemical variability of kerogen types and the changes produced as petroleum is generated. To do this, we use Van Krevelen plots, which graph the atomic hydrogen to carbon ratio [latex]\left( \dfrac {H}{C}\right)[/latex] versus the oxygen to carbon ratio [latex]\left( \dfrac {O}{C}\right)[/latex] (Figure 1, [latex]\dfrac {H}{C}[/latex] and [latex]\dfrac {O}{C}[/latex] ratios of kerogen Types 1-IV and their stages in the evolution of petroleum. FIGURE 1 Van Krevelen diagram plotting atomic H/C ratio against atomic O/C ratio. Arrows show evolution paths at increasing maturity. O: formation of oxygenated products [CO2, H2O, NSO molecules]; P: petroleum formation; G: gas formation.). The [latex]\left( \dfrac {H}{C}\right)[/latex] ratio helps define the origin of kerogen. Most of the oxygen is lost during diagenesis in the form of carbon dioxide and water. The highest organic [latex]\left( \dfrac {H}{C}\right)[/latex] ratio of 4 is found in methane gas. The [latex]\left( \dfrac {H}{C}\right)[/latex] ratio decreases rapidly as hydrogen-rock molecules crack off as oil or gas. (adsbygoogle = window.adsbygoogle || []).push({}); Type I algal kerogens enter diagenesis with the highest atomic [latex]\left( \dfrac {H}{C}\right)[/latex] ratios of about 1.65, while Types II, III and IV enter diagenesis with progressively lower [latex]\left( \dfrac {H}{C}\right)[/latex] ratios. As any one of these kerogen types is heated, it may reach the second stage in the formation of petroleum, catagenesis (Figure 2). FIGURE 2 Reach the second stage in the formation of petroleum, catagenesis Because oil and gas molecules have very high [latex]\left( \dfrac {H}{C}\right)[/latex] ratios, petroleum generation causes the [latex]\left( \dfrac {H}{C}\right)[/latex] ratio of the residual kerogen to decrease. Generation of oil and gas from kerogen ceases during the final stage of petroleum generation, metagenesis, but large quantities of methane gas can be generated by thermal alteration of previously generated crude. Residual kerogen produced during this stage approaches pure carbon in the form of graphite. Although both Type I and Type II kerogen are oil-prone, Type I kerogens generate more hydrocarbons than Type II kerogens because [latex]\left( \dfrac {H}{C}\right)[/latex] ratios are initially higher for Type I kerogens. Likewise, Type II kerogens generate larger quantities of hydrocarbons than Type III kerogens, and Type IV kerogens are essentially barren. (adsbygoogle = window.adsbygoogle || []).push({}); Depth, Temperature and Time Effects https://youtu.be/1nZ_APP4PYw (adsbygoogle = window.adsbygoogle || []).push({}); Petroleum generation is related to the burial depths of source rocks. The local geothermal gradient, kerogen type and burial history affect the generation depths for particular types of source rocks. Figure 1 shows average maximum and minimum generation depths. FIGURE 1 Maximum and minimum generation depths At very shallow depths, only biogenic methane is generated during diagenesis by the action of anaerobic bacteria. At depths of 1 to 2 km, catagenesis begins. The principal zone of oil formation during the early stage of catagenesis -- the oil window -- begins at depths of 1 to 2 km and continues to a depth of approximately 3 km. The gas window ranges from 3 to about 4 km, and corresponds to the stage of late catagenesis during which predominantly gas forms. Below this zone, source rocks are over-mature and only methane gas is formed. The correlation of petroleum generation with depth is primarily a function of increased temperature (Figure 2). FIGURE 2 The correlation of petroleum generation with depth is primarily a function of increased temperature Major oil generation begins when source rocks are heated above 60 degrees C. These low-temperature oils, formed at relatively shallow depths, tend to be heavy and laden with non-saturated oil (NSO) compounds. Oils become lighter at greater depths and higher temperatures. Oil generation peaks at temperatures in the vicinity of 100 degrees C, beyond which oil generation declines and condensates form. The boundary between the oil and gas windows occurs at approximately 175 degrees C. Direct generation of hydrocarbons from kerogen stops at approximately 225 degrees C; methane, however, can form from the cracking of previously formed oil up to 315 degrees C. (adsbygoogle = window.adsbygoogle || []).push({}); The western Canada Basin is a good example of the relationship between maturation and depth. Shallow Upper Cretaceous sediments contain immature source rocks that yield dry gas with a high nitrogen content. At greater depths, Cretaceous and Devonian rocks produce oil and wet gas. Deeply buried Paleozoic rocks in the depocenter produce methane and hydrogen sulfide gases. Chemical reaction rates vary as functions of both temperature and time. As seen in Figure 3, temperatures for oil formation are lowest for Paleozoic source rocks and are progressively higher for Mesozoic and Cenozoic source rocks. FIGURE 3 Temperatures for oil formation This relationship between the temperature of oil formation and geologic time may be due to the phenomenon that time compensates for temperature and vice versa. For example, source rocks that have always remained cool may take more than a hundred million years to generate oil, whereas young source rocks subjected to sufficiently high temperatures might generate oil within a few million years. The effect of temperature is exponential, while that of time is linear. Therefore, temperature generally plays a greater role than time in maturation of source rocks. For example, Paleozoic rocks that have never been heated above 50 degrees C will not generate petroleum, regardless of the passage of time. Conversely, time is insignificant in petroleum generation from young source rocks in active basins with high thermal gradients. Wherever rapid burial occurs and geothermal gradients are high, hydrocarbon generation takes place early. Examples include the Miocene-Pliocene beds of Indonesia and California. And, while the generation of petroleum can happen over relatively short time intervals, it might not happen until long after deposition. For example, Silurian-age source rocks in eastern Algeria did not generate hydrocarbons until they were deeply buried during Mesozoic time. (adsbygoogle = window.adsbygoogle || []).push({}); Paleothermometry (adsbygoogle = window.adsbygoogle || []).push({}); The geothermal gradient was often higher when a basin was active than it is today. Therefore, we need accurate paleothermometers to measure the maximum temperature to which a particular source rock was exposed. Some paleothermometers are based on the physical and chemical properties of kerogen, while others rely on rock properties. After determining kerogen type using microscopy, we can evaluate the degree of maturation of a particular kerogen with the Van Krevelen diagram (Figure 1). For all types of kerogen, more hydrogen and oxygen is lost relative to carbon as maturation progresses. We analyze hydrogen, carbon and oxygen contents of kerogens chemically and plot them as ratios. FIGURE 1 Van Krevelen diagram plotting atomic H/C ratio against atomic O/C ratio For some kerogen macerals, such as spores and pollens, color can serve as a paleothermometer. Initially, these macerals are colorless. With heat, they change progressively to greenish-yellow, yellow, orange, reddish-brown, dark brown and ultimately black. The color indicates the highest temperature reached by the source rock. As kerogen is heated, the reflectivity of vitrinite increases gradually. We use a reflecting microscope with a photo-multiplier to measure this reflectivity. This technique is useful because vitrinite is the most extensively dispersed maceral in sedimentary rocks. A linear increase in temperature increases the reflectivity of vitrinite exponentially, which plots as a straight line on semi-log paper (Figure 2). FIGURE 2 Linear increase in temperature increases the reflectivity of vitrinite exponentially (adsbygoogle = window.adsbygoogle || []).push({}); We use the percent mean reflectance, Rm, averaged from several measurements, because individual reflectances vary with plant tissue type and grain orientation as seen with a microscope. Crude oil generation occurs for Rm values between 0.6 and 1.2 percent. Values of Rm between 1.2 and 2 percent signal generation of wet gas, while values from 2 to 4 percent indicate generation of dry gas. We can also use source rock minerals to gauge paleotemperature. Swelling clays, such as montmorillonite, contain a significant amount of structurally bound water. As temperature increases, these clays dewater, gradually losing their mixed layers and becoming more ordered. We use x-ray diffraction techniques to calibrate the systematic loss of layers to temperature. At approximately the optimal temperature of the oil window (80 to 120 degrees C), mixed-layered clays and montmorillonite ultimately transform into other types of clays, such as illite and chlorite. We can also use x-ray diffraction to measure this temperature-related change through the improvement in illite crystallinity. As temperature increases, peaks made by illite on x-ray diffraction patterns become sharper, narrower and more symmetrical. Various methods are used to calibrate this effect with temperature. Clay mineral diagenesis is affected by factors other than time and temperature, such as the chemistry of pore waters. Therefore, paleothermometers based on clay diagenesis may be less precise than kerogen-based methods. Despite their differences, we can correlate these paleothermometers to each other and to the temperatures of oil and gas generation. We can also correlate these paleothermometers to other maturation indicators, such as exinite fluorescence and electron spin resonance. We should use at least two different paleothermometry methods to assess the maturity of a particular source rock. (adsbygoogle = window.adsbygoogle || []).push({}); Assessment Maturation Processes (adsbygoogle = window.adsbygoogle || []).push({}); 1. The highest organic H/C ratio of __________ is found in methane gas. A .4B .8C .16 2. Major oil generation begins when source rocks are heated above: A .30 degrees CB .60 degrees CC .100 degrees CD .155 degrees C 3. In oil generation, the effect of temperature is , while that of time is . A .linear / exponentialB .exponential / linear (adsbygoogle = window.adsbygoogle || []).push({}); 4. For all types of kerogen, more hydrogen and oxygen is lost relative to carbon as maturation progresses. A .TrueB .False 5. As kerogen is heated, the reflectivity of vitrinite: A .decreases gradually.B .increases gradually.C .does not change. Recommended for You Structural Interpretation Prospect Generation | What is a Prospect in Petroleum Geology? Braided Stream Environments Classification of Nonmarine Sandstones Alluvial Fan Environments Meandering Channel Alluvial Systems (adsbygoogle = window.adsbygoogle || []).push({});