Hydrocarbon Generation Modelling Research Articles

97/04546 Kinetic model of hydrocarbon generation from coals using maceral composition: Jimenez, A. et al. DGMK Tagungsber., 1997, 9703, (Proceedings ICCS '97, Volume 2), 621–624

97/04546 Kinetic model of hydrocarbon generation from coals using maceral composition: Jimenez, A. et al. DGMK Tagungsber., 1997, 9703, (Proceedings ICCS '97, Volume 2), 621–624

Geohistory, thermal history and hydrocarbon generation history of the north-west South Caspian basin

Both the hydrocarbon potential of, and excess fluid pressure build-up in, the thick (25–30 km) sedimentary pile of the northwestern part of the South Caspian Basin were evaluated using a one-dimensional fluid flow/compaction model. The model consists of three parts: a geohistory model; a thermal history model; and a hydrocarbon generation model. Input data for the model are commonly used depth values of geological parameters: lithofacies, formation thicknesses, stratal ages, porosity, permeability, pore pressure, temperature, total organic carbon content, type of organic matter, vitrinite reflectance and other maturity indicators. In order to bracket oil generation in terms of timing and depth location, two extreme thermal histories were modeled: paleoheat flow values at one half and twice the present-day values with a linear variation through time to present day measured values. The most intensive oil generation occurs during the last 5.2 My, when the ‘oil window’ is confined to depths between 5–7.5 km in the northwest, 7–10 km in the west (onshore part of the study area), and 8–11 km in the central and southwestern parts of the area. Below the ‘oil window’ cracking occurs of oil into gas. Rapid sedimentation, which took place in the middle Pliocene through Quaternary, results in overpressure build-up across all of the study area. Maximum values of excess fluid pressure of 300–400 atm at 6–10 km are reached in the central and southeastern parts of the area, where the sedimentation rate is the highest. Isobaric contours of excess pressure are then at shallow depths compared to the previous history of the area. Because there is a laterally decreasing trend of excess pressure, oriented from the central and western parts of the area to the northeast and, in addition, the sand/shale ratio is increasing in the same direction, inferences that can be drawn on the most probable hydrocarbon migration directions suggest recent flows towards the northeast with hydrocarbon accumulations of gas and light oil likely to be more prevalent in the northeastern sands.

The hydrocarbon generation mechanism and the three-stage type model of hydrocarbon generation for carbonate source rocks

The diagenetic mechanism and process of carbonate rocks, which is different to that of clastic rocks, decides the existence of different existing state organic matters in carbonate rocks. This has been verified by both the microscopic observation of organic petrology and the analysis of organic geochemistry of many samples. Based on the hydrous pyrolysis simulation experiment of the low-mature carbonate rocks, the contrasting study on the yield and their geochemistry characteristics of different existing state soluble organic matters of a series of various maturity samples shows that the different existing state organic matters make different contributions to hydrocarbon generation during every evolution state. So that, the hydrocarbon generation process of carbonate rocks can be summarized as the following three stages: the first is the direct degradation of biogenic bitumen macromolecules during the immature stage, the second is the thermal degradation of a large amount of kerogen at the mature stage, the last stage is the expulsion or release of inclusion organic matter owing to the increased thermal expansion pressure during the high evolution stage.

Hydrocarbon generation modelling in the west of the Moesian Platform, Romania

Silurian, Middle Carboniferous, Middle Jurassic and Sarmatian shales as well as Devonian bituminous limestones are thought to be main the source rocks in the study area. The thermal maturation level of the source rocks was computed using burial history curves for 175 wells. Maps of isoreflectance show that all the source rocks are mature in the north of the study area. The onset of oil generation from most of the source rocks took place during Sarmatian and Pliocene times, after most traps were formed. The calculations suggest that the volumes of hydrocarbons available to be reservoired are much greater than the volumes discovered to date.

A Comparison of the Rates of Hydrocarbon Generation from Lodgepole, False Bakken, and Bakken Formation Petroleum Source Rocks, Williston Basin, U.S.A.: ABSTRACT

Recent successes in the Lodgepole Waulsortian Mound play have resulted in the reevaluation of the Williston Basin petroleum systems. It has been postulated that hydrocarbons were generated from organic-rich Bakken Formation source rocks in the Williston Basin. However, Canadian geoscientists have indicated that the Lodgepole Formation is responsible for oil entrapped in Lodgepole Formation and other Madison traps in portions of the Canadian Williston Basin. Furthermore, geoscientists in the U.S. have recently shown oils from mid-Madison conventional reservoirs in the U.S. Williston Basin were not derived from Bakken Formation source rocks. Kinetic data showing the rate of hydrocarbon formation from petroleum source rocks were measured on source rocks from the Lodgepole, False Bakken, and Bakken Formations. These results show a wide range of values in the rate of hydrocarbon generation. Oil prone facies within the Lodgepole Formation tend to generate hydrocarbons earlier than the oil prone facies in the Bakken Formation and mixed oil/gas prone and gas prone facies in the Lodgepole Formation. A comparison of these source rocks using a geological model of hydrocarbon generation reveals differences in the timing of generation and the required level of maturity to generate significant amounts of hydrocarbons.

Primary cracking of algal and landplant kerogens: Kinetic models of isotope variations in methane, ethane and propane

Samples of an algae-rich kerogen and a xylite were subjected to an open-system pyrolysis that allows a simulation of primary cracking (temperatures: 20 to 810°C, heating rate: 5°C/min, helium flow: 21 ml/min) within the (measured) maturity range 0.3 to 5.4% vitrinite reflectance. Gases collected during pyrolysis were analyzed for their molecular composition and the carbon isotope ratios of methane, ethane and propane. With increasing maturity of the algae-rich kerogen, we observe an increase of the carbon isotope ratios of produced light hydrocarbons. Carbon isotope values of methane derived from xylite, however, show significant inversions with increasing maturity, that indicate an isotopic inhomogeneity of the precursors from which methane is generated. Hydrogen isotope values of methane from Kukersite vary between −211 and −84‰, whereas, hydrogen isotope ratios of methane from xylite increase from −314 to −164‰. The data of the pyrolysis experiments have been used to develop kinetic models of hydrocarbon generation that are combined with Rayleigh-distillation models to describe the isotope fractionation between organic matter and light hydrocarbons. Carbon isotope fractionation factors between kerogens and individual gas components are high for Kukersite ( α CH4-Kuk = 1.017, α C2-Kuk = 1.009, α C3-Kuk = 1.005) and low for xylite ( α CH4-Xyl = 1.0042, α C2-Xyl = 1.003, α C3-Xyl = 1.001). Hydrogen isotope fractionation factors are lower for Kukersite and higher for xylite ( α CH4-Kuk = 1.1, α CH4-Xyl = 1.2). Gas generation and isotope models are combined with kinetic models of thermal kerogen alteration. The results of the calculations are compared to measured data of natural samples from the Delaware and Val Verde basins (U.S.A.).

Estimation and inference in inverse methods for kinetic models of hydrocarbon generation

Procedures based on ordinary and generalized least of squares for the estimation of kinetic parameters in laboratory pyrolysis experiments are compared. When the data consist of measurements on the degree of chemical reaction through time for a number of temperatures, a single regression procedure is preferred to the two-stage regression alternative. Methods are developed for the construction of confidence intervals for calibration curves used to infer formation temperature on the basis of the unreacted fraction of source material.

Modelling of hydrocarbon generation in the Jameson Land Basin, East Greenland

Modelling of hydrocarbon generation in the Jameson Land Basin, East Greenland

Chemical Kinetic Model of Hydrocarbon Generation, Expulsion, and Destruction Applied to the Maracaibo Basin, Venezuela

This paper describes the development and application of a compositional chemical model of hydrocarbon generation, expulsion, and destruction for the Cretaceous La Luna Formation source rock of the Maracaibo basin, Venezuela. Applications include both laboratory and geological settings. Laboratory pyrolysis experiments were used to study bulk oil generation, expulsion, and associated changes in composition of the kerogen, extractable organic matter, and expelled and unexpelled hydrocarbons. The laboratory experiments were also used to determine kinetic parameters to quantitatively describe organic reactions, via a computer model that also includes simulation of pressure-driven primary expulsion, over widely varying conditions. We show that the chemical model accurately sim lates the experimental results. Thermal history models for wells in the Maracaibo basin were used to simulate hydrocarbon generation and pore pressure development in the La Luna Formation and expulsion into nearby Cretaceous reservoirs. Results of the modeling indicate that both compaction disequilibrium and organic maturation play important roles in the development of excess pore pressure in the La Luna Formation. The model simulation of the variation of indicators such as Rock-Eval parameters and extract and oil compositions shows generally good agreement with measurements from remaining kerogen, oils, and extracts recovered from the La Luna Formation and from nearby Cretaceous reservoirs.

The Origin of Oil and Gas Accumulations in the Western Sector of the South Caspian Sea: ABSTRACT

The western sector of the South Caspian Sea is the most studied offshore area within the intermontane South Caspian Depression. The base of the sedimentary section occurs at depths of 15-18 km and the thickness of Pliocene-Quaternary section reaches 10 km. Hundreds of drill wells, some exceeding 6 km, have been drilled in the study area and adjacent onshore providing detailed subsurface information for evaluating the petroleum system. Molecular characterization of Miocene-Pliocene reservoired hydrocarbons indicate most of the oils have been sourced from the same or similar source facies at temperatures near or less than peak generation. Examination of Neogene and Paleogene source rock organic richness and molecular character indicates the hydrocarbons are not syngenetic in origin but most likely sourced from Lower Miocene or older shales. Maturation modeling based on well and seismic data indicates temperatures sufficient to generate large volumes of hydrocarbons does occur at depths from 6.5 to 12 km, 2 to 3 times greater than their present reservoir depths. A multi-stage model of hydrocarbon emplacement for evolving structural and stratigraphic traps has been postulated based on the distribution and type of hydrocarbons, tectonic-stratigraphic development, hydrocarbon generation models, and probable migration pathways.

Reflected light microscopy and micro-FTIR of Upper Ordovician Gloeocapsomorpha prisca alginite in relation to paleoenvironment and petroleum generation, Saskatchewan, Canada

Gloeocapsomorpha prisca alginites from Upper Ordovician Type I kerogen in hydrocarbon source rocks (kukersites), Yeoman Formation, Saskatchewan, Canada, have been studied using incident light microscopy and transmission micro-Fourier transform infrared spectroscopy. Gloeocapsomorpha prisca coccoidal alginite are classified as three maceral varieties: (i) small agglomerations of thin-walled disseminated A, (ii) larger agglomerations of thick-walled disseminated B; and (iii) a stromatolitic variety. Each alginite maceral variety is interpreted as a stage in the life cycle of the algal precursor resulting from progressive normal growth controlled by chemical and physical changes in the paleowater column. Thickened cell walls of disseminated B and stromatolitic G. prisca are characterized by strong i.r. absorbances in the OH region and a higher aromatic C—H absorption compared to the early growth stage of the disseminated A alginite at the same level of thermal maturity. This characteristic is attributed to the presence of highly aliphatic and resistant outer cell wall biopolymers formed by the algal precursors in response to a variation in either oxygen supply or fluctuating salinity levels within the paleoenvironment and is outlined in a proposed paleoenvironmental model. The rate of reflectance increase in oil and the degree of fluorescence red shift (lambda max) with increasing depth of burial and thermal maturation is greater for G. prisca disseminated varieties compared to the stromatolitic maceral variety. Aromatic C—H absorption (3050 cm −1) per unit area for disseminated A and B alginite increases at approximately the same rate with increasing thermal maturity. In contrast the aliphatic C absorption bands (2920 and 2850 cm −1) decrease with increasing maturity in G. prisca disseminated A alginite whereas aliphatic absorption per unit area increases in disseminated B alginites with increasing thermal maturation. The aliphatic absorption bands also increase with increasing thermal maturation for stromatolitic G. prisca, but in a pattern unlike disseminated B. A hydrocarbon generation model for G. prisca alginite proposes that the molecular structure of the disseminated B variety undergoes a transformation from an alkyl long chain structure into a more cyclic bitumen-like maceral prior to peak generation. In contrast, the smaller, thin-walled, disseminated A alginite,representing the early growth stage, probably generates free bitumen from diagenesis through to catagenesis. This is supported by a reduction in aliphatics with increasing thermal maturity and by the formation of oily-bitumen that evolves from the alginite during petrographic analysis. The stromatolitic G. prisca alginite remains morphologically very rigid throughout the diagenetic range of thermal maturities.

Inverse methods and kinetic models of hydrocarbon generation. IV. Sensitivity analysis, synthetic tests, and application of a residual kerogen analysis model to geological conditions

An investigation is given of sensitivity analysis, synthetic tests, and application to geological conditions of an inverse kinetic model for residual kerogen analysis. Using kinetic parameters derived from different experimental data a sensitivity analysis study allows a discussion of the discrepancies in predictions of kerogen degradation rates and cumulative amounts of kerogen degraded with temperature, time, and depth of sediments. The synthetic tests and the application examine the applicability to different geological conditions and the uncertainty in predictions of hydrocarbon generation. The study shows that when average values of the kinetic parameters derived from different experimental conditions and samples are used under geological conditions, the modeled kerogen degradation rates and cumulative amount of kerogen degraded are uncertain by about 25°C in temperature, 12.5 My in time and 600 m in depth.

Expulsion from hydrocarbon sources: the role of organic absorption

The role of absorption of generated petroleum within solid organic matter in source rocks has been investigated. We conclude that absorption is a significant phenomenon and that selective absorption is one cause of observed compositional differences between migrated petroleum and petroleum (bitumen) extracted from source rocks. Evidence for absorption includes the frequently-noted correlation between extractable organic content and TOC. Absorption selectivity appears consistent with documented interactions between solvents and either coals or synthetic polymers. Preliminary modeling of selective absorption equilibrium gives compositions of absorbed versus free liquids that are consistent with observations. A method is described for including hydrocarbon absorption effects in predictive models of hydrocarbon generation and expulsion. A key part of this method is assessment of expulsion efficiency from source rocks, using geochemical measurements. When absorptive retention of generated hydrocarbon liquids is included in yield calculations, expulsion of oil from low Hydrogen Index sources (even with high TOC values) is delayed. This results in ultimately higher gas-oil ratios of expelled petroleum.

Confidence limits on kinetic models of primary cracking and implications for the modelling of hydrocarbon generation

Kinetic models of primary cracking for use in hydrocarbon modelling are obtained through empirical calibration against laboratory measurements. This paper utilizes least-squares variance analysis to evaluate the uncertainty in the calibrated kinetic parameters and discusses some consequences for the prediction of hydrocarbon generation. It is substantiated that the sensitivity of the average kinetic parameters E a ∗ and log e (A) ∗ to micropyrolysis errors can be parameterized by errors in pyrolysis T max. The absolute and relative errors in T max are modelled by normal (Gaussian) random variables and the variance analysis yields the joint normal probability density distribution of variability in E a ∗ and log e (A) ∗ . It is found that T max errors reduce the ability to resolve independently the values of E a ∗ and log e (A) ∗ : the estimation errors are highly positively correlated and repeated measurements on identical kerogens will produce values of E a ∗ and log e (A) ∗ which tend to fall close to and along the line log e (A) ∗ = E a IRT p + constant , where T p is an average pyrolysis temperature. This correlation is consistent with observations, and hence it is suggested that it is mainly an artifact which originates in the experimental errors of laboratory pyrolysis. When values of E a ∗ and log e (A) ∗ are confined to the region of the confidence ellipsoid, the pyrolysis data are satisfied within their error bounds. However, the variability in predictions of hydrocarbon generation may be large depending on the particular geological temperature history. The uncertainties in the depth to the oil window may be several hundreds of metres, and the timing of peak hydrocarbon generation rate may vary considerably. The inclusion of basin geochemical data in the calibration drastically reduces the ambiguity in E a ∗ and log e (A) ∗ and emphasizes the need to validate the laboratory calibrated kinetic models against basin observations.

Determination of Virgin Rock Temperature From Drillstem Tests

This paper reports on the accuracy of virgin rock temperatures determined from drillstem tests (DST's) that was investigated by examining factors that affect the temperatures recorded downhole during DST's. It is shown that virgin rock temperatures can be calculated with a standard deviation of about 1.5{degrees} C. The data base for the investigation consisted of more than 300 measurement series recorded from DST's in the Norwegian North Sea, encompassing temperature readings from 208 DST's in 112 different oil and natural gas wells.

Inverse methods and kinetic models of hydrocarbon generation: III. Case histories for autoclave product analysis

From a determination of the transformation matrix for three pyrolysis product experimental data sets, an examination is given of both the applicability of the laboratory experimental data to the modeling of oil cracking in a sedimentary basin, and of the appropriateness of an inverse model. The results of the laboratory experimental data sets, which were done under different thermodynamic conditions and using different sources, show that the transformation matrix varies over each data set and also with time. Therefore, it is necessary to check the data sets before applying them to a basin for hydrocarbon modeling. The laboratory experimental data taken at lower temperature and over longer times appear more pertinent for the construction of an oil-cracking kinetic model suitable for geologic conditions.

Buried Mesozoic Rift Basins of the U.S. Middle Atlantic Continental Margin

The Atlantic continental margin is one of the frontier areas for oil and gas exploration in the US. Most the activity has been offshore where Upper Jurassic-Lower Cretaceous siliciclastic and carbonate rocks have been the drilling objectives, with only one significant but noncommercial gas discover. Onshore, recent exploration activities have focused on early Mesozoic rift basins buried beneath the postrift sediments of the middle Atlantic coastal plain. Many of the basins are of interest because they contain fine-grained lacustrine rocks that have sufficient organic richness, if not lost through hydrocarbon generation, to be classified as source beds for oil or gas. Locations of inferred rift basins beneath the middle Atlantic coastal plain were determined by analysis of drill-hole data in combination with gravity anomaly and aeromagnetic maps. Two basins in Delaware and the Queen Anne basin of Maryland are imaged on a regional Vibroseis profile. Areas enclosing inferred rift basins in the offshore region were mapped from interpretation of seismic reflection profiles. Assuming that petroleum source beds are present in the basin (synrift) rocks, hydrocarbon-generation models (Lopatin method) indicate that for a basin just offshore Delaware that is buried by 7 km of postrift sediments, only dry gas would bemore » present in reservoir rocks; for the Norfolk basin of the Virginia coast buried by only 3 km of postrift rocks, the upper few hundred meters of synrift rocks are still within the oil-generation window. The less deeply buried basins beneath the coastal plain likely are still within the oil window.« less

Solid Bitumen at Atigun Gorge, Central Brooks Range Front: Implications for Oil Exploration in the North Slope Fold and Thrust Belt

The Atigun Gorge area of the north-central Brooks range is a structurally complex region in which a sequence of north-verging duplex structures involving Paleozoic and Mesozoic Ellesmerian continental margin deposits are structurally overlain by a south-verging thrust of Brookian foreland basin deposits of Albian age. The resulting structural triangle zone is marked by numerous small-scale thrusts involving Permian and Triassic strata in which solid bitumen, occupying fissures up to 10 cm wide and several meters in length, has been found. The presence of aromatics in the odorless, black material was confirmed by ultraviolet fluorescence following extraction in dichloromethane. The occurrence of solid bitumen at Atigun Gorge adds to a growing inventory of hydrocarbon-filled fractures found mostly in Cretaceous rocks in the Brooks Range foothills. These occurrences are consistent with a model of hydrocarbon generation beneath the northern margin of the Brooks Range. The regional distribution of vitrinite reflectance isograds suggests that the northern margin of the Brooks Range and the adjoining foreland basin deposits of the North Slope have experienced similar thermal histories. The 0.6% vitrinite reflectance isograd intersects the land surface along the southern margin of the foreland and the 2.0% isograd lies within the northern part of themore » range. Although these relations suggest the possibility of petroleum resources at shallow depths beneath the Brooks Range foothills, they also indicate that a considerable amount of differential uplift has occurred, probably resulting in redistribution and some leakage of any oil and gas accumulations.« less

Inverse methods and kinetic models of hydrocarbon generation: I. Theoretical considerations

Several different proposed models of thermocatalytic cracking of kerogen to hydrocarbons are exhibited. The specific models are then combined into a single generic, encompassing framework. For laboratory pyrolysis measurements of kerogen degradation and of thermal generation of hydrocarbons, inverse methods are used to show how to determine the relevant distributions of kinetic parameters consistent with the measured data.

How well can artificial coalification simulate the natural maturation trend?

A modified Fischer retort apparatus was used to pyrolyze three organic-rich rocks (Types I, II and III) to various degrees of maturation. In order to test the feasibility of constructing hydrocarbon generation models from the pyrolysis data, we examined the coalification trends of natural and pyrolyzed coals. The maturation trend expressed by H/C vs O/C atomic ration of the pyrolyzed coal-residues is very different from that of naturally matured samples. However, the trend expressed by H/C vs vitrinite reflectance of the pyrolyzed coal-residues and natural samples are very similar. In addition, the “H/C vs vitrinite reflectance” trend shown by the published data from both open-system pyrolysis (Rock-Eval) and from closed-system pyrolysis is very similar to that of the natural samples. Although the artificial coalification does not simulate the natural maturation perfectly, it seems to simulate the maturation trend expressed by “H/C vs vitrinite reflectance” rather well. Because the pyrolysis yield of the organic matter in organic-rich rocks (including coals) correlates closely with the H/C of kerogens, the artificial coalification should simulate the maturation trend expressed by “yield vs vitrinite reflectance” as well. This result justifies the simulation of petroleum yield of source rocks as a function of vitrinite reflectance using a pyrolysis apparatus such as the Fischer retort.