Hydrocarbon Generation Modelling Research Articles

A study on molecular structural evolution of type II kerogen in a gold tube thermal system: Insights from solid-state 13C NMR

Lacustrine type II kerogen is widely distributed in China and has important hydrocarbon potential, but the study of its structural evolution is not comprehensive enough. In this study, a closed gold tube system was used to simulate the maturation of kerogen extracted from the Nengjiang Formation of the Songliao Basin to investigate a model of hydrocarbon generation and molecular structure change in lacustrine type II kerogen. The pyrolysis products at two heating rates were collected and quantitatively analyzed, and the Easy%Ro of 20 solid kerogen residue samples (solid pyrolysis products after extraction of methylene chloride and methanol) ranged from 0.69 to 2.49. From elemental analysis and 13C nuclear magnetic resonance (13C NMR), the molecular structure evolution of kerogen was clearly determined, and four average molecular models of kerogen were established. The results show that with increasing maturity, the aliphatic fractions of kerogen decreased, and the aromatic fractions increased. Before the main oil window (Easy%Ro < 0.89), the main products were nonhydrocarbon heteroatomic functional groups (NSOs: asphaltene and resin). The oil peak occurred at an Easy%Ro of approximately 1.1 when hydrocarbon C14+ production reached the maximum and kerogen residue was the lowest. After the oil peak, aromatic groups became dominant in the structure. C14+ began to decrease, and the kerogen residue proportion increased, which was related to the occurrence of secondary coking reactions after the main oil window. The hydrocarbon generation capacity of kerogen was exhausted after the oil peak, and the kerogen likely became the precursor of generated gaseous products. In the gas window (Easy%Ro > 1.53), the large quantity of C1-5 was mainly due to the secondary cracking of hydrocarbons. The number of aromatic structures caused by alkyl bond breaking and condensation was estimated. It was found that before the oil peak, the number of aromatic structures caused by alkyl bond breaking decreased and was higher than that of aromatic structures caused by condensation. After the oil peak, the latter structures were obviously dominant, which further indicates that polymerization is the main structural change mechanism of kerogen evolution.

A method for assigning pre-exponential factors for kerogen kinetics, calibrated with Easy%RoDL, and comparison with EASY%Ro

Modeling hydrocarbon-generation processes requires reliable kinetic models for the thermal decomposition of kerogens. To improve confidence and accuracy in modeling of generation, this study employs data from both natural and laboratory maturation to quantify thermal stress and strain for kerogens in 11 source-rock data sets. The method yields kinetic parameters (pre-exponential factor and Ea) for hydrocarbon generation that are constrained to make accurate predictions about thermal stress (quantified here as Ro-equivalent) and thermal strain (quantified as Hydrogen Index) under both laboratory and natural conditions. Methods for converting Tmax values to Ro-equivalents were examined and are discussed briefly. Vitrinite reflectance values were calculated at geological heating rates using the Easy%RoDL kinetic formulation, and were then compared with previous results obtained using EASY%Ro. The large differences observed between the EASY%Ro and Easy%RoDL evaluations are attributed to the differences in the pre-exponential factors in those two Ro-kinetic formulations. Understanding this relationship gives us a way to choose kinetic parameters for hydrocarbon generation that will work well for modeling under geological conditions. The single best A factor for hydrocarbon-generation when using EASY%Ro is 1e13 s−1 , while that for Easy%RoDL is 2e14 s−1 . The minor variation in A factors observed within each of the data sets may or may not be real. Using these results and concepts, more reliable hydrocarbon-generation windows in terms of either Ro-equivalent or Transformation Ratio can be achieved and cross-correlated. These results thus have the potential to increase both the accuracy of hydrocarbon-generation modeling, and the confidence in its results. Cited as: Waples, D. W., Yang, S. A method for assigning pre-exponential factors for kerogen kinetics, calibrated with Easy%RoDL, and comparison with EASY%Ro. Advances in Geo-Energy Research, 2023, 7(1): 1-6. https://doi.org/10.46690/ager.2023.01.01

Maturity assessment of solid bitumen in the Sinian carbonate reservoirs of the eastern and central Sichuan Basin, China: Application for hydrocarbon generation modelling

Maturity assessment of solid bitumen is significant for the reconstruction of the thermal evolution history and obtaining the key periods of hydrocarbon generation for the Qiongzhusi source rocks in the eastern and central Sichuan Basin because of the absence of vitrinite in the marine mudstones. Based on the Fourier transform infrared (FTIR) spectroscopy and Raman spectroscopy analyses of solid bitumen, the thermal maturity of solid bitumen in the Sinian reservoir was evaluated, which was used to calibrate the thermal maturation history modelling results of the Qiongzhusi source rocks. The FTIR spectrums of solid bitumen are characterized by depleted aliphatic carbon and CO group, and enrichment of aromatic carbon, which indicates that the vitrinite reflectance equivalent (VReq) values of solid bitumen in the Sichuan Basin exceed at least 1.3%. The calculated VReq values of solid bitumen inferred by Raman spectroscopy analysis are 3.8%–4.09% and 3.51%–3.77% in the eastern and central Sichuan Basin, respectively. The calculated VReq values of bitumen in fluorite and calcite inclusions of the central Sichuan Basin vary from 3.54% to 3.64%. The thermal evolution history of the Qiongzhusi source rocks can be divided into two heating–cooling stages. At the end of the second heating stage, which is the Late Cretaceous, the Qiongzhusi source rocks reached the highest temperature of 250 and 225°C in the eastern and central Sichuan Basin, respectively. The different burial and thermal history of the Qiongzhusi source rocks controls their key periods of hydrocarbon generation in the eastern and central Sichuan Basin. Two episodes of intense oil generation of the Qiongzhusi source rocks were determined at 440–380 Ma and 290–260 Ma, and one phase of gas generation from oil cracking was from 260 to 85 Ma in the eastern Sichuan Basin. The intense oil generation of the Qiongzhusi source rocks occurred at 240–185 Ma and the oil cracking phase was from 185 to 90 Ma in the central Sichuan Basin.

Petroleum generation modelling of the Middle‐Late Cretaceous sediments in the Abu Gharadig Field, Northwestern Desert, Egypt

The present work introduces an integral study concerning the Middle‐Late Cretaceous source rocks in Abu Gharadig (AG) Field utilizing source rock evaluation techniques and hydrocarbon generation modelling. The used methods include TOC%, Rock‐Eval pyrolysis, vitrinite reflectance (Ro%), and 1D basin modelling data. Our results show that most of the studied marine Middle‐Late Cretaceous intervals in AG Field are considerable as source rocks, excluding the Abu Roash A‐D members. The Kharita, Bahariya, and Abu Roash E &amp; G intervals have mainly gas‐prone kerogen. The Abu Roash F and Khoman B members contain mixed kerogen type II/III with oil/gas‐prone generative potential. Khoman A member has marine type II kerogen with mainly oil‐ and minor gas‐prone generative potential. Among the Middle‐Late Cretaceous rock units, the Khoman Formation is either immature or early mature, whereas others are mature enough to generate hydrocarbons. The burial history models typify a high subsidence rate during the deposition of Kharita, Bahariya, and Abu Roash formations in response to the Tethyan rifting phase. The timing of the peak of oil generation window for the Abu Roash G interval is ranged as Late Oligocene‐Early Pliocene time. Moreover, the timing of the peak of oil generation for the Abu Roash F interval is ranged as Early Miocene‐Latest Miocene. Based on transformation ratios (TR), the Abu Roash F member demonstrates a limited hydrocarbon expulsion (25% &gt; TR &lt;50), whereas both Abu Roash G and Khoman B members can generate in‐situ hydrocarbon (TR ≤10%). Compiling data along the AG basin from previous works infers that there are spatial and temporal discrepancies in organics composition and thermal maturity of the Middle‐Late Cretaceous intervals. Changes in paleoclimate, eustatic, and basin tectonics can be considered as the primary drivers that triggered such spatiotemporal variation. Integrated approaches are needed to constrain the multi‐geospheric interactions of major Cretaceous anoxic events in the Northwestern Desert of Egypt, and to explore the driving forces on these organics‐accumulating events.

Potential resources of conventional, tight, and shale oil and gas from Paleogene Wenchang Formation source rocks in the Huizhou Depression

Conventional and tight unconventional oil and gas resources in the Huizhou Depression have shown broad exploration prospects, which mainly originate from Wenchang Formation source rocks. Thus far, studies on Wenchang Formation source rocks mainly focused on the geochemical characteristics and conventional petroleum resource evaluation; however, the correlation of conventional, tight, and shale oil and gas, and their resources are still unknown. In fact, the formation of conventional, tight, and shale oil and gas are intrinsically related, which allows for a more objective evaluation to consider the three types of oil and gas resources simultaneously in the whole dynamic process of both hydrocarbon generation and expulsion, as well as reservoir tightness history. In this work, based on geological and geochemical analyses, the improved hydrocarbon generation potential method was utilized to establish a hydrocarbon generation and expulsion model of the Wenchang Formation source rocks. Then, combined with the reservoir tightness history, the conventional, tight, and shale oil and gas resources were evaluated. The results show that the Wenchang Formation source rocks are distributed in the whole depressions, with a thickness of 50-1850 m and an average total organic carbon content of 2.2%. The organic matter is mainly type II and is mature-high maturity. The Wenchang Formation source rocks reached hydrocarbon generation threshold and expulsion threshold at a vitrinite reflectivity of 0.43% and 0.65%, respectively, and the reservoir evolved completely tight at 2.3 Ma. Overall, the Lower and Upper Wenchang Formation contain a large amount of conventional, tight, and shale oil and gas resources. Cited as: Hu, T., Wu, G., Xu, Z., Pang, X., Liu, Y., Yu, S. Potential resources of conventional, tight, and shale oil and gas from Paleogene Wenchang Formation source rocks in the Huizhou Depression. Advances in Geo-Energy Research, 2022, 6(5): 402-414. https://doi.org/10.46690/ager.2022.05.05

Hydrocarbon generation potential and model of the deep lacustrine source rocks in the Dongying Depression, Bohai Bay Basin

The deep mudstone in the Palaeogene of the Dongying Depression has been relatively deeply buried and is a useful example of a deep source rock. We use TOC, rock pyrolysis, gas chromatography-mass spectrometry (GC-MS) and vitrinite reflectance (VRo) to evaluate organic matter types, the sedimentary environment, thermal maturity, and hydrocarbon generation potential. Thermal pyrolysis experiments and PVT phase simulation were also used to study the evolution of hydrocarbon generation in these deep source rocks. Two sets of dark mudstone are formed in a reductive salt lake environment, and the organic matter types are mainly I and II. TOC data and pyrolysis experiments show considerable hydrocarbon generation potential. The mudstone samples present low pristane/phytane, high gammacerane/C30hopane, and gammacerane/C31hopane (22R) values, reflecting a strong reduction environment with development of gypsum and salt rocks for the source rocks. A significant effect of maturity on the carbon isotope was indicated, and the carbon isotope values of aromatics are unusually heavier than those of saturated hydrocarbons and resins. The maturity parameters VRo and pyrolysis peak temperature (Tmax) are somewhat reduced owing to the influence of multiple units of gypsum-salt rocks. The VRo values of the two sets of mudstone are in the range 0.74%–1.0% and 0.75%–1.95%, respectively, indicating that these mudstones are mainly moderately mature and high to over mature. The results of thermal simulation experiments of a hypersaline mudstone show that the increase in organic matter maturity is uneven at different stages of thermal evolution, and the increasing rate is relatively fast in the oil generation window. The wide maturity range of the source rocks contributes to the formation of various types of reservoirs, including normal oil, volatile light oil, condensate gas and single dry gas in the deep part of depression; all reservoir types are distributed regularly with burial depth. A detailed hydrocarbon generation model for salt lake facies is proposed to show the evolutionary stages of biogas, bitumen, low mature oil, normal oil, wet gas, volatile oil, condensate gas, and dry gas with increasing thermal maturity. Reservoirs of volatile oil, condensate gas, and dry gas develop at depths of >4000 m. At depths of >4500 m, condensate gas and single dry gas reservoirs mainly exist; these are the main targets for deep petroleum exploration in the area.

A calibrated empirical method to choose A factors for kerogen kinetics. Part 1: Using Easy%Ro to calculate thermal stress

Kinetic parameters (A factor and Ea distribution) for kerogens are routinely determined using data from high-temperature pyrolysis experiments, with few efforts to validate or calibrate the application of those high-temperature kinetics under cooler geological conditions. This study uses data from both natural and laboratory maturation to quantify thermal stress and thermal strain in source rocks. Values for both A and Ea are thus constrained under both laboratory and natural time-temperature conditions to make accurate predictions about thermal stress (quantified here as Ro-equivalent) and thermal strain (quantified as both Hydrogen Index and Mean activation energy (Mean Ea)). “Accuracy” is defined here as simultaneous agreement between measured values and values calculated using standard kinetic equations (Easy%Ro for thermal stress and the standard pseudo-first-order attrition hydrocarbon-generation model for thermal strain). To achieve this agreement the calculated A factor and Ea distribution for hydrocarbon generation were adjusted to fit the measured values for both stress and strain. The resulting solutions perform equally well under laboratory and natural time-temperature conditions.The method was developed and tested on nearly 2000 samples from ten North American kerogens representing various ages and kerogen types. If we assume that the 2001 equation of Jarvie et al. for converting Tmax to Ro-equivalent and that the Easy%Ro kinetics for evolution of Ro are satisfactory, the best single value for A for hydrocarbon generation is between 1e13 and 1.5e13 s−1, with a range from 1e13 to 5e13 among the best six data sets studied. The potential impact of using erroneous uncalibrated A factors in defining generation windows is demonstrated. This new information will lead to major increases in both the accuracy of modeling of hydrocarbon generation, and our confidence in the results of such modeling.

Hydrocarbon Generation Potential of Microbial Carbonate in the Western Qaidam Basin, China: Implication From Thermocompression Experiment

The potential of microbial carbonate rocks as hydrocarbon source rocks still remains uncertain. To evaluate the hydrocarbon generation and expulsion capability of microbial carbonate rocks, stromatolite obtained from the Xiaganchaigou formation of the western Qaidam Basin has been used for thermocompression experiments to simulate hydrocarbon generation and expulsion at temperature of 280 to 380°C. The results show that the generation potentials of total oil, residual oil, expelled oil, and hydrocarbon gases for stromatolite are 143.39 to 379.99 mg/g total organic carbon (TOC), 47.08 to 223.92 mg/gTOC, 71.12 to 170.81 mg/gTOC, and 6.60 to 101.74 mg/gTOC, respectively. A three-stage model of hydrocarbon generation and expulsion evolution has been constructed for stromatolite. The results show that the first stage is characterized by relatively slow oil generation with associated hydrocarbon gases, having limited capability of oil expulsion in the temperature range of 280 to 360°C (0.50% ≤ Ro ≤ 0.70%). The second stage is characterized by rapid oil generation with associated hydrocarbon gases, having incremental capability of oil expulsion in the temperature range of 320 to 360°C (0.70% ≤ Ro ≤ 1.15%). The third stage is characterized by hydrocarbon gas generation with associated oil, having efficient oil expulsion capability in the temperature range of 360 to 380°C (1.15% ≤ Ro ≤ 1.45%). The experimental data of argillaceous dolostone, gray mudstone, and marlstone, which were reported with the same hydrocarbon generation experimental method, was compared with the data for stromatolite. Compared with traditional source rocks, the oil generation potential of stromatolite is less than that of argillaceous dolostone and gray mudstone but greater than that that of marlstone in the same amount of organic carbon. Especially, the hydrocarbon gas generation potential of stromatolite is approximately double than that of traditional source rocks. Therefore, the experiments indicate that the microbial carbonate rocks in the western Qaidam Basin could be effective source rocks.

Multi-stage hydrocarbon migration and accumulation of Permian petroleum system in the Zaysan Basin, NE Kazakhstan

The Zaysan Basin in northeastern Kazakhstan is a petroliferous basin that closely correlates with the Central Asian Orogenic Belt (CAOB). The basin is characterized by multi-stage hydrocarbon migration and accumulation, while the details are poorly understood. Hydrocarbon accumulation processes were investigated within the constraints of the regional tectonic evolution and the timing of trap formation. Along with assessment of geochemical characteristics, hydrocarbon generation and accumulation models were established. Light blue-green fluorescence colours of intergranular oil were identified for the deep Permian and Jurassic reservoirs, but they were absent within the shallow Paleogene Severozagsan reservoirs. Geochemical results indicate that source rocks for the oils were deposited in anoxic brackish-saline environments, and mainly contain type I and type II kerogen. Oil and extracted bitumen from the Permian and Jurassic reservoirs originate from the same Permian source rocks and show low maturity. The biodegradation of oils within the Permian and Jurassic reservoirs, however, indicates different alteration processes. Paleogene gas is the biodegradation product of the oils. In the study area, two stages of oil charge and one stage of gas charge were identified. The first oil charge began about 207 Ma (Late Triassic) when the source rock entered the oil window. The oil migrated into the Permian reservoirs and subsequently underwent biodegradation. The second oil charge took place about 70–100 Ma and was controlled by Late Cretaceous cooling and exhumation events. Oil in the Jurassic reservoir originated by oil remigration from the Permian reservoir. The gas charge occurred during the Late Cenozoic. The gas was mainly the biodegradation of oils and accumulated in Paleogene reservoirs.

Multi-Stage Hydrocarbon Generation Model of Saline Lacustrine Source Rocks: Insights from Hydrous Pyrolysis Based on Clay Mineral-Organic Matter Interactions

Multi-Stage Hydrocarbon Generation Model of Saline Lacustrine Source Rocks: Insights from Hydrous Pyrolysis Based on Clay Mineral-Organic Matter Interactions

Hydrocarbon Generation Characteristics of Source Rocks from Different Saline Environments in the Dongpu Depression, Bohai Bay Basin, China

AbstractThe Dongpu Depression is a secondary salt‐bearing tectonic unit in the Bohai Bay Basin, eastern China. The depositional environment of this depression regarding its Paleogene strata is clearly different in plane, including the saltwater environment (SE) in the north, the freshwater environment (FE) in the south and the brackish water environment (BE) in the middle. The result of oil and gas exploration in the Dongpu Depression shows that more than 90% of the proven oil reserves are distributed in the northern saltwater environment. Previous studies indicate that the organic geochemistry characteristics and the hydrocarbon generation capacity of the source rocks are very clearly diverse under different environments, which results in the significant differences in the proved reserves between the north and the south. In order to further explore the differences in the hydrocarbon generation capacity of the source rocks under distinct depositional environments and the mechanism of their occurrence, three samples from different depositional environments (W18‐5 for SE, H7‐18 for BE, CH9 for FE) were used for confined gold tube pyrolysis experiments. The results show that the CH4 yields of W18‐5, H7‐18 and CH9 increase with increasing temperature, the maximum yields being 405.62 mg/g TOC, 388.56 mg/g TOC and 367.89 mg/g TOC, respectively. The liquid hydrocarbon yields of W18‐5, H7‐18 and CH9 firstly increase with increasing temperature and then decrease after the critical temperatures. The maximum yields of C6–14 are 149.54 mg/g TOC, 140.18 mg/g TOC and 116.94 mg/g TOC, the maximum yields of C14+ being 852.4 mg/g TOC, 652.6 mg/g TOC and 596.41mg/g TOC, respectively for W18‐5, H7‐18 and CH9. To summarize, the order of hydrocarbon potential from high to low is W18‐5, H7‐18 and CH9. On this basis, through analyzing the influencing factors of hydrocarbon differences, this paper reveals that the saltwater environment is characterized by 4 factors: higher salinity, halophilic algae, high paleo‐productivity and a strongly reducing environment, which are beneficial to the enrichment of organic matter and lead to the formation of high levels of sapropelite and exinite. According to the variation of oil and gas components in the pyrolysis experiments, the hydrocarbon generation process is divided into three stages: kerogen cracking, oil cracking and C2–5 cracking. Combined with hydrocarbon generation characteristics and stages, the evolutionary model of hydrocarbon generation for source rocks under different environments is established.

Source Rock Evaluation and Hydrocarbon Generation Model of a Permian Alkaline Lakes—A Case Study of the Fengcheng Formation in the Mahu Sag, Junggar Basin

The alkaline lake source rocks of the Fengcheng Formation are developed in the Mahu Sag of the Junggar Basin. Different from traditional continental fresh water and saltwater lake source rocks, alkaline lake source rocks lack targeted evaluation criteria, and it is unknown whether their hydrocarbon generation models are consistent with traditional models. Therefore, in the present study, evaluation standards and hydrocarbon generation models of alkaline lake source rocks are discussed based on geological and organic geochemical data and a systematic summary of the geochemical characteristics of the Fengcheng Formation source rocks. The Fengcheng Formation source rocks are mainly diamictite with mixed argillaceous rock and dolomite; most total organic carbon (TOC) values range from 0.2–1.4%; and the kerogen is primarily oil-prone type II, reaching low- to high-maturity stages. Based on the types of organic matter in source rocks and the relationships between organic matter abundance parameters, the evaluation standard of alkaline lake source rocks is proposed. The Fengcheng Formation is mainly composed of good to excellent source rocks (55.5%) with high hydrocarbon generation potential. The single-peak hydrocarbon generation model of the Fengcheng Formation is similar to that of traditional freshwater or saltwater lakes, with a high hydrocarbon generation rate, two to five times that of the traditional model; its main particularity is in the formation of naphthenic crude oil from the kerogen of bacteria and algae. A new understanding of the hydrocarbon generation potential and model of alkaline lake source rocks in the Fengcheng Formation can provide support for tight oil and shale oil exploration in the Mahu Sag.

Thermal maturity and hydrocarbon generation modelling for the Lower Rudeis source rock and petroleum system analysis in Garra area, Gulf of Suez Rift, Egypt

The Lower Rudeis Formation is an active source rock in the Garra region, which is characterized by a good hydrocarbon generative potential. The Lower Rudeis source rock reached the early mature stage in the Middle Miocene Langhian (15.5 Ma) and went through the mid mature stage at 0.9 Ma.. It was generated from a clay source rock, deposited under sub-oxic to oxic conditions and derived from an organic material composed mainly of terrestrial organic material. The Lower Rudeis source rock went through two phases of hydrocarbon generation and expulsion. The first phase occurred from 6.0 Ma to 3.4 Ma, while the second phase started at 3.4 Ma and continued until the present time, with a transformation ratio estimated of 42%. The oil expulsion increased to 16 mg/gTOC and gas expulsion to 40 mg/gTOC, thus the expelled hydrocarbons are mainly composed of mainly gas and some oil. In contrast to the southern province, the Garra region has a single petroleum system which is charged by pre-Miocene and Miocene, Lowers Rudeis, source rocks along vertical and lateral migration routes and the main Kareem-Rudeis reservoirs that were sealed by the Belayim evaporite. The current study is based on the geological, geochemical, biomarker and stable carbon isotope data, which were analyzed, interpreted and presented as burial, thermal and maturity models using the petroleum systems and basin analysis program (BasinMod software).

Thermal maturation, hydrocarbon generation and expulsion modeling of the source rocks in the Baiyun Sag, Pearl River Mouth Basin, South China Sea

The Baiyun Sag plays a role as the most important, largest deepwater target in petroleum exploration across the northern side of the South China Sea. Three sets of primary source rocks are developed in the Baiyun Sag: early Eocene middle-deep lacustrine source rock (EMD), late Eocene-early Oligocene inshore-shallow lacustrine source rock (OIS), and late Oligocene transitional source rock (LOT). A quantitative 3D model of the Baiyun Sag was constructed by using a stratigraphic framework based on 3D seismic interpretations and lithology well logging data of 66 wells. The geothermal parameters of the 3D model were determined and calibrated based on the measurements of seafloor temperature, formation temperature, and vitrinite reflectance from the wells. The source rock property parameters of the EMD, OIS, and LOT in the 3D model were set according to the results of the total organic carbon test and Rock-Eval pyrolysis analysis of the well samples. The thermal maturation, hydrocarbon generation and expulsion histories of the EMD, OIS, and LOT were reconstructed to study how the evolution of source rocks influenced the current oil accumulation. Modeling results show significant differences among evolutions of the EMD, OIS, and LOT in both vertical and plane directions. The majority of the EMD reached the threshold of hydrocarbon generation (Ro = 0.5%) at about 45 Ma and kept in the oil window (Ro = 0.5–1.3%) from 45 to 15 Ma. The majority of the OIS and LOT was not capable of generating hydrocarbon until 35 Ma and 20 Ma, respectively, and have not entirely passed the oil window at present. The EMD, OIS, and LOT in the south and east region of the Baiyun Sag matured faster than the ones in the north and west region. The total oil generation quantities of the EMD, OIS, and LOT are 3772.51 × 108 t, 585.93 × 108 t, and 517.83 × 108 t, respectively; and the total oil expulsion quantities of the EMD, OIS, and LOT are 1246.04 × 108 t, 47.85 × 108 t, and 18.49 × 108 t, respectively. The oil generated and expelled in the Sub-sag B1 accounts for 82% of the total oil generation and 96% of the total oil expulsion in the study area, respectively. However, only 4% of the oil originated from the EMD, and 3% of the oil generated in the Sub-sag B1, was expelled after the deposition of primary reservoir rocks (23.8–0 Ma). On the contrary, 69% of the oil expulsion of the OIS and all of the oil expelled from the LOT took place after 23.8 Ma. The EMD in the Sub-sag B2, the OIS in the Sub-sag B1 and B4, and the LOT in the Sub-sag B1 are favorable to current oil accumulation due to their high proportions and large quantities of the oil expulsion after the deposition of primary reservoir rocks.

Modeling Hydrocarbon Generation of Deeply Buried Type Ⅲ Kerogen: A Study on Gas and Oil Potential of Lishui Sag, East China Sea Shelf Basin

The hydrocarbon generation model and hydrocarbon potential are investigated in the Lishui Sag, based on gold-tube pyrolysis experiments of deeply buried type Ⅲ kerogen. From this, we discuss the classification of kerogen types of source rocks with mixed organic matter sources. The hydrocarbon generated from the source rocks of the Lingfeng Formation and Yueguifeng Formation is dominated by natural gases with little oil in the West subsag, and the hydrocarbon generation model of the Lingfeng Formation is similar to that of Yueguifeng Formation, but the gas potential of Lingfeng Formation is higher than that of Yueguifeng Formation. The hydrocarbon potential of the Yueguifeng Formation in the East subsag is much higher than the West subsag, and it has considerable oil potential. Macerals diversity of source rocks is responsible for the difference of hydrocarbon generation characteristics for type Ⅲ kerogen in the Lishui Sag. It is not rigorous to evaluate the hydrocarbon potential of kerogen only based on pyrolysis parameters. Application of kerogen type index (KTI) can improve the accuracy of the classification of kerogen types with mixed organic matter sources. According to the classical kerogen classification template, the selected samples belong to type III kerogen. In this article, the selected samples were further subdivided into type III and type II/III based on the KTI value. Type III kerogen (0.5 ≤ KTI &amp;lt; 1.5) mainly produces gas, and type II/III kerogen (1.5 ≤ KTI &amp;lt; 5) mainly produces gas, but its oil potential is higher than that of type III.

Quantitative hydrocarbon generation and charge risk assessment in the NW Persian Gulf: A 3D basin modeling approach

Three-dimensional basin and petroleum system modeling was conducted to investigate hydrocarbon generation, migration, and accumulation in the Iranian sector of the NW Persian Gulf. The presented basin model was developed based on seismic and well data covering an area of about 20,000 km2 bounded by the base-Triassic and the present-day sea-floor. Hydrocarbon generation modeling uses newly developed discrete activation energy distributions for Albian source rocks. This study provides a key to the understanding of the Cretaceous-Tertiary petroleum systems and hints to the possible causes of exploration failure at few places. This can reduce future charge-related exploration risk in the region especially for the stratigraphic and combined structural-stratigraphic traps.The modeling results indicate the major role of the Zagros orogeny on controlling burial and thermal evolution as well as hydrocarbon migration and accumulation. The Zagros orogeny and following reactivation of the deep-seated faults resulted in the creation of two depressions in the region hosting the main hydrocarbon generation kitchens for the Cretaceous source rocks. The direction of hydrocarbon migration and accumulation is mainly controlled by the kinematics of the structural highs. During the Late Cretaceous to Miocene, southward deepening of the basin directed most hydrocarbon migration towards the northern part. The latest phase of the tectonic activity during the Miocene and tilting and deepening of the horizons towards the NE resulted in changing the direction of hydrocarbon migration towards the southern part. The results show that the rather young petroleum accumulations related to the Late Miocene to recent Zagros movements can hardly been understood without considering filling of former structures and re-migration due to tectonic restructuring.

Geochemical characteristics, genetic types, and source of natural gas in the Sinian Dengying Formation, Sichuan Basin, China

The Sinian Dengying Formation is a key target for deep oil and gas exploration in the Sichuan Basin, China. Natural gas was mainly distributed in the Ziyang–Weiyuan area (ZWA) and the Gaoshiti–Moxi area (GMA). At present, the genetic types and sources of natural gas are still unclear and controversial. The chemical composition, stable carbon isotopes, and biomarkers were used to analyze geochemical characteristics, genetic types, and gas–source relations. The results showed that the composition and content of hydrocarbon gas in the ZWA and GMA were similar. Natural gas was a typical dry gas with an average dry coefficient (C1/C1+) of 0.9991, which reflected higher methane (CH4) content and lower heavy hydrocarbon gas (C2+) content. For nonhydrocarbon gas, CO2 (0.01%–26.34%), N2 (0.03%–24.95%), H2S (0.10%–3.19%), and He (0.01%–0.37%) were mainly distributed. Compared with the GMA, the ZWA was characterized by higher N2 content and lower CO2 content. Although the carbon isotopes had not been reversed, the values of δ13C2–δ13C1 were different between the ZWA and GMA, with the GMA having the higher value. The assemblage relation between the natural gas composition and carbon isotopes indicated that the natural gas type was dominated by oil-cracking gas. Mud-shale in the high maturity stage of thermal evolution greatly influenced on the content of N2 and He. H2S mainly belonged to thermochemical sulfate reduction (TSR), and most of CO2 was formed by deep carbonate metamorphism and TSR. The gas–source relation showed that natural gas in the ZWA was derived from the Cambrian Qiongzhusi Formation and that the gas in the GMA mainly originated from the Sinian Dengying Formation and the Cambrian Qiongzhusi Formation. The established hydrocarbon generation model indicated that the Sinian Dengying Formation is potentially gas-rich.

Hydrocarbon Generation Kinetics of the Gas-Prone Kerogens in the Central Uplift of the South Yellow Sea Basin

A kinetic hydrocarbon generation model is critical to the evaluation of hydrocarbon prospects, which can promote the offshore oil-gas exploration in the South Yellow Sea Basin (SYSB). To ascertain ...

Controls on overpressure evolution during the gravitational collapse of the Amazon deep-sea fan

The Amazon Fan provides a natural laboratory to study the generation of overpressure, due to rapid late Cenozoic burial that has resulted in gravitational collapse above shale detachments. Here we examine collapse systems for the first time using the techniques of petroleum systems analysis. We propose an integrated methodology based on numerical modeling constrained by the structural restoration of a seismic profile across the southwestern fan. The results provide information on the evolution of pore pressure and temperature and their implications for the operation of the detachment and overlying extensional and compressional faults during the deposition of up to 6 km of sediment over the last 8 Ma. The modelled thermal history implies that fluid release by smectite-to-illite transformation has taken place within the thickening sedimentary succession, but has not significantly contributed to pore pressures along the detachment. Modeling of hydrocarbon generation and migration from source rocks beneath the fan indicates gas accumulated in successions at depths of 102–103 m beneath the detachment without influencing pore pressures along it. In contrast, model results indicate that overpressures have varied in response to disequilibrium compaction. Fault activity within the collapse system took place during phases of higher sedimentation rates, and ceased from 5.5 to 3.7 Ma when sediment supply to the SE fan decreased. From 2 Ma, renewed sediment flux and shelf-slope progradation led to a basinward migration both of overpressure along the detachment and of fault activity above it. We conclude that gravity tectonics in the Amazon Fan over the last 8 Ma have been mainly controlled by overpressures due to disequilibrium compaction, with secondary contributions from clay mineral transformation. Present-day pressure conditions show that the southeastern Amazon Fan is not at equilibrium and gravity driven deformation could occur at any time.

1D modelling of hydrocarbon generation from the Istebna Beds in borehole profile from the Silesian Unit

1D modelling of hydrocarbon generation from the Istebna Beds in borehole profile from the Silesian Unit