Hydrocarbon Generation History Research Articles

Tectono–Thermal Evolution, Hydrocarbon Filling and Accumulation Phases of the Hari Sag, in the Yingen–Ejinaqi Basin, Inner Mongolia, Northern China

This work restored the erosion thickness of the top surface of each Cretaceous formations penetrated by the typical well in the Hari sag, and simulated the subsidence burial history of this well with software BasinMod. It is firstly pointed out that the tectonic subsidence evolution of the Hari sag since the Cretaceous can be divided into four phases: initial subsidence phase, rapid subsidence phase, uplift and erosion phase, and stable slow subsidence phase. A detailed reconstruction of the tectono–thermal evolution and hydrocarbon generation histories of typical well was undertaken using the EASY Ro% model, which is constrained by vitrinite reflectance (Ro) and homogenization temperatures of fluid inclusions. In the rapid subsidence phase, the peak period of hydrocarbon generation was reached at c.a. 105.59 Ma with the increasing thermal evolution degree. A concomitant rapid increase in paleotemperatures occurred and reached a maximum geothermal gradient of about 43–45°C/km. The main hydrocarbon generation period ensued around 105.59–80.00 Ma and the greatest buried depth of the Hari sag was reached at c.a. 80.00 Ma, when the maximum paleo–temperature was over 180°C. Subsequently, the sag entered an uplift and erosion phase followed by a stable slow subsidence phase during which the temperature gradient, thermal evolution, and hydrocarbon generation decreased gradually. The hydrocarbon accumulation period was discussed based on homogenization temperatures of inclusions and it is believed that two periods of rapid hydrocarbon accumulation events occurred during the Cretaceous rapid subsidence phase. The first accumulation period observed in the Bayingebi Formation (K1b) occurred primarily around 105.59–103.50 Ma with temperatures of 125–150°C. The second accumulation period observed in the Suhongtu Formation (K1s) occurred primarily around 84.00–80.00 Ma with temperatures of 120–130°C. The second is the major accumulation period, and the accumulation mainly occurred in the Late Cretaceous. The hydrocarbon accumulation process was comprehensively controlled by tectono–thermal evolution and hydrocarbon generation history. During the rapid subsidence phase, the paleo temperature and geothermal gradient increased rapidly and resulted in increasing thermal evolution extending into the peak period of hydrocarbon generation, which is the key reason for hydrocarbon filling and accumulation.

Hydrocarbon Generation by the Rocks of the Bremer Formation in Adjacent Areas of the Nonvolcanic Passive Margins of Australia and Antarctica

This paper analyzes differences in the history of hydrocarbon (HC) generation by the rocks of the Bremer 1–6 formations in adjacent areas of the nonvolcanic passive continental margins of Australia and Antarctica. The problem is examined by the example of the numerical reconstruction of the burial and thermal history of two sedimentary sequences of approximately equal thicknesses: the section of well 19–2012 in the Bremer sub-basin of the southwestern margin of Australia and the section of pseudowell 2 in the adjacent area of the passive margin of Antarctica on seismic profile 5909 across the Mawson Sea. The asymmetry of Gondwana rifting in the region of interest resulted in asymmetry in the tectonic structure and development of adjacent areas of passive margins and, as a consequence, significantly different histories of HC generation by the rocks of the Bremer 1–6 formations in these areas. Modeling indicates that the rocks of the Bremer 1 and 2 formations are mainly gas-prone in the Bremer basin and can become oil-prone in the Mawson Sea region of the Antarctic margin. In contrast, according to modeling, the rocks of the Bremer 4 and 5 formations generate a minor amount of HC in the well 19–2012 area of the Bremer sub-basin and considerable amounts of heavy and light oil in the adjacent Antarctic margin area at pseudowell 2 in the Mawson Sea.

Thermal evolution and hydrocarbon generation histories of black shale in Lower Carboniferous Baizuo Formation, Southern Guizhou Depression

Thermal evolution and hydrocarbon generation histories of black shale in Lower Carboniferous Baizuo Formation, Southern Guizhou Depression

Quantitative Identification of the Annealing Degree of Apatite Fission Tracks Using Terahertz Time Domain Spectroscopy (THz-TDS).

Apatite fission-track (AFT) analysis, a widely used low-temperature thermochronology method, can provide details of the hydrocarbon generation history of source rocks for use in hydrocarbon exploration. The AFT method is based on the annealing behavior of fission tracks generated by 238U fission in apatite particles during geological history. Due to the cumbersome experimental steps and high expense, it is imperative to find an efficient and inexpensive technique to determinate the annealing degree of AFT. In this study, on the basis of the ellipsoid configuration of tracks, the track volume fraction model (TVFM) is established and the fission-track volume index is proposed. Furthermore, terahertz time domain spectroscopy (THz-TDS) is used for the first time to identify the variation of the AFT annealing degree of Durango apatite particles heated at 20, 275, 300, 325, 450, and 500 ℃ for 10 h. The THz absorbance of the sample increases with the degree of annealing. In addition, the THz absorption index is exponentially related to annealing temperature and can be used to characterize the fission-track volume index. Terahertz time domain spectroscopy can be an ancillary technique for AFT thermochronological research. More work is urgently needed to extrapolate experimental data to geological conditions.

Fluid geochemistry of the Jurassic Ahe Formation and implications for reservoir formation in the Dibei area, Tarim Basin, northwest China

The condensate gas reservoirs of the Jurassic Ahe Formation in the Dibei area of the Tarim Basin, northwest China are typical tight sandstone gas reservoirs and contain abundant resources. However, the hydrocarbon sources and reservoir accumulation mechanism remain debated. Here the distribution and geochemistry of fluids in the Ahe gas reservoirs are used to investigate the formation of the hydrocarbon reservoirs, including the history of hydrocarbon generation, trap development, and reservoir evolution. Carbon isotopic analyses show that the oil and natural gas of the Ahe Formation originated from different sources. The natural gas was derived from Jurassic coal measure source rocks, whereas the oil has mixed sources of Lower Triassic lacustrine source rocks and minor amounts of coal-derived oil from Jurassic coal measure source rocks. The geochemistry of light hydrocarbon components and n-alkanes shows that the early accumulated oil was later altered by infilling gas due to gas washing. Consequently, n-alkanes in the oil are scarce, whereas naphthenic and aromatic hydrocarbons with the same carbon numbers are relatively abundant. The fluids in the Ahe Formation gas reservoirs have an unusual distribution, where oil is distributed above gas and water is locally produced from the middle of some gas reservoirs. The geochemical characteristics of the fluids show that this anomalous distribution was closely related to the dynamic accumulation of oil and gas. The period of reservoir densification occurred between the two stages of oil and gas accumulation, which led to the early accumulated oil and part of the residual formation water being trapped in the tight reservoir. After later gas filling into the reservoir, the fluids could not undergo gravity differentiation, which accounts for the anomalous distribution of fluids in the Ahe Formation.

Evaluation of hydrocarbons generated from the Permo-Carboniferous source rocks in Huanghua Depression of the Bohai Bay Basin, China

The Huanghua Depression is located in the north-centre of Bohai Bay Basin, which is a rift basin developed in the Mesozoic over the basement of the Huabei Platform, China. Permo-Carboniferous source rocks were formed in the Huanghua Depression, which has experienced multiple complicated tectonic alterations with inhomogeneous uplift, deformation, buried depth and magma effect. As a result, the hydrocarbon generation evolution of Permo-Carboniferous source rocks was characterized by discontinuity and grading. On the basis of a detailed study on tectonic-burial history, the paper worked on the burial history, heating history and hydrocarbon generation history of Permo-Carboniferous source rocks in the Huanghua Depression combined with apatite fission track testing and fluid inclusion analyses using the EASY% Ro numerical simulation. The results revealed that their maturity evolved in stages with multiple hydrocarbon generations. In this paper, we clarified the tectonic episode, the strength of hydrocarbon generation and the time–spatial distribution of hydrocarbon regeneration. Finally, an important conclusion was made that the hydrocarbon regeneration of Permo-Carboniferous source rocks occurred in the Late Cenozoic and the subordinate depressions were brought forward as advantage zones for the depth exploration of Permo-Carboniferous oil and gas in the middle-northern part of the Huanghua Depression, Bohai Bay Basin, China.

Thermal history and organic matter maturation modeling of the East Siberian Sea sedimentary basins

2D and 3D thermal history and organic matter maturity modeling of East Siberian Sea sedimentary basinsare performed in this study. We present cross-sections with temperature and vitrinite reflectance distribution along composite seismic line, temperature maps ofmain horizons fordifferent time stages. Vitrinite reflectance maps of source rocks fordifferent time stages and transformation ratio maps of source rocks for present time are also presented. Maturation history and possibilities of hydrocarbon generation were analyzed using modeling results.

Simulation of shale gas generation by using different experimental systems: A case study from Chang7 shale in the Ordos Basin

In this study, open system and closed system laboratory pyrolysis are conducted on a low maturity shale sample from Yanchang Formation of the Ordos Basin. The kinetics parameters in different experimental systems were calculated and extrapolated to geological conditions to predict the yield of hydrocarbon gases and the hydrocarbon generation history. In addition, the amount of hydrocarbon gases expelled during generation was estimated by using hydrocarbon gas generation kinetics extrapolation and the residual gas measurement of the shale. Moreover, the desorbed gas in 98 shale core samples from 4 drilling wells were measured and the ratio of desorbed hydrocarbon gases to generated hydrocarbon gases was calculated. The yield and transformation ratio of methane (C1) in the study area ranged from 22.80 to 36.52 ml/g·TOC and 0.07 to 0.31, respectively. The yield and transformation ratio of hydrocarbon gases (C1-C5) in the study area ranged from 36.13 to 59.28 ml/g·TOC and 0.12 to 0.34, respectively. During the generation process, shale gas was expelled in quantities ranging from 4.68 to 27.83 ml/g·TOC. The average ratios of desorbed hydrocarbon gases to generated hydrocarbon gases in 98 shale samples ranged from 33.78% to 55.79%; however, the ratios of samples for 4 different drilling wells were different, suggesting different adsorption capacities in shales from different parts of the southeastern Ordos Basin.

The evolutionary history of methane adsorption capacity with reference to deep Carboniferous-Permian coal seams in the Jiyang Sub-basin: Combined implementation of basin modeling and adsorption isotherm experiments

Carboniferous-Permian (C-P) coal seams experienced multiple burial and uplift events, which result in complex gas adsorption and desorption processes. Therefore, the understanding of the adsorption history and its dominant factors contribute to determining present-day coalbed methane (CBM) storage and enhance the development of deep CBM. In this paper, we first reconstructed the burial history using the basin model and synchronously conducted the isothermal adsorption experiment. Then an adsorption model was achieved from regression analysis about Langmuir parameters, and therefore, the adsorption history was rebuilt, accompanied by temperature, pressure, and maturity. Lastly, incorporated with the hydrocarbon generation history and adsorption history, we divided the actual adsorbed stages and further analyzed the dominant factors controlling the actual adsorption amount. The results indicate that: (1) based on the adsorption model calculated using regression analysis, a real critical depth of adsorption capacity (approximately 2000 m) is obtained; (2) coal-bearing sequences experience three temperature, pressure, and hydrocarbon generation processes, and the Himalayan epoch is the main stage for producing coal-derived gas; (3) the actual adsorption history contains a maximum depth stage (250–208 Ma), reburial stage (208–110 Ma), re-uplift stage (110–50 Ma), and present stage (50 Ma–present); (4) the critical event (208 Ma) represents that generating the amount of gas is equal to the adsorption capacity in the actual adsorbed amount, and before and after the event, the dominant factors controlling the actual adsorbed amount are maturity and temperature, respectively.

Differences in formation process of tight sandstone gas reservoirs in different substructures in Changling Fault Depression, Songliao Basin, NE China

Abstract The tight sands reservoirs in the Lower Cretaceous Denglouku Formation in Changling Fault Depression of Songliao Basin, NE China were taken as study object. The burial history, thermal evolution history and hydrocarbon generation history of source rock, accumulation stage and porosity evolution history of typical tight sandstone reservoirs in the central deep depression belt, east slope belt and east structural belt were examined by the dissection based on the fundamental features of tight sandstone gas reservoirs, to find out the differences in their formation process, the coupling relationship between source and reservoir of different substructures, then the favorable exploration areas can be confirmed. The east structural belt has the best source rocks and reservoirs, where the Denglouku Formation tight sandstone formed reservoirs earliest when the reservoirs were not tightened yet with features of one stage accumulation. The sandstone of the Denglouku Formation in the east slope belt formed reservoirs secondly and shows one stage accumulation but two charging peaks, the first charging peak occurred when the reservoirs were not tightened, the second charging peak occurred when the sandstone was tightened already. The sandstone of the Denglouku Formation in central deep depression belt formed reservoir the latest when the reservoirs were densified already with the features of one stage accumulation. The study shows that the east structural belt has the best coupling relationship between source rocks and reservoirs, and is the most favorable exploration area for tight gas in the Changling Fault Depression.

Main factors for large accumulations of natural gas in the marine carbonate strata of the Eastern Sichuan Basin, China

The natural gas accumulation zone, where the marine carbonate rock strata are developed, was formed in the eastern Sichuan Basin under the influence of several main tectonic movements (Caledonian Movement, Indosinian Movement, Yanshanian Movement, and Himalayan Movement). Most natural gas reservoirs exhibit the structural-stratigraphic traps together with multistage accumulation, late-stage adjustment and reformation, et cetera. The natural gas accumulation zone (or so-called gas reservoir groups) is controlled by the following main factors: multi-sourced and multi-formed hydrocarbons for marine source rocks (i.e. Lower Silurian Longmaxi Formation, Lower Permian, Upper Permian Longtan Formation), paleo-uplift, paleoslope, and the hinge belt controlled by the steep dip structures, namely the Lower and Middle Triassic high-quality gypsum. Three sets of high-quality source rocks (i.e. S1l, P1, P2l) account for the abundant hydrocarbon supply for natural gas accumulation in the eastern Sichuan area, especially in the destructed oil reservoir formed earlier. The said destructed oil reservoir not only provides the preservation space for natural gas reservoir that will take place later, but it also provides the hydrocarbon source for thermal cracking of hydrocarbons and thermochemical sulfate reduction (TSR). Although the gas reservoirs in the eastern part of the Sichuan Basin experienced multi-stage adjustment and reformation at later times, the thick and high-quality gypsum as well as the mudstone, as available caprocks, have offered a good preservation condition for the underlying gas reservoirs. The paleohighs (e.g. Luzhou paleohigh and Kaijiang paleohigh), the Permian platform margin slope, and the structurally transformed slope under the function of the steep dip anticline in the eastern Sichuan not only form the high-quality carbonate reservoir, but they also became favorable for oil and gas accumulation. The difference in hydrocarbon generation history of the source rock and multistage accumulation of hydrocarbons in the eastern part of the Sichuan Basin caused the diversity in the location of the gas reservoirs, where the gas reservoirs with low H2S contents are distributed in the eastern Sichuan Basin (e.g. Jiannan gas field), while the gas reservoirs with high H2S content are located in the northeastern Sichuan Basin (e.g. Puguang gas field).

Inversion of source rock hydrocarbon generation kinetics from Rock-Eval data

Basin and petroleum system modeling requires source rock kinetics as input for the reconstruction of hydrocarbon generation history. For less well-studied petroleum systems, there may be little information on petroleum generation kinetic parameters publically available; thus, an analog of representative source rock kinetics must be chosen from available kinetics databases. Recent studies suggest that source rock kinetics may vary considerably even when they contain the same type of kerogen. Thus, kinetic parameters from analog basins/source rocks may lead to erroneous results in petroleum generation history reconstruction. Rock-Eval data contain information about source rock kinetics, and can be used to improve the kinetic model in petroleum system modeling. However, the kinetic information in Rock-Eval data is not in the form of activation energies and frequency factors required to solve the temperature dependency of reaction rate in the Arrhenius equation. This article proposes a kinetic inversion method so that the analogous kinetic model chosen by the user can be improved based on Rock-Eval data of the targeted source rock. We demonstrate the method using a synthetic dataset in a case study for method validation and its application to real source rock evaluation for examples from the Devonian Duvernay Shale in the Western Canada Sedimentary Basin (WCSB).

Systematic Division of Coalbed Methane-Enriched Units

Division of coalbed methane (CBM)-enriched units primarily depends on the analysis of the main controlling factors of CBM occurrence. The main controlling factors analyzed in this article are sedimentary sequences related to the forming and alteration of CBM, tectonic movement, and burial and hydrocarbon-generation histories. The parameters were measured for independent quantities such as CBM content, gradient, coefficient of extraction difficulty and geological structure complexity. Correlation analysis was conducted between the measured parameters of CBM-bearing systems and the main controlling factors. When the controlling factors are sedimentary sequences and the sedimentary systems tract, the division of CBM-enriched units is based on the coal-forming environment, coal mass distribution and coal characteristics. When the controlling factor is the tectonic matching between the orefield, mining area and mining wells, the division of CBM-enriched units is based on tectonic movement. When burial and hydrocarbon-generation histories are the controlling factors, the division of CBM-enriched units is based on metamorphic traits.

Geochemical characteristics of crude oil from a tight oil reservoir in the Lucaogou Formation, Jimusar sag, Junggar Basin

Jimusar sag, which lies in the Junggar Basin, is an important tight oil study area in China. However, the properties and origin of the crude oil and the geochemical characteristics of the tight oil from the Lucaogou Formation have not yet been studied. In the present study, 23 crude oil samples from the Lucaogou Formation were collected for analysis, including physical properties (density and viscosity), bulk composition, saturated hydrocarbon gas chromatography–mass spectrometry, and calculation of various biomarker parameters. Source rock evaluation and porosity permeability analysis were applied to the mudstones and siltstones. To analyze the hydrocarbon generation history of the Lucaogou source rocks, one-dimensional basin modeling was performed. The oil-filling history was also investigated by means of basin modeling and microthermometry. Biomarkers of suitable source rocks (total organic carbon content is >1%, summation of the free and volatile hydrocarbon and remaining hydrocarbon generative potential is >6 mg HC/g rock, and vitrinite reflectance is between 0.7% and 1%) were analyzed for oil–source correlation. The results indicate that low-maturity to mature crude oils originated from the source rocks containing terrigenous organic matter, which were deposited in a saline lake. The source rocks are of mainly type II kerogen. Oil in the lower section of the Lucaogou Formation is relatively dense and viscous and has elevated nonhydrocarbon content. In addition, a higher proportion of bacteria and algae is shown to have contributed to the formation of crude oil in the lower section when compared with the upper section of the Lucaogou Formation. Oil–source correlations demonstrate that not all mudstones within the Lucaogou Formation contribute to oil accumulation. Thin section observation indicates organic macerals surround the grains of some siltstones within the porous and permeable subsections, which proves the siltstones contribute to hydrocarbon generation. Crude oils from the upper and lower sections mainly originate from thin-bedded mudstones interbedded and siltstones within the porous and permeable subsections. The mudstones over or beneath the porous and permeable subsections consist of seals and prevent the vertical movement of oil by capillary forces. Despite being thicker, mudstones between the two porous and permeable subsections make no obvious contribution to the oil accumulation because of their low permeability and distance from the porous and permeable subsections, which is consistent with the principle of near-source charging for tight oil accumulations. Lucaogou oil has been charged twice, once from 235 to 210 Ma and again from 180 to 150 Ma, coinciding with oil generation time.

Play types, geologic characteristics and exploration domains of lithological reservoirs in China

Abstract By dissecting thirty-six representative oil-gas reservoirs and analyzing accumulation conditions of giant oil and gas provinces in four prototype basins, including the Songliao Rift and Depression Basin, the Mesozoic Ordos Depression Basin, the Bohai Bay Rift and Depression Basin, the Mesozoic Junggar Depression Basin, the West Sichuan Foreland Basin and the Tarim Craton Basin, the hydrocarbon plays classification scheme of lithologic reservoirs is established and improved from the perspective of oil-gas accumulation zone and exploration target. The results reveal the accumulation characteristics and controlling factors of lithologic reservoirs including three kinds of slopes, three kinds of sag centers, three kinds of hydrocarbon accumulation assemblages and multiple genetic types. Based on the understandings on reservoir formation mechanisms and enrichment regularities of different hydrocarbon provinces, six major assessment indexes, parameter system and grading standard of lithologic plays are established, including hydrocarbon source rock condition, transportation pathway, reservoir condition, reservoir-cap assemblage, fluid property, and time-space configuration etc. Through comprehensive analysis of burial history, hydrocarbon-generation history, digenesis history, tectonic history, trap-forming history and accumulation history, plays of lithologic reservoirs are evaluated and optimized. The results show that the middle-shallow layers in the slope zones of the Songliao and Bohai Bay Basins oil-rich sags, the Mesozoic in the Ordos Basin, the Permian-Jurassic in the Junggar Basin, etc. are the major oil exploration areas in the future, with oil resources of about 42×10 8 t–67×10 8 t; the deep volcanic rocks of the Songliao Basin, the Carboniferous of the Junggar Basin, the Cambrian of the Tarim and Sichuan Basins, the Permian-Triassic reefs and shoals within the platform and on the platform margin of the Sichuan Basin are the major gas exploration areas in the future, with gas resources of about 1.5×10 12 m 3 −2.0×10 12 m 3 .

Hydrocarbon gas generation from pyrolysis of extracts and residues of low maturity solid bitumens from the Sichuan Basin, China

Two sets of pyrolysis experiments were performed on bitumen “A” (BA) and extracted organic matter (ER) from low-maturity solid bitumen at heating rates of 2°C/h and 20°C/h in confined systems (gold capsules). The main observations can be listed as follows: (1) BA and ER have high generation potential of hydrocarbons and were a significant secondary hydrocarbon source. (2) Both have similar evolutionary characteristics of hydrocarbon gas generation, and have high C1/C1–5 values than those from an Ordovician normal oil. Ea distributions of the methane generated from pyrolysis of BA and ER is far lower than that of Ordovician normal oil. (3) The evolution of stable carbon isotope values of individual hydrocarbon gases can be divided into three stages. Plots of lnC1/C2 versus lnC2/C3, δ13C1–δ13C2 versus ln(C1/C2) and δ13C2–δ13C3 versus ln(C2/C3) clearly illustrate the characteristics of hydrocarbon gases generated from BA and ER at different thermal maturity stages. (4) Basin modelling reconstructions of the hydrocarbon generation history of BA and ER in Sinian and Cambrian strata respectively indicate: Hydrocarbon gases generation from ER started in the Middle Jurassic, and ended in the Early Cretaceous with a maturity equivalent to Easy%Ro≈2.2%. The final conversion rate of C1–5 and C1 are 0.71 and 0.48, respectively. Hydrocarbon gas generation from BA started in the Early Jurassic, and ended in the Early Cretaceous with an Easy%Ro≈3.0%. The final conversion rate of C1–5 and C1 are 0.90 and 0.81, respectively.

History of hydrocarbon generation, migration and accumulation in the Fula sub-basin, Muglad Basin, Sudan: Implications of a 2D basin modeling study

The Fula sub-basin is located in the northeastern part of the Muglad Basin. A 2D petroleum systems model of the Lower Cretaceous within the northern portion of the Fula Sub-basin was illustrated by integrating geological, geophysical and geochemical data. Timing of hydrocarbon generation, migration, and accumulation in the Fula Sub-basin are predicted from the model results. Based on reservoir distributions and common petroleum system events, the Fula Sub-basin petroleum system is considered to have three subsystems.In this petroleum system, deep lacustrine mudstones and shales in the Lower Cretaceous Abu Formation were known to be very good source rocks that possess more than 2.0 wt % TOC. Deltaic and turbidite sandstones within the Abu Gabra Formation and the thick fluvial sandstones of the upper Bentiu and fan-delta sandstones within the Aradeiba Formation are good reservoir bearing intervals. The mudstone in the Darfur Group acts as the regional seal. The petroleum system is considered to be effective and significant proportions of both oil and gas in these reservoirs can be preserved. The Abu Gabra Formation is considered to have entered the oil window approximately 120 Ma ago. Late oil generation continued for approximately 55 Ma. Gas generation took place in the mid-Eocene and probably continues to present-day. The results also show that the generated hydrocarbon is mainly oil with minor gas shows. In the main kitchen area, the migration and accumulation of hydrocarbon began at about 90 Ma. Migration is shown to be associated mainly with fault patterns controlling migration direction. Some migrated hydrocarbons escaped through the faults.

MESOZOIC THERMAL EVENTS IN CENTRAL LOWER YANGTZE AREA AND IMPACTS ON HYDROCARBON GENERATION OF MARINE SOURCE ROCKS

AbstractTemperature is a key parameter of controlling hydrocarbon generation of source rocks. Elevated temperature resulted from tectonothermal events may significantly affect hydrocarbon generation. Based on geology, fission track analysis, apatite U‐Th/He and volcanic rock isotopic age data, it is found that there existed Indosinian (T3‐J2) and Yanshanian (J3‐K1) tectonothermal events in Lower Yangtze area and the sedimentary basins reached their peak heat flow at about 130∼110 Ma. The maximum heat flows obtained from thermal history reconstruction based on vitrinite reflectance are ∼94 mW·m–2 and ∼78 mW·m–2 in Jurong and Taixing areas respectively, with an increasing trend from east to west. Hydrocarbon generation history reconstruction based on the EASY%Ro model shows that the dominating gas generation periods of the Cambrian source rock are the Early Permian‐Late Triassic and the Late Triassic‐Early Cretaceous in Changzhou and Jurong areas respectively. Because of the dual effects from the foreland sediments deposited in T3‐J1–2 and the magmatism thermal event in the Early Cretaceous, the marine source rocks reached their maximum temperature at the end of Early Cretaceous. The temperature of the marine source rocks was no longer elevated owing to the decreased heat flow since the Late Cretaceous, though, in some parts of the Jurong, Taixing and Changzhou areas, subsidence occurred and burial depth increased during the K2‐E period. Therefore, the secondary hydrocarbon generation of the marine source rocks is not a widespread process in central Lower Yangtze area.

Sinian-Ordovician Hydrocarbon-source Rock Correlation and Hydrocarbon-generation Evolution in Central and Southeastern Sichuan, China

Abstract: Geology, stratigraphy, drilling, logging, biomarker studies and apatite fission tracks were used to study Sinian-Ordovician mudstone and reservoir bitumen extracted from exploration wells located in central and southeastern Sichuan. This analysis confirms the source rocks were located in a reducing sedimentary environment, with organic matter such as bacteria and algae. The bitumen found in Sinian-Ordovician reservoirs in central Sichuan and Sinian reservoirs in southeastern Sichuan were mostly derived from Cambrian mudstones. The reservoir bitumen found in Cambrian rocks in southeastern Sichuan are from a mixed Cambrian-Silurian source. The apatite fission track combined with the Easy% Ro model were used to reconstruct the hydrocarbon-generation history of Cambrian source rocks in the Dingshan 1 well in southeastern Sichuan. The comparison between the Gaoke 1 well located in central Sichuan and the Dingshan 1 well demonstrates the maturation time and oil and gas generation stage from Cambrian source rocks in southeastern Sichuan is younger than the source rocks from central Sichuan. The source rock formations underwent tectonic uplift and reburial for secondary hydrocarbon-generation. The research methods provided can assist in oil exploration of deep and old hydrocarbon-bearing strata with a multi-stage evolution and tectonically superimposed features in the Chinese Qinghai-Tibet plateau basin, or similar basins worldwide.

Overpressure compartments in the central paleo-uplift, Sichuan Basin, southwest China

The Sichuan Basin is a prime gas-producing basin in China. Besides the giant Neoproterozoic Weiyuan gas field discovered in the central paleo-uplift, an extra giant gas reservoir in the Cambrian in this area has been confirmed in recent years. Although the lower Paleozoic in the southwest (Weiyuan area) is normally pressured, it is overpressured in the central area (Moxi–Gaoshiti area). Combined with the seal distribution, five pressure systems, including three overpressure systems, can be divided based on drill-stem test, mud weight, and sonic transit time data. Overpressures appear at depth interval of 1500 to 4900 m (4921 to 16,076 ft), approximately. Benefiting from the good sealing capacity of the gypsum in the Upper and Middle Triassic, high overpressure (pressure coefficient [r] > 2.0) has been preserved in the Lower Triassic, and the Upper Triassic and Cambrian are moderately overpressured (1.3 < r < 1.7). Mechanisms for various overpressure systems are different. Abnormally high sonic transit time in the Permian indicates disequilibrium compaction overpressure. The analyses of sonic transit time–effective stress suggest that disequilibrium compaction is the primary mechanism for the overpressure in the Upper Triassic Xujiahe Formation, but the Cambrian overpressure system is predominantly associated with fluid expansion, which mainly resulted from gas generation. Furthermore, we consider that the late thermal cracking of oil to gas is a key factor for gas and overpressure preservation in old strata. The high overpressure in the Lower Triassic marine carbonate rocks was caused by oil cracking and gypsum dehydration mechanisms. Combining the origin analysis with the burial and hydrocarbon generation histories, we constructed the Cambrian pore pressure evolution model, which is characterized by roughly normal pressure before 200 Ma, overpressuring from 200 to 90 Ma, and overpressure releasing since 90 Ma.