Thermal Evolution Of Source Rocks Research Articles

Thermal Maturation Trend and Cluster Validation Using K-Means Clustering: Case Study in Salawati Basin

In the last few years, exploration activities have experienced obstacles and have not attracted much attention from researchers in Indonesia. One of the basins in Indonesia that is still interesting is Salawati Basin in West Papua, Indonesia. Several studies related to petroleum systems have been carried out in this basin, especially those that control the migration of hydrocarbon in Salawati Basin. This research was conducted on three wells located in the western of Salawati Basin to evaluate the characteristics and the maturity of the source rock, especially the Sirga Formation. This formation is penetrated by wells MM-02, MM-03, and MM-04, by using the K-Means Clustering method to validate several parameter variations of the maturity level. K-means cluster performs data from various parameters of maturity level with predefined three numbers of cluster. The thermal evolution of source rocks can alter organic matter physical and chemical properties, converting it into hydrocarbon compounds. The selected maturity parameters have good sensitivity to the determination of thermal maturity including phenanthrene (P), in addition to the MPI (methylphenanthrene index) parameter which was obtained from mass chromatograms m/z 178 and m/z 192 based on the peak area of P and methylphenanthrene (MP). Based on the appearance of the crossplot, both Radke and Kvalheim Formulas show that the maturity in studied area is divided into three main zones: peak maturity zone, early maturity zone, and outliers. This study also found that increasing thermal maturity is correlativewith the increasing depth.

Geochemical characteristics and exploration significance of ultra-deep Sinian oil and gas from Well Tashen 5, Tarim Basin, NW China

The Well Tashen 5 (TS5), drilled and completed at a vertical depth of 9017 m in the Tabei Uplift of the Tarim Basin, NW China, is the deepest well in Asia. It has been producing both oil and gas from the Sinian at a depth of 8780–8840 m, also the deepest in Asia in terms of oil discovery. In this paper, the geochemical characteristics of Sinian oil and gas from the well were investigated and compared with those of Cambrian oil and gas discovered in the same basin. The oil samples, with Pr/Ph ratio of 0.78 and a whole oil carbon isotopic value of −31.6‰, have geochemical characteristics similar to those of Ordovician oils from the No. 1 fault in the North Shuntuoguole area (also named Shunbei area) and the Middle Cambrian oil from wells Zhongshen 1 (ZS1) and Zhongshen 5 (ZS5) of Tazhong Uplift. The maturity of light hydrocarbons, diamondoids and aromatic fractions all suggest an approximate maturity of 1.5%–1.7% Ro for the samples. The (4-+3-) methyldiamantane concentration of the samples is 113.5 μg/g, indicating intense cracking with a cracking degree of about 80%, which is consistent with the high bottom hole temperature (179 °C). The Sinian gas samples are dry with a dryness coefficient of 0.97. The gas is a mixture of kerogen-cracking gas and oil-cracking gas and has Ro values ranging between 1.5% and 1.7%, and methane carbon isotopic values of −41.6‰. Based on the equivalent vitrinite reflectance (Reqv = 1.51%–1.61%) and the thermal evolution of source rocks from the Cambrian Yu'ertusi Formation of the same well, it is proposed that the Sinian oil and gas be mainly sourced from the Cambrian Yu'ertusi Formation during the Himalayan period but probably also be joined by hydrocarbon of higher maturity that migrated from other source rocks in deeper formations. The discovery of Sinian oil and gas from Well TS5 suggests that the ancient ultra-deep strata in the northern Tarim Basin have the potential for finding volatile oil or condensate reservoirs.

Comparison of Evaporite-Related Source Rocks and Implications for Petroleum Exploration: A Case Study of the Dongying Depression, Bohai Bay Basin, Eastern China

The Dongying Depression (Bohai Bay Basin, eastern China) was widely filled with evaporite (anhydrite and halite) layers during the Paleogene period, especially the middle of the fourth member of the Shahejie Formation (Es4). Most evaporite layers are interbedded with mudstone strata. The strata of Es4 are divided into three sections, referred to as the upper layers, evaporite layers, and lower layers, respectively. The analysis of elemental concentrations, elemental ratios, and Pr/Ph suggests that the lower layers were deposited in an intermittent saline lake environment within a relatively dry climate. The evaporite layers were formed in a highly saline lake environment, whereas the upper layers were formed in a brackish-saline to fresh-water environment. Organic matter (OM) abundance indices, including total organic carbon (TOC), chloroform extracts, total hydrocarbon content (HC), hydrocarbon generation potential (S1 + S2), and OM type, show that the source rock potential for petroleum generation in the upper layers is best, that in the evaporite layers is fair, and in the lower layers it is poor. Carbon isotopes (δ13C) of hydrocarbons in the evaporite and lower layers were heavier than those in the upper layers. Thermal maturity parameters show that the thermal evolution process of OM in the upper layers was faster where evaporite were present compared with evaporite-free areas, while the thermal evolution of OM in the lower layers was slower in these regions. The high thermal conductivity of evaporites may have accelerated the thermal evolution of source rocks in upper layers and allowed hydrocarbon generation at a shallower burial depth. This resulted in the earlier appearance of the petroleum generation window compared to in evaporite-free areas. Meanwhile, the thermal evolution of OM in the lower layers was restrained, and consequently the hydrocarbon generation window was widened, which implies the potential for petroleum exploration in deep strata under the evaporite sequence. This is a common phenomenon in evaporite-bearing basins, according to previous and present studies.

Differential Enrichment Regulation and Genetic Analysis of Tight Sandstone Gas Reservoir

In the deep Paleogene of graben basins in eastern China, not only the tight sandstone oil and gas resources, but also the secondary hydrocarbon generation of source rocks are universal and worth studying. In order to elucidate the laws of oil and gas accumulations in tight sandstone with different phases and explore the diversity of its genetic mechanism, Shahejie Formation in Wendong area was taken as an example in this paper to carry out further research. Firstly, the differential enrichment rules of oil and gas reservoirs are clarified from the aspects of spatial distribution, phase type and fluid properties. Secondly, the reasons for differential accumulation of oil and gas reservoirs were analyzed from multiple perspectives by using a variety of methods, such as source rock thermal evolution simulation, fault activity evaluation and reservoir porosity evolution. A large number of researches have been carried out on hydrocarbon generation and expulsion process of source rocks, paleo-temperature and paleo-pressure changes, the connectivity of skeleton sand bodies, reservoir physical property and densification process, tectonic strength and so on. The results indicate that the deep tight sandstone reservoirs of the Paleogene in the Wendong area have a quasi-continuous distribution characteristic of "planar partition and longitudinal zoning". Secondary kerogen cracking gas, crude oil cracking gas, medium light crude oil, and primary kerogen cracking gas are distributed in a semi-circular manner, from the center of Qianliyuan Sag to Wendong graben and rollover anticline belt at the high structural position. In conclusion, the two periods of hydrocarbon generation and expulsion of source rocks lead to the discontinuity of hydrocarbon accumulation process. Paleo-temperature and paleo-pressure conditions control the phase types of hydrocarbon filling. The lateral connectivity and the difference of physical properties of the skeleton sand bodies limit the distribution range of oil and gas reservoirs. The temporal and spatial availability of faults during the critical accumulation period determines the differential enrichment of oil and gas. The temporal and spatial validity of faults during the critical accumulation period determines the extent of differential enrichment of oil and gas.

Coupling Relationship between Diagenesis and Hydrocarbon Charging in Middle Permian–Lower Triassic in the Eastern Slope of Mahu Sag in Junggar Basin, Northwest China

In this study, a variety of test and analysis methods, such as cast thin sections, fluorescent thin sections, scanning electron microscopy, fluid inclusions, etc., were comprehensively used and combined with logging data, sedimentary systems, burial history and other research results, to systematically study the diagenesis characteristics of Middle Permian Lower Wuerhe formation–Lower Triassic Baikouquan formation reservoirs and their control on hydrocarbon accumulation. The coupling relationship between the hydrocarbon accumulation process and reservoir secondary pores was established. The result shows that besides the development of primary intergranular pores, the reservoir develops secondary pores, such as particle dissolution pores, cement dissolution pores and fractures. The development of secondary dissolution pores, such as particle dissolution pores, carbonate and zeolite cement dissolution pores, is mainly controlled by the range and scale of organic acids produced by the thermal evolution of source rocks. It is considered that being located in the updip direction of source rocks, being involved in the development of the unconformity surface and the faults connecting source rocks, and being involved in the development of alkaline cements (such as laumontite) are the three dominant conditions for the development of secondary dissolution pores in the study area.

Physical properties of lacustrine shale oil: A case study on the lower member of the Lucaogou Formation (Jimusaer Sag, Junggar Basin, NW China)

Shale oil generated by the lower member of the Lucaogou Formation, which was deposited under saline lacustrine conditions within the Jimusaer Sag of the Junggar Basin (NW China), is generally characterized by high density and viscosity. However, a strong spatial heterogeneity of physical properties is observed as well. In this paper, these spatial variations and their controlling mechanisms are evaluated from the perspective of the primary depositional environment, source rock thermal evolution and fractionation effects of primary migration. Based on a detailed organic petrological and geochemical characterization of the target interval within the key well JHBE, hydrous pyrolysis experiments conducted on representative source rock samples from well JHBE, as well as established methods of oil-source correlation subjected to oil samples from several regionally distributed producing shale oil wells, a predictive model of density and viscosity changes of crude oil was established. According to the findings of this study, the thermal evolution and sedimentary environment of source rocks are the main factors affecting the quality of crude oil, and the fractionation effect of primary migration has little effect. Crude oil density and viscosity at first increase up to peak oil maturity, followed by a decrease with further increasing thermal evolution of the source rock. Furthermore, if the source rocks experienced similar thermal histories, it was discovered that relatively low density and corresponding viscosity values are characteristic for crudes from source rocks which were formed in a relatively high salinity environment. In contrast, hydrocarbon generation of source rocks formed under relatively low salinity environments is slightly retarded in direct comparison, and the density and viscosity of the generated crude oil are both relatively high. This highlights that a detailed organic petrographical and geochemical evaluation of the target formation is crucial for the assessment of shale oil potential and production sweet spots in alginite-dominated lacustrine sedimentary environments.

Differential Characteristics and the Main Controlling Factors of Shale Oil Sweet Spot Reservoirs in Lucaogou Formation, Jimsar Sag, Junggar Basin

The microscopic differences in characteristics and formation mechanism of shale oil reservoirs in the upper and lower sweet spot sections of the Lucaogou Formation in the Jimsar Depression, which has been identified as a national shale oil demonstration area in China, are still unclear. In this study, the characteristics and the main controlling factors of reservoir differences in different sweet spots of Lucaogou Formation were specified based on core observation, thin-section observation, X-ray diffraction, Rock-Eval, microscopic fluorescence of hydrocarbon inclusions, and temperature measurement of saline inclusions. Results show that the Lucaogou Formation mainly develops dissolution and primary intergranular pores. The dissolution transformation leads to obvious differences between the upper and lower sweet spots. Specifically, the upper sweet spot section mainly develops primary intergranular pores and partially develops dissolution pores; the lower sweet spot section mainly develops dissolution pores, including intergranular, intragrain, and intergranular pores. Geochemical data such as inclusions indicate that hydrocarbon generation began in the Triassic, and a large number of hydrocarbons were charged in the Middle-Late Jurassic-Early Cretaceous. As the key fluid that triggers reservoir dissolution modification, it is mainly derived from organic acids generated by thermal evolution of source rocks within shale formations. The scale and quality of source rocks in the lower sweet spot are better than those in the upper sweet spot. The former has stronger hydrocarbon generation potential, which lays a foundation for the scale difference of organic acid output in the upper and lower sweet spots. At the same time, the source rocks in the lower sweet spot are more mature due to magmatic-hydrothermal upwelling. This condition accelerates the release of organic acids from source rocks, which results in the scale difference of dissolution effects in the upper and lower sweet spots.

Analysis of Controlling Effect of Temperature–Pressure Conditions on Hydrocarbon Generation of Source Rocks

The thermal evolution of source rocks and the generation of oil and gas were not isolated reactions of kerogen pyrolysis but were comprehensively controlled by many influencing factors. In this study, using Permian source rock samples from Junggar Basin, a large number of high-temperature thermal simulation experiments were carried out to study the characteristics of kerogen, for example, thermal evolution degree and hydrocarbon yield, and their influences under the open system, closed system, and different temperature–pressure conditions. The results show that the hydrocarbon yield under the low heating rate is higher than that under the high heating rate, and the hydrocarbon generation reaction can be fully carried out under the low heating rate, which is more favorable for hydrocarbon generation; with the increase in pressure in the reaction system, the dominant frequency of activation energy of hydrocarbon generation gradually decreases. In terms of the hydrocarbon yield, the oil yield is higher in a high-pressure environment, especially the yield of C6-14 component in hydrocarbons is obviously increased, while there is a relatively small difference between the C14+ components. The result of this research provides a scientific evidence for evaluating the evolution process, hydrocarbon generation kinetics, and hydrocarbon resource potential of source rocks under different temperature–pressure conditions.

Controlling factors of hydrocarbon accumulation and differential distribution in the western Qaidam Basin, Tibet Plateau

Hydrocarbon distribution in the western Qaidam Basin is complex and characterised by large reserves, dispersed distribution, local enrichment, and multi-layer accumulation. Near the Altyn Tagh Ranges, the traps are mainly oil-filled, whereas far away and near the basin centre, they are gas-filled. With hydrocarbon distribution in the western Qaidam Basin poorly understood, the tectonic evolution, source-rock thermal evolution and space–time configurations were studied using burial history, strata thickness, source-rock generation and expulsion processes, and trap formation. Mode 1 system was characterised by continuous hydrocarbon accumulation, rapid source-rock burial and trap formation early in the basin history resulting in early generation and trapping of low maturity oil and later generation of high maturity oil. Mode 2 was characterised by mid-section hydrocarbon accumulation, steady source-rock burial velocity and trap formation with the traps filled by mature oil and small amounts of gas. Mode 3 was characterised by tail hydrocarbon accumulation, rapid source-rock burial and trap formation late in basin development resulting in traps filled with high-maturity gas. In the Mesozoic–Cenozoic petroleum system, such as the Dina2 condensate gas field, hydrocarbon accumulation was earlier than in the Yingxi Shizigou oilfield belonging to the Cenozoic petroleum system, which was mainly controlled by tectonic evolution and source-rock thermal evolution. The well-matching relationships between hydrocarbon generation–expulsion time and trap formation may create a giant oilfield, an earlier formed trap, later matured source rock and good preservation leading to continuous accumulation of hydrocarbon favourable for exploration. Key points In the western Qaidam Basin, hydrocarbon differential distribution was mainly controlled by source-rock burial history, stratigraphic thickness and trap formation processes. Multi-stage hydrocarbon accumulation characteristics are classified into three modes according to the thermal evolution stage of the source rock. A comparison of hydrocarbon accumulation processes between the Yingxi oilfield in the western Qaidam Basin and Dina 2 gas fields in the Kuqa foreland basin allowed hydrocarbon accumulation modes to be determined.

Main constrains and dynamic process of Ordovician hydrocarbon accumulation, central and western Tahe Oil Field, Tarim Basin

Diversified types of oil and gas resources have been discovered in the Ordovician strata of central and western parts of the Tahe Oil Field, Tarim Basin. The formation contains oil in the direction as a whole, and its accumulation process appeared to be extremely complicated. The dynamic process of oil and gas accumulation in the central and western parts of Tahe Oil Field were re-studied on the basis of combination of approaches including perspective of multiple reservoir-forming factors and their temporal and spatial dynamic configuration relationships, the discussion of typical reservoir profiles, thermal evolution of source rocks and consequent hydrocarbon generation history, paleo-structural evolution, hydrocarbon accumulation period and transport system, thus, a model of compound accumulation was established following an idea that paleo-structures and strike-slip faults together constrained reservoir formation and hydrocarbon generation as well as accumulation. Studies have shown that the main constrains for hydrocarbon accumulation in the study area includes the long-term hydrocarbon generation and expulsion from source rocks, multi-stage charging and accumulation and mixing transformation, paleo-structural controlling the migration and accumulation direction, conduction and lateral adjustment by strike-slip faults, and multiple types of fractures and caves. The dynamic process of hydrocarbon accumulation has the characteristics of vertical transportation, lateral accumulation, paleo-uplift controlling enrichment in the early stage, and in-situ hydrocarbon source, migration and accumulation, and fault controlling enrichment in the late stage. The mixed accumulation of oil and gas of different stages and different properties has created the present complex oil and gas appearance of the Ordovician strata. The heavy oil area was dominated by early accumulation, which was related to the high paleo-structures in the middle and late Caledonian periods, and the later charging was relatively weaker. The light oil area was dominated by late accumulation, mainly constrained by the transport and short-range lateral adjustment of strike-slip faults. It is most developed in the NNE-trending fault zone and the intersection with the NNW-trending fault.

Evaluation of Hydrocarbon Generation Using Structural and Thermal Modeling in the Thrust Belt of Kuqa Foreland Basin, NW China

The Kuqa Basin is a typical foreland basin in northwest China, characterized by compressive foreland fold-and-thrust belts and a regionally distributed huge salt layer. A large number of overthrust faults, fault-related folds, and salt-related structures are formed on the thrust belt due to strong compression and structural deformation, causing difficulty in simulation of the basin. In this study, modeling of the thermal history of the complicated compressional structural profiles in the Kuqa foreland basin was successfully conducted based on the advanced “Block” function introduced by the IES PetroMod software and the latest geological interpretation results. In contrast to methods used in previous studies, our method comprehensively evaluates the influence of overthrusting, a large thick salt layer with low thermal conductivity, fast deposition, or denudation on the thermal evolution history. The results demonstrate that the hydrocarbon generation center of the Kuqa foreland basin is in the deep layers of the Kelasu thrust belt and not in the Baicheng Sag center, which is buried the deepest. A surprising result was drawn about the center of hydrocarbon generation in the Kuqa foreland basin, which, although not the deepest in Baicheng Sag, is the deepest part of the Kelasu thrust Belt. In terms of the maturity of the source rock, there are obvious temporal and spatial differences between the different structural belts in the Kuqa foreland basin, such as the early maturation of source rocks and the curbing of uplift and hydrocarbon generation in the piedmont zone. In the Kelasu thrust belt, the source rock made an early development into the low mature-mature stage and subsequently rapidly grew into a high-over mature stage. In contrast, the source rock was immature at an early stage and subsequently grew into a low mature-mature stage in the Baicheng Sag–South slope belt. The time sequence of the thermal evolution of source rocks and structural trap formation and their matching determines the different accumulation processes and oil and gas compositions in the different structural belts of the Kuqa foreland basin. The matching of the multistage tectonic activity and hydrocarbon generation determines the characteristics of the multistage oil and gas accumulation, with the late accumulation being dominant. The effective stacking of the gas generation center, subsalt structural traps, reservoir facies of fine quality, and huge, thick salt caprocks creates uniquely favorable geological conditions for gas enrichment in the Kelasu foreland thrust belt.

Development and exploration practice of the concept of hydrocarbon accumulation in rifted-basin troughs: A case study of Paleogene Kongdian Formation in Cangdong sag, Bohai Bay Basin

Abstract Based on the merged 3D seismic data, well logging, formation testing, analysis and testing data, the structural evolution, sedimentary reservoirs, thermal evolution of source rocks were investigated of Paleogene Kongdian Formation in the trough area of Cangdong sag, Bohai Bay Basin. A conventional-unconventional hydrocarbon accumulation pattern in the trough area of rifted basin was revealed. The reservoir forming elements in the trough area of Cangdong sag have a zonation feature in terms of reservoirs and source rocks. There are two types of reservoir forming models, primary trough and reformed trough. The formation and evolution of trough controlled the orderly distribution of conventional oil to unconventional oil in the trough. Particularly, structural reservoirs occur in the upper part of the trough, stratigraphic-lithologic reservoirs are likely to form in the delta front deposits at the outer ring of trough, the middle ring transitional belt is the favorable site for tight oil reservoirs, while the fine grain deposits zone in the inner ring is shale oil and gas exploration area. The study has pointed out the new domains and directions for searching reserves in the secondary exploration of mature oilfields.

Importance of evolving fault seals on petroleum systems: Southern Halten terrace, Norwegian Sea

The role of faults in petroleum systems is important especially in cases where the hydrocarbon accumulation in the prospect or field is fault-dependent. Usually, the properties of faults in petroleum systems are considered as static through time. We present a case study from the southern Halten terrace in the Norwegian Sea which highlights not only the importance of faults but also that the evolution of fault properties is key in determining the correct charge in the fields in the region. The best-fit model shows that in order to match observations the petroleum system requires at least two stages of hydrocarbon migration during which fault properties change from partially to completely sealing with respect to hydrocarbon flow across them. The most likely process that results in fault sealing is cementation due to increasing temperatures caused by the rapid burial during the Quaternary glaciations. This results in the most accurate charge of accumulations in the region while also explaining other observations such as present-day pressure compartmentalization and biodegradation. The best-fit model also implements the source rock thermal evolution based on a 2D basin model that improves the match of fluid GOR in the accumulation to the measured values. This study highlights the importance of multi-scale, multi-physics and multi-stage models in order to obtain results consistent with present day observations.

Present temperature field and Cenozoic thermal history in the Dongpu depression, Bohai Bay Basin, North China

The Dongpu depression is located in the southern Bohai Bay Basin, North China, and it has abundant oil and gas reserves. There has been no systematic documentation of this depression's temperature field and thermal history. In this article, the present geothermal gradient and heat flow were calculated for 68 wells on the basis of 892 formation-testing data from 523 wells. Moreover, the Cenozoic thermal history was reconstructed using 466 vitrinite reflectance data from 105 wells. The results show that the Dongpu depression is characterized by a medium-temperature field between stable and active tectonic areas, with an average geothermal gradient of 34.8 °C/km and an average heat flow of 66.8 mW/m2. The temperature field in the Dongpu depression is significantly controlled by the Changyuan, Huanghe, and Lanliao basement faults and thin lithosphere thickness. The geothermal gradient twice experienced high peaks. One peak was during the Shahejie 3 Formation depositional period, ranging from 45 °C/km to 48 °C/km, and the second peak was in the middle and late of the Dongying Formation depositional period, ranging from 39 °C/km to 40 °C/km, revealing that the Dongpu depression experienced two strong tectonic rifts during the geothermal gradient high peak periods. The geothermal gradient began to decrease from the Neogene, and the geothermal gradient is 31–34 °C/km at the present day. In addition, these results reveal that source rock thermal evolution is controlled by the paleo temperature field of the Dongying Formation depositional period in the Dongpu depression. This study may provide a geothermal basis for deep oil and gas resource evaluation in the Dongpu depression.

Quantitative analysis of the effect of salt on geothermal temperature and source rock evolution: A case study of Kuqa foreland basin, Western China

Abstract There develop two sets of thick salt in the Kuqa foreland basin, the impact of salt thickness on geothermal temperature and thermal evolution of source rock was analyzed using transient thermal modeling method based on the two dimensional seismic profile from west to east of the basin and the related boundary condition. The results indicate that: (1) the change of salt plies will not have different impact on geothermal temperature when the total thickness of the salt body is constant; (2) the geothermal temperature of formations above the salt will increase about 0.3–0.6 °C/100 m, while the subsalt geothermal temperature will decrease about 0.6–1.0 °C/100 m in the west of the basin; the geothermal temperature of formations above the salt will increase about 1.9–2.3 °C/100 m, while the subsalt geothermal temperature will decrease about 0.2–2.6 °C/100 m in the east of the basin; (3) the value of vitrinite reflectance will be lagged about 0.02%/100 m averagely in the west of the basin, and will be lagged about 0.05%/100 m in the east. As the thermal conductivity of salt is negatively correlated with temperature, the salt body in the east has a shallower burial and lower geothermal temperature, so its overall thermal conductivity is higher, causing the changing rates of geothermal temperature and R o are higher than the west. A case study of Dina 2 condensate field of Kuqa foreland basin indicates that the charge time of hydrocarbon there lagged about 7.5–9.0 Ma because of the delayed source rock thermal evolution caused by the salt, matching well with the formation period of trap, which is favorable for the late accumulation of hydrocarbon in this area.

东濮凹陷前梨园洼陷热史及烃源岩热演化

东濮凹陷为临清坳陷重要的生油构造单元，是渤海湾盆地最具有油气勘探潜力的凹陷之一。其中前梨园洼陷是整个东濮凹陷增储的主要地区，为了揭示其热史及烃源岩热演化历史，首先利用5口典型井的镜质体反射率数据恢复了前梨园洼陷的热历史，结果表明前梨园洼陷在沙河街组沉积开始至东营组沉积末期，经历了两期裂陷作用，地温梯度出现两期峰值，为39℃/km~48℃/km和38℃/km~40℃/km。再以热史为基础，结合沉积和构造发育史及烃源岩地球化学资料，模拟了前梨园洼陷5口典型井6套烃源岩的成熟度演化历史，揭示了前梨园洼陷烃源岩成熟度演化受东营组沉积时期古地温场控制，6套烃源岩成熟度都在东营组沉积末期达到最高，这将为前梨园地区深层油气勘探提供参考。 The Dongpu sag is an important generation hydrocarbon area of tectonic units in the Linqing de-pression of the Bohai Bay Basin, which has the greatest potential for oil and gas exploration. The Qianliyuan sub-sag is the main area of increasing oil and gas reserves in the Dongpu sag. In order to reveal the thermal history and source rock thermal evolution history, the thermal history of the Qianliyuan sub-sag was reconstructed based on vitrinite reflectance data from 5 typical wells. The results show that Qianliyuan sub-sag has experienced two phases of rifting, and the geothermal gradient reached twice high peaks during the early stage of the Shahejie Formation depositional period (39˚C/km - 48˚C/km) and the late stage of the Dongying Formation depositional period (38˚C/km - 40˚C/km). Moreover, based on the thermal history results, combined with the sedimentary and tectonic histories and source rock geochemical data, six sets of source rocks maturity history of 5 typical wells were simulated in the Qianliyuan sag. The results reveal that source rock thermal evolution is controlled by the paleo geothermal fields of the Dongying Formation depositional period in the Qianliyuan sag. The maturity of 6 sets of source rocks reached a maximum at the late stage of the Dongying Formation depositional period. This work will provide reference for deep oil and gas exploration in the Qianliyuan area.

The salt chimney effect: delay of thermal evolution of deep hydrocarbon source rocks due to high thermal conductivity of evaporites

AbstractHalf of the topseals to the world's largest oilfields are evaporites. Rock salt has a thermal conductivity two to four times greater than that of other sedimentary rocks found in oil‐ and gas‐bearing basins. Strong heat conduction through evaporites can increase the geothermal gradient above evaporite deposits, resulting in a positive thermal anomaly and above‐average temperature while simultaneously decreasing the geothermal gradient below evaporites, resulting in a negative thermal anomaly. Most Triassic–Jurassic hydrocarbon source rocks in the Kuqa Basin, western China, are overlain by ~1500‐m‐thick Tertiary evaporites with underlying Cretaceous sandstones and mudstones. Directly measured strata temperatures indicate an obvious break in the steepness of the geothermal gradient above and below Paleogene evaporites, with a significantly steeper geothermal gradient above the evaporites. Simulations of the thermal evolution of source rocks based on data collected from well Kela‐2 indicate that if the thickness of evaporites (mainly rock salt and anhydrite rock) in overlying rocks above source rocks increases compared with the thickness of siliciclastic rocks in the overlying rocks, then strata temperatures and vitrinite reflectance in Jurassic source rocks will decrease accordingly. Our thermal simulations based on the thickness and thermal conductivity of evaporites accurately coincide with previous studies based on homogenization temperatures, hydrocarbon–water contact retrospection, and carbon isotope results from natural gases. The gas generation center located in the Kalasu Tectonic Belt today is also sealed in an evaporite‐related structural trap that formed at this time. Therefore, the speculated natural gas generation times not only correlate with the evaporite‐related structural trap formation, but the calculated maturity of deep source rocks below the evaporites also coincides with current gas reserves. And our studies can help to find the deep oils and gases under thick evaporites.

Yanshan‐Himalayan Denudation in Western Hubei Eastern Chongqing Area

AbstractWestern Hubei Eastern Chongqing area is a major exploration block of marine‐facies petroleum as well as a currently popular area of shale gas exploration. It has suffered long term uplift and erosion since the Late Yanshan‐Himalayan period. Erosion thickness is an indispensable basic parameter for study of thermal evolution of source rocks, reservoir formation and evolution, and basin modeling to calculate the amount of resources. Considering the inherent limitations and application conditions of the existing methods of erosion thickness reconstruction, firstly we used the paleogeothermal gradient inversion method to reconstruct the erosion thickness of boreholes after analyzing the vitrinite reflectance (Ro) profiles. Then, we studied the relationship between the erosion thickness of boreholes and the upmost sequences of the boreholes drilled. After that, a contour map was compiled based on the geological map. The results show that the vitrinite reflectance (Ro) profiles of boreholes in the western Hubei Eastern Chongqing area do not show obvious “dislocations” or “jumps”, recorded maximum palaeotemperatures of sequences in the maximum burial depth. There exists a clear correlation between the erosion thickness and the upmost sequence of the wells: the greater age of the upmost sequence, the greater erosion thickness of the well, and vice versa. Generally, the late Yanshan‐Himalayan erosion amount gradually decreases from east to west in the Western Hubei Eastern Chongqing area. From the Lichuan area to Shizhu and to the west of the Fangdoushan, the erosion thickness decreases from 2000∼4000 m to 1500∼2500 m and to 1000∼1500 m.

Controls of Late Jurassic-Early Cretaceous tectonic event on source rocks and seals in marine sequences, South China

Thermal evolution of source rocks and dynamic sealing evolution of cap rocks are both subjected to tectonic evolution. The marine sequences in South China have experienced superposed structural deformation from multiple tectonic events. To investigate the effectiveness of preservation conditions, it is of great importance to understand the controls of key tectonic events on the dynamic evolution of cap rocks. This paper discusses the controls of Late Jurassic-Early Cretaceous (J3-K1) tectonic event on source and cap rocks in marine sequences in South China based on the relationships between J3-K1 tectonic event and the burial history types of the marine sequences, the hydrocarbon generation processes of marine source rocks, the sealing evolution of cap rocks, the preservation of hydrocarbon accumulations, and the destruction of paleo-oil pools. The study has the following findings. In the continuously subsiding and deeply buried areas during the J3-K1 period, marine source rocks had been generating hydrocarbons for over a long period of time and hydrocarbon generation ended relatively late. At the same time, the sealing capacity of the overburden cap rocks had been constantly strengthened so that hydrocarbons could be preserved. In the areas which suffered compressional deformation, folding and thrusting, uplifting and denudation in J3-K1, the burial history was characterized by an early uplifting and the hydrocarbon generation by marine source rocks ended (or suspended) during the J3-K1 period. The sealing capacity of the cap rocks was weakened or even vanished. Thus the conditions for preserving the hydrocarbon accumulations were destroyed. The continuously subsiding and deeply buried areas during the J3-K1 period are the strategic precincts of the petroleum exploration in marine sequences in South China.

Formation and accumulation of oil and gas in marine carbonate sequences in Chinese sedimentary basins

Advances in studies of formation and accumulation mechanisms of oil and gas in marine carbonate sequences have led to continuing breakthroughs of petroleum exploration in marine carbonate sequences in Chinese sedimentary basins in recent years. The recently discovered giant Tahe Oil Field and Puguang Gas Field have provided geological entities for further studies of the formation and accumulation of oil and gas in marine carbonate sequences. Marine carbonate sequences in China are characterized by old age, multiple structural deformation, differential thermal evolution of source rocks, various reservoir types (i.e. reef-bank complex and paleo-weathered crust karst reservoir), uneven development of caprocks, especially gypsum seal, and multi-episodes of hydrocarbon accumulation and readjustment. As a result, the formation of hydrocarbon accumulations in the Chinese marine carbonate sequences has the following features: (i) the high-quality marine source rocks of shale and calcareous mudstone are often associated with siliceous rocks or calcareous rocks and were deposited in slope environments. They are rich in organic matter, have a higher hydrocarbon generation potential, but experienced variable thermal evolutions in different basins or different areas of the same basin. (ii) High quality reservoirs are controlled by both primary depositional environments and later modifications including diagenetic modifications, structural deformations, and fluid effects. (iii) Development of high-quality caprocks, especially gypsum seals, is the key to the formation of large- and medium-sized oil and gas fields in marine carbonate sequences. Gypsum often constitutes the caprock for most of large sized gas fields. Given that Chinese marine carbonate sequences are of old age and subject to multiple episodes of structural deformation and superposition, oil and gas tend to accumulate in the slopes and structural hinge zones, since the slopes favor the development of effective assemblage of source-reservoir-caprock, high quality source rocks, good reservoirs such as reef-bank complex, and various caprocks. As the structural hinge zones lay in the focus area of petroleum migration and experienced little structural deformation, they are also favorable places for hydrocarbon accumulation and preservation.