Secondary Hydrocarbon Research Articles

Experimental investigation of kerogen structure and heterogeneity during pyrolysis

Kerogen in shale microstructure plays a vital role in hydrocarbon generation, retention and accumulation. However, characterization of kerogen structure is challenging arguably due to a complex microporous structure and chemical heterogeneity. Thus, the role of kerogen molecular structure in controlling porosity and its heterogeneity, as well as its evolutionary processes, remains unclear. In this study, we investigate the chemical and pore structure of heated kerogen samples by employing a range of characterization tools including gas adsorption experiments, high-resolution transmission electron microscopy (HRTEM), Fourier transform infrared (FTIR) spectroscopy, and laser Raman experiments for a broad range of pyrolysis temperatures (420–850 °C). Multifractal theory and peak fitting techniques were used to evaluate the controlling mechanisms of kerogen pore structure and heterogeneity. The results suggest that with increasing thermal maturity, the content of oxygen functional groups and long-chain aliphatic groups in kerogen significantly decreases, while the length of aromatic fringes increases and gradually becomes oriented. Furthermore, with increasing thermal maturity, the pore volume of kerogen exhibits a non-monotonic trend, i.e., a decrease, followed by an increase, and then finally a decrease. This is primarily influenced by processes such as hydrocarbon production weakening, secondary hydrocarbon cracking, and carbonization. The heterogeneity and dispersion of meso to macro-sized pores in kerogen increase with temperature, while the connectivity gradually decreases. The chemical structure and spatial distribution of kerogen significantly affect the heterogeneity, connectivity, and dispersion of meso to macro-sized pores. Specifically, high aromaticity, structural disorder, and short aliphatic chains result in enhanced heterogeneity and dispersion of meso to macro-sized pores, reducing pore connectivity. This study thus contributes to a deeper understanding of the evolution of organic matter pores.

Thermal evolution differences of reservoir bitumen and their implications: A case study of the Moxi area in the central Sichuan basin

Temperature and time were generally considered as the two key influences on the thermal evolution of both source organic matters and secondary hydrocarbon products (i.e., oil, gas, bitumen and solid bitumen). And for the hydrocarbons, other factors such as the types of source organic matters, the alteration reactions and fluid pressure evolution can also influence their degree of thermal maturation. As a consolidated product of bitumen, the traditional view is that the solid bitumen originated from the same source would exhibit similar maturity after experiencing identical paleo-temperature. However, things need to be more thoughts, such as the impact of system open or not on the solid bitumen thermal evolution and maturation degree. In this regard, we compared the solid bitumens within both reservoir pores and inclusions in deep carbonate reservoirs of lower Cambrian Longwangmiao Formation (Є1l) and the fourth member of the Sinian Dengying Formation (Z2dn4) in the Moxi area in the central Sichuan Basin. And by analyses of the Raman spectroscopy and bitumen reflectance, our results show a significant difference of maturities for these homologous solid bitumens after experienced the same highest geological temperature. Specifically, based on petrological observations, three types of solid bitumen occurrences (Bit. A, Bit. B, and Bit. C) were identified. Bit. A fills the early fine-grained dolomite dissolution pores with small and dispersed morphology, which eRo-Raman (equivalent vitrinite reflectance obtained by Raman) values show a narrow range from 2.60% to 2.80%. Bit. B with larger, blocky morphology, distributes within pores between the early recrystallized dolomites or the subsequent euhedral dolomites, including the bitumen filling in the fracture as stylolite. Their eRo-Raman values mainly concentrate in the range of 1.80%–1.90%. Bit. C refers to the bitumen inclusions hosted in various diagenetic minerals, with eRo-Raman values range from 2.70% to 2.87%. Since these solid bitumens originated from the same source rocks and have experienced the same highest geological temperature, their heterogeneous eRo-Raman values, therefore, suggest that whether the system open or not matters the thermal evolution of solid bitumen. Our results suggest that caution should be applied when using maturity to study the thermal evolution history in an open system, and hydrocarbons trapped in a closed system (e.g., fluid inclusion) can serve as a more credible recorder of thermal evolution.

Controlling effect of palaeo-tectonic stress field on gas occurrence

The paleo-tectonic stress fieldwas hereby inverted by using the stereographic projection method through field and underground observations of conjugate shear joints. On the basis of analyzing and studying the characteristics of gas occurrence in mining areas, the control effect of paleo-tectonic stress field on gas occurrence was discussed from three aspects of gas generation, preservation environment and gas migration. The results show that: (1) During the Indosinian and early-middle Yanshan period, the coal seam was buried deep, and the temperature and pressure conditions were suitable for massive gas generation, especially during the Indosinian period featuring massive gas generation and weak gas migration; (2) During the late Yanshan period, the metamorphic evolution rate of coal seams accelerated, secondary hydrocarbon generation occurred in the coal seams, and a large amount of gas was generated. Meanwhile, the gas migration was enhanced. The gas generation amount was much larger than the emission amount, therefore, making it still a period of massive gas generation in general; (3) During the Himalayan period, the coal measure stratum was in the uplift stage, and a large number of geological structures were developed in the stratum. The tectonic stress field in this period caused the escape of massive coal seam gas. Multi-stage tectonic stress field acted on coal measures strata in turn, resulting in gas generation in coal seam and gas migration at the same time. Besides, gas occurrence is the superposition effect of gas generation, preservation conditions, and gas migration in coal seam.

Research on fault-controlled hydrocarbon accumulation in rifted lacustrine basins based on structural geological modeling: a case study of the Banqiao area in Bohai Bay Basin, China

The Banqiao area in the Bohai Bay Basin has experienced three stages of extensional deformation, leading to the formation of numerous fault-bound traps. Faults, acting as boundary conditions for these traps, play a crucial role in hydrocarbon accumulation. In this study, we conducted a 3D structural modeling of the area using high-resolution 3D seismic data and established a fault-reservoir database based on previous research. Our findings reveal four levels of faults in the Banqiao area: basin-controlling faults, boundary faults, derivative master faults, and secondary adjusting faults. The structural units can be categorized into subsag areas, slope areas, stress tran-sition zones, bifurcation and main incised fault zones, and southern block areas. The segmented growth of the main boundary faults controls the evolution of the subsags, with the subsidence center gradually shifting eastward from Rift Phase I to Rift Phase II, aligning with the distribution of source rocks. Fault-bound traps in the Banqiao area include single faults, intersecting faults, and side faults. Faults primarily act as barriers to lateral hydrocarbon migration during the process of hydrocarbon accumulation, while also providing pathways to a lesser extent. By integrating the fault-reservoir database with the fault system classification, we identified four types of fault-controlled hydro-carbon accumulation models: like-dipping fault barrier model, oppositely-dipping fault barrier model, intersecting fault barrier model, and reactivation-controlled secondary hydrocarbon ac-cumulation model. This structural geological model effectively demonstrates the spatial configura-tion of faults and their role in hydrocarbon accumulation in the Banqiao area. The fault control mechanisms presented in the model can also be applied to other blocks in the Bohai Bay Basin, laying a foundation for future petroleum exploration in continental rifted basins and facilitating the ap-plication of big data algorithms in various geoscientific research fields.

A new method of the hydrocarbon secondary migration research: Numerical simulation

A three-dimensional invasion percolation simulation model is introduced and integrated into a novel three-dimensional geological modeling framework based on the “unit element” theory to study secondary hydrocarbon migration. Leveraging the computational efficiency inherent in the invasion percolation theory, the simulation method is effectively applied to basin-scale hydrocarbon migration using finely discretized grids. Sensitivity analysis demonstrates the substantial influence of geological parameters including structural configuration, sedimentary facies, and pressure, on simulation results. Noteworthy observations from this study encompass: (1) The intricate influence of sedimentary facies and petrophysical properties characteristics on hydrocarbon migration and accumulation patterns within structural and lithological traps. Favorable petrophysical attributes in the carrier beds enhance the likelihood of accumulation in the structural traps, while lithological traps are prevalent in less conducive carrier beds. (2) The significant impact of sand bodies exhibiting favorable petrophysical attributes, such as channels, on migration and accumulation profiles. This underscores the necessity of incorporating sedimentary facies and rock attributes into oil and gas resource exploration. (3) The pronounced effects of overpressure magnitude and direction on hydrocarbon migration and accumulation dynamics. (4) Optimal strategies for oil and gas resource exploration necessitate a comprehensive assessment of rock attributes, overpressure considerations, and sedimentary facies. The practical implementation of this methodology is demonstrated in an actual exploration project within China's Junggar Basin. The simulation results closely align with established oil recovery data and facilitate predictive identification of promising exploration areas. This indicates the methodology is applicable to all petroleum systems similar to Junggar Basin. Through practical applications, the development of a scientifically rigorous three-dimensional geological model for the study area, coupled with numerical simulations of oil and gas migration, facilitates the elucidation of accumulation patterns. This approach aids in identifying pivotal factors such as sand body distribution, internal structural composition, permeability attributes, and fracture behavior, which collectively influence oil and gas migration. Furthermore, by correlating insights obtained from oil and gas discoveries in wells, a deeper understanding of carrier bed properties and their geological evolution is attained.

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.

Hydrocarbon dominant migration direction and accumulation mode in Qijiang area, Sichuan Basin, China

The high‐quality hydrocarbon source rocks developed in the Longtan Formation of the Qijiang area and the good reservoir capacity of the overlying dolomite of the Jialingjiang Formation indicate that the area has great exploration potential. To clarify the hydrocarbon migration and accumulation characteristics of the area, the fluid potential of the Longtan Formation in the Qijiang area in the Early Jurassic was determined. The direction of the maximum negative gradient of the fluid potential indicates the direction of the primary migration of hydrocarbons, and the structural ridge theory is used to analyse the direction of the secondary migration of hydrocarbons. The results show that the fluid potential of the hydrocarbon source rocks of the Longtan Formation in the Early Jurassic is characterized by the alternate distribution of high potential zones and low‐potential zones. The central syncline, eastern syncline and western syncline are drainage zones and high potential zones, while the Shiyougou structural belt and Fo'er Ya structural belt are supply zones and low‐potential zones. The oil and gas fluids migrate from the east–west direction to the anticlinal zone for the primary migration; the structural ridge controls the secondary migration of oil and gas in the low‐potential area along the north–south direction, resulting in a zonal distribution of oil and gas traps along the structural ridge. By combining fluid potential and structural ridge characteristics to determine the dominant direction of primary and secondary hydrocarbon migration, a model of hydrocarbon migration and accumulation in the Qijiang area is developed, which provides an important basis for finding hydrocarbon reservoirs.

Identification methods and the main factors controlling water washing in secondary oil reservoirs: A case study of Qingshuihe formation of lower Cretaceous in Mosuowan area of Junggar Basin

Secondary oil reservoirs have undergone multi-stage structural evolution, the hydrocarbon forming process is complex, and the main controlling factors of reservoir formation are unclear, and it is difficult to effectively identify, which seriously restricts the next exploration and extraction. Secondary oil reservoirs of the Qingshuihe Formation in the Mosuowan area of Junggar Basin were used as a case. Using experimental analyses of water washing simulation, group composition, rock pyrolysis, resistivity, high-pressure mercury injection, and homogenisation temperature of inclusion, this study carried out research on the identification methods of secondary oil reservoirs, causes of water production of oil-bearing cores and main controlling factors. The results show that water washing in secondary oil reservoirs is characterised by low saturated hydrocarbon, low aromatic hydrocarbon, high colloid, high asphaltene, a low ratio of S1/S2, low oil saturation, and low resistivity. Based on this feature, a comprehensive identification method combining geochemistry and logging of secondary reservoirs is established. The oil deposits of the Qingshuihe Formation in the Mosuowan area have two stages of hydrocarbon filling, the first stage is Late Cretaceous, forming primary oil reservoirs. The second stage is Neogene, and oil reservoirs are adjusted to form secondary oil reservoirs. Under the influence of Himalayan movement, the oil adjustment and dispersion were caused by structural tilting movement, which led to the water production of oil-bearing cores with favourable physical properties and large thickness in the research region. The adjusted residual oil reservoirs are major governed by paleogeomorphology, sedimentary microfacies, reservoir physical properties, and low amplitude structure. Four secondary hydrocarbon accumulation models are established: thin interbedded lithologic oil reservoir, sedimentary filling lithologic oil reservoir, low amplitude structural oil reservoir, and stratigraphic pinch-out lithologic oil reservoir. The research results have important instructive meanings for the identification and prospecting of secondary hydrocarbon reservoirs.

ASSESSMENT AND PROTECTION OF GEOENVIRONMENT COMPONENTS FROM IMPACTS PRODUCED BY TECHNOGENOUS HYDROCARBON DEPOSITS

The article presents the results of studies of technogenous hydrocarbon deposits - Light Non-Aqueous Phase Liquid (LNAPL) bodies in technonatural systems. The specific feature of these bodies is their location in the geological environment beneath operating and abandoned oil industry enterprises. Enterprises are the sources of hydrocarbons in the geological environment. Light non-aqueous phase liquid bodies are interpreted as complex, dynamic, multicomponent systems, which are subject to the influence of flooding and low-water phenomena in the nearby surface water bodies. Based on the study of archive data and the results of field survey of these objects, the integrated system has been developed for assessing the status of technonatural systems containing LNAPL bodies. It is based on the suggested criteria, and includes geometric, technological, geoecological, resource-economic and inertial-oscillatory groups. The scheme of carrying out a complex of works, including research, assessment, modeling, and liquidation of LNAPL bodies is proposed. This scheme takes into account the LNAPL dual nature: on the one hand, LNAPL body contaminate the environment, on the other hand, produce secondary hydrocarbon resources. The proposed integrated assessment system permits us to determine the current state of LNAPL bodies as a part of technonatural systems, to select and justify technological solutions for their liquidation and remediation of contaminated sites.

An indication of salt caprock failed integrity in inclusion records: Dongpu depression, bohai bay basin, China

Salt rocks are widely distributed in the Paleogene strata of the Dongpu Depression, China, as major caprocks of the Shahejie Formation. Previous studies have suggested that the decline of formation pressure during the Dongying movement is accompanied by petroleum leakage, but they lack any direct evidence of failed integrity of the salt caprocks. Therefore, fluid inclusion analysis under both incident ultraviolet (UV) and transmitted light (TR) modes on halite samples were conducted in this study, supported by basin and fluid inclusion PVTX modeling to prove lack of integrity in the caprock, periodically. Our observation showed that various types of hydrocarbon inclusions exist in halite crystals, revealing multi-stage fracturing and healing processes inside the salt caprocks. Coupling the PVTX and basin modeling results, revealed that oil inclusions were trapped at around 6.6 Ma during the secondary hydrocarbon generation of the source rocks. Moreover, salt caprocks failed due to the overpressure that was formed during hydrocarbon generation. This was exacerbated by the following uplifting which ultimately led to the present-day normal reservoir pressure in the sampled depth. In addition, the fluorescence of oil inclusions in the same fracture gradually changed from orange to blue. This proved that analyzing the thermal maturity of trapped hydrocarbons within the inclusions, solely based on the fluorescence color, could be misleading and other submicron scale analytical methods should be employed to examine the inclusions. Overall, this study enabled us to investigate the caprock integrity via optical methods, which can eventually help us to avoid regions where hydrocarbon is lost vs. prolific areas in the formation understudy.

Origin and accumulation models of ultra-low permeability-tight sandstone (gravel) gas in Bohai Bay Basin, China

Ultra-low permeability–tight sandstone (gravel) gas reservoir is an important exploration target for natural gas both domestically and internationally. As a crucial oil and gas exploration basin in China, the Bohai Bay Basin has discovered tight sandstone (gravel) gas in every depression. However, the distribution, origin, and accumulation model of tight sandstone (gravel) gas reservoirs were not systematically studied by previous researchers, who instead mainly concentrated on depressions from the basin-wide perspective. The research conclusively demonstrates that ultra-low permeability–tight sandstone (gravel) gas reservoirs are widely distributed in the Bohai Bay Basin, covering various depressions and multiple strata of Paleozoic, Cenozoic, and Upper Paleozoic coal-formed gas as well as Paleogene oil-type gas. The Upper Paleozoic ultra-low permeability–tight sandstone gas reservoirs are mainly distributed in residual Upper Paleozoic strata of the Huanghua, Linqing, and Jiyang depressions. Most of those reservoirs, which are located in uplifted sag zones, are structural gas reservoirs, and because the strata were buried deeply in the past, most of the reservoirs have worse physical properties. This natural gas is typical coal-formed gas originating in Carboniferous and Permian, and others are Paleogene oil-type gas. Paleogene ultra-low permeability–tight gas reservoirs are widely distributed in all depressions, including the multiple strata in the Kongdian Formation and the second, third. and fourth members of the Shahejie Formation (Es2, Es3, and Es4); The gas reservoirs are located in the uplift, slope, and steep slope zones of the sags, including a variety of trap types, such as lithology, lithology-structure, structure reservoirs, and others. Sandstone reservoirs often found in the Es2 and Es3 are distributed in gentle slopes, whereas sandstone and glutenite reservoirs can be found in the Es4 and Kongdian Formation (Ek), with the glutenites mainly distributed in steep slope area. Since the Paleogene is a continuous deposit, burial depth appears to be a controlling factor in the reservoirs physical properties. Densification threshold depths for distinct depressions range from 3200 m to 4000 m. The majority of the natural gas is gas formed from Paleogene oil-type, while some of it is gas formed from Upper Paleozoic coal. Four different hydrocarbon accumulation models have been developed in this area in accordance with the relationship between gas sources and reservoirs. These models include migration along fault with old source rock and new reservoir, near-source accumulation with new source rock and new reservoir, distant-source accumulation with old source rock and old reservoir, and migration along fault with new source rock and old reservoir, of which the first two are the main hydrocarbon accumulation models. Two sets of Carboniferous–Permian and Paleogene strata are developed, and the remaining natural gas resources have great potential in the Bohai Bay Basin. The Carboniferous–Permian beneficial zone of secondary hydrocarbon generation, the structures adjacent to the margin of the Paleogene gas generation center, and the sweet spot in lithology reservoirs would all be promising areas for further exploration. The research is of instructive significance for tight sandstone (gravel) gas exploration in the Bohai Bay Basin.

Can Agents Model Hydrocarbon Migration for Petroleum System Analysis? A Fast Screening Tool to De-Risk Hydrocarbon Prospects

Understanding subsurface hydrocarbon migration is a crucial task for petroleum geoscientists. Hydrocarbons are released from deeply buried and heated source rocks, such as shales with a high organic content. They then migrate upwards through the overlying lithologies. Some hydrocarbon becomes trapped in suitable geological structures that, over a geological timescale, produce viable hydrocarbon reservoirs. This work investigates how intelligent agent models can mimic these complex natural subsurface processes and account for geological uncertainty. Physics-based approaches are commonly used in petroleum system modelling and flow simulation software to identify migration pathways from source rocks to traps. However, the problem with these simulations is that they are computationally demanding, making them infeasible for extensive uncertainty quantification. In this work, we present a novel dynamic screening tool for secondary hydrocarbon migration that relies on agent-based modelling. It is fast and is therefore suitable for uncertainty quantification, before using petroleum system modelling software for a more accurate evaluation of migration scenarios. We first illustrate how interacting but independent agents can mimic the movement of hydrocarbon molecules using a few simple rules by focusing on the main drivers of migration: buoyancy and capillary forces. Then, using a synthetic case study, we validate the usefulness of the agent modelling approach to quantify the impact of geological parameter uncertainty (e.g., fault transmissibility, source rock location, expulsion rate) on potential hydrocarbon accumulations and migrations pathways, an essential task to enable quick de-risking of a likely prospect.

Reuse of Flowback Water from Hydraulic Fracturing for Drilling Mud Preparation and Secondary Hydrocarbon Recovery

Flowback water after completion of hydraulic fracturing is one of major waste streams generated during the lifespan of a well so its beneficial reuse is crucial. The application of treated flowback is not limited to stimulation processes but also may include drilling operations and secondary oil recovery. The flowback water used in this work is characterized by high salinity reaching up to ~295 g/L caused mainly by NaCl. The presence of suspended solids, mainly corrosion products, prompts the use of coagulation and filtration as treatment methods. Among tested coagulants the most effective one was the SAX18 (NaAlO2) commercial coagulant applied at concentration of 12 mL/L which reduces the water turbidity from over 400 FTU to 23 FTU. The applied treatment greatly reduces the concentration of scaling ions and so the concentration of SiO2 is reduced by 64%, Ba2+–66%, Fe2–36%, Mn2+–65%, SO42−–66%. The treated flowback fluid can be reused in surfactant flooding for enhanced oil recovery where achieves 7% higher displacing efficiency than fresh water. The drilling muds which were prepared using the untreated flowback water exhibit good rheological properties. The obtained results show that recycling of flowback water in future drilling and exploitation operations is technically feasible.

Burial history and the evolution of hydrocarbon generation in Carboniferous-Permian coal measures within the Jiyang super-depression, China

In the Jiyang Sub-basin, Carboniferous-Permian (C-P) coal-measure source rocks have experienced complex multi-stage tectonics and therefore have a complex history of hydrocarbon generation. Because these coal measures underwent multi-stage burial and exhumation, they are characterized by various burial depths. In this study, we used the basin modeling technique to analyze the relationship between burial history and hydrocarbon generation evolution. The burial, thermal and maturity histories of C-P coals were reconstructed, including primary hydrocarbon generation, stagnation, re-initiation, and peak secondary hydrocarbon generation. The secondary hydrocarbon generation stage within this reconstruction was characterized by discontinuous generation and geographical differences in maturity due to the coupled effects of depth and a delay of hydrocarbon generation. According to the maturity history and the delay effect on secondary hydrocarbon generation, we concluded that the threshold depth of secondary hydrocarbon generation in the Jiyang Sub-basin occurred at 2,100 m during the Yanshan epoch (from 205 Ma to 65 Ma) and at 3,200 m during the Himalayan period (from 65 Ma to present). Based on depth, residual thickness, maturity, and hydrocarbon-generating intensity, five favorable areas of secondary hydrocarbon generation in the Jiyang Sub-basin were identified, including the Chexi areas, Gubei-Luojia areas, Yangxin areas, the southern slope of the Huimin depression and southwest of the Dongying depression. The maximum VRo/burial depth (%/km) occurred in the Indosinian epoch as the maximum VRo/time (%/100Ma) happened in the Himalayan period, indicating that the coupling controls of temperature and subsidence rate on maturation evolution play a significant role in the hydrocarbon generation evolution. A higher temperature and subsidence rate can both enhance the hydrocarbon generation evolution.

Hydrocarbon generation from Carboniferous-Permian coaly source rocks in the Huanghua depression under different geological processes

Natural gas and condensate derived from Carboniferous-Permian (C-P) coaly source rocks discovered in the Dagang Oilfield in the Bohai Bay Basin (east China) have important implications for the potential exploration of C-P coaly source rocks. This study analyzed the secondary, tertiary, and dynamic characteristics of hydrocarbon generation in order to predict the hydrocarbon potentials of different exploration areas in the Dagang Oilfield. The results indicated that C-P oil and gas were generated from coaly source rocks by secondary or tertiary hydrocarbon generation and characterized by notably different hydrocarbon products and generation dynamics. Secondary hydrocarbon generation was completed when the maturity reached vitrinite reflectance (Ro) of 0.7%–0.9% before uplift prior to the Eocene. Tertiary hydrocarbon generation from the source rocks was limited in deep buried sags in the Oligocene, where the products consisted of light oil and gas. The activation energies for secondary and tertiary hydrocarbon generation were 260–280 kJ/mol and 300–330 kJ/mol, respectively, indicating that each instance of hydrocarbon generation required higher temperature or deeper burial than the previous instance. Locations with secondary or tertiary hydrocarbon generation from C-P coaly source rocks were interpreted as potential oil and gas exploration regions.

Catalytic deparaffinization of middle distillates

The middle distillate fractions obtained in primary oil refining plants contain a significant amount of n-paraffins, which have positive pour points, resulting in degradation of the low-temperature characteristics of fuels produced from these fractions. To improve the low-temperature properties of middle distillate frac tions, various depressor additives are used or dewaxing is carried out in various ways. The most efficient dewaxing process is the catalytic one. Classical methods for the secondary processing of hydrocarbon fractions are costly and often uneconomical for small oil refineries. The development of secondary hydrocarbon processing methods applicable at medium and low capacity refineries is an urgent task today. Therefore, our goal was to develop a technology for combined processes of primary distillation of oil coming through the Eastern Siberia – Pacific Ocean oil pipeline system and catalytic dewaxing of the resulting middle distillates. To determine the conditions for carrying out the process of catalytic hydrogen-free dewaxing, an experimental plant of continuous operation was developed with a feed rate of 10 l/h, including a tube furnace, a reactor with a fixed catalyst bed, a heat exchanger, and control and measuring devices. Experiments performed on a pilot plant made it possible to determine the optimal technological parameters for the catalytic dewaxing of middle distillates. It was shown that the catalytic dewaxing of middle distillates under experimentally determined conditions proceeds quite effectively on cracking catalysts SGK-1, SGK-5, KN-30-BIMT, manufactured in Russia. An optimal technological scheme for combining the process of primary oil separation and catalytic dewaxing of middle distillates is proposed. Calculation and optimization of the proposed technological scheme was performed in a computer simulation system ChemCad.

Tectono-thermal evolution of Cambrian–Ordovician source rocks and implications for hydrocarbon generation in the eastern Tarim Basin, NW China

The tectono-thermal evolution is an important control on petroliferous basin development; however, this evolution is difficult to reconstruct in sedimentary basins subjected to multiple tectono-thermal events. The Tarim Basin is the largest petroliferous basin in northwestern China and hosts a complex oil–gas system comprising several sets of source, reservoir, and cap rocks that have experienced multiple tectonic, thermal, and sedimentary events. Large oil and gas reserves have been discovered in the central and northern Tarim Basin during the last 30 years, but none in the eastern part of the basin. This is generally attributed to the high thermal maturity reached by source rocks during the Late Ordovician, and subsequent hydrocarbon loss. Therefore, reconstructing the Cambrian–Ordovician tectono-thermal evolution is critical in facilitating successful oil and gas exploration in this region. We compiled equivalent vitrinite reflectance data (n = 178) of source rocks from seven wells in the Tarim Basin, which for Cambrian–Ordovician source rocks are >1.3%, beyond the hydrocarbon generation threshold and in the main gas and dry gas generation stages. The Cambrian–Ordovician source rocks experienced rapid burial and heating during the Caledonian period, entered the hydrocarbon generation stage during the Middle–Late Ordovician, and reached peak hydrocarbon generation at the end-Caledonian period. They might have experienced secondary hydrocarbon generation after the Jurassic. Homogenization temperatures of fluid inclusions (n = 616) from wells GC4, LX1, MD1, and YD2 as well as the modeled thermal evolution reveal a main hydrocarbon generation event during the Caledonian period and a secondary event in the Yanshanian and Himalayan period in other wells (LX1, MD1, and YD2). Hercynian and Indosinian uplift and exhumation in the eastern Tarim Basin controlled the main structures, and faulting created favorable conditions for secondary hydrocarbon generation and migration at this time. Since the Yanshanian and Himalayan, the Tarim Basin has experienced further sedimentation and heating, and the tectono-thermal evolution might have been related to the formation of the Tibetan Plateau. In summary, our reconstruction of the tectono-thermal evolution of Cambrian–Ordovician strata and the hydrocarbon generation history of the Tarim Basin suggests that the eastern Tarim Basin may also have hydrocarbon generation potential and can guide future oil and gas exploration.

Secondary migration of hydrocarbons in Ordovician carbonate reservoirs in the Lunnan area, Tarim Basin

The study on the secondary migration of hydrocarbons in Ordovician carbonate reservoirs in the Lunnan area has been a challenge caused by limited geologic records as direct physical evidence, and physical simulations are difficult to conduct since the parameters of realistic geologic conditions are rare. Based on the analysis of the regional structure, and by integrating the study on the fluid properties and benzocarbazole nitrogen compounds parameters, the secondary hydrocarbon migration in Ordovician carbonate reservoirs in the Lunnan area, Tarim Basin, were investigated. The results indicated oil density show gradually increasing trends from Lungudong Fault to the Middle Slope in eastern Lunnan Uplift; while the trend is converse from southwest of Lunxi and Sangtamu Faults to the Middle Slope in western area. The benzocarbazole nitrogen compounds contents of Ordovician reservoir oil exhibit gradually increasing trends from southwest of Lunxi and Sangtamu Faults and southeast of Lungudong and Sangtamu Faults to the Middle Slope. The wax contents, gas dryness coefficients and gas/oil ratios show decreasing trends from east to west and away from the Lungudong Fault and Sangtamu Fault. The crude oil generated at the late Hercynian stage (about 290 Ma ago) in the Lunnan area migrated along the directions from southwest of Lunxi and Sangtamu Faults and southeast of Lungudong and Sangtamu Faults to the Middle Slope; the gas formed at the late Himalayan stage (about 208 Ma ago) migrated from the east to west laterally, and along the natural gas invasion faults Lungudong Fault and Sangtamu Fault upwards vertically.

Hydrocarbon accumulation period and process in Baobab area of Bongor Basin

The hydrocarbon reservoirs of Baobab area in the Northern Slope of the Bongor Basin in Chad, are very important petroleum exploration region in the basin. Baobab area could be divided into BS zone, BC zone and BN zone according to the tectonic distribution characteristics. All the three zones develop sandstone reservoirs, and the BC zone is mainly buried-hills reservoirs. Based on the analysis of the oil-source relationship of BS, BN and BC zone, the hydrocarbon accumulation period and adjustment process was investigated using a suite of hydrocarbon generation and expulsion history, tectonic thermal evolution history, GOI characteristics of fluid inclusions, microfluorescence determination and temperature measurement technology. The results show that crude oils of BS zone were sourced from BS zone source rock, oils of BN zone from BN zone source rock, and oil of BC zones from both of BS and BN source rocks. The history of hydrocarbon generation and expulsion history of source rock shows that the source rocks in BS zone matured earlier than the source rocks of BN. The hydrocarbon accumulation occurred in the early Late Cretaceous in BS zone, and in the middle Late Cretaceous in BN zone. The hydrocarbon accumulation period in the BC reservoirs was controlled by the hydrocarbon generation and expulsion history of source rock in BS and BN zones, which was a continuous process with different accumulation intensities during the Late Cretaceous. Due to the effects of tectonic events during Late Cretaceous, buried hill reservoirs of BC zone experienced the primary hydrocarbon accumulation of about 80-55 Ma and the secondary hydrocarbon accumulation at about 25 Ma. The reconstruction of buried-hill reservoirs in BC zone is obvious. The migration of crude oils from the ancient reservoir to the higher part of the Baobab structure along the faults and fractures due to tectonic inversion formed a new reservoir, and the oil-water contact became shallower about 357 m.

Origin and hydrocarbon source of the Ordovician high wax content oil in Southern Slope Zone of Dongying Depression

Exploration has inevitably extended into deep layers with ever-increasing exploration for oil and gas. Oils from Ordovician burial hill are recently discovered from Ordovician burial hill in the south slope of Dongying Depression, Bohai Bay basin, and the oils are characterized by high content of waxy alkanes with a low concentration of biomarker and sulphur content. Several types of oils also existed in the south slope of Dongying depression, such as biodegraded oil, normal oils in Shahejie Formation and high wax oils in Kongdian Formation. Forty-three oil samples and twenty-three source rock samples are finely analysed by inclusion analysis, monomer hydrocarbon isotope analysis and absolute content of biomarkers. On the basis of isotope compositions, biomarkers and integrating the physical properties of the hydrocarbons including densities and PVT relationships, it can be speculated that the oils from Ordovician buried hill and Kongdian Formation have the same source, obviously different from the overlying oils from Shahejie Formation. Combined with maturity parameters, biomarkers, and inclusions analysis, it is speculated that the oils are a secondary hydrocarbon accumulation from the mixing of earlier formed oil and a late formed gas, and the oils of Ordovician and Kongdian bear a typical features of deep Es4 source rocks. Aquatic organism, higher plants and bacteria are the source of the waxy oil, and the gas invasion in geological history should be responsible for the formation of the high waxy oils. This study is helpful for unravelling hydrocarbons accumulation mechanisms and deep petroleum resources evaluation in this area. Besides, the research process in this paper can also be applied to other basins to explore for high wax oil reservoirs.