Source Rock Generation Research Articles

Hydrocarbon potentiality and thermal maturity of the Cretaceous rocks in Al Baraka oil field, KomOmbo basin, south Egypt

This paper aims to evaluate the hydrocarbon potentiality and thermal maturity of the Cretaceous source rocks in Al Baraka oil field in KomOmbo basin, south Egypt. To achieve this aim, geochemical analyses (TOC), Rock eval pyrolysis and vitrinite reflectance measurements (R0) were carried out on the studied rocks. The analytical results of the samples that were collected from five exploratory oil wells revealed that almost Lower Cretaceous formations (Sabaya, Abu Ballas, Six Hills and KomOmbo C, B, A) and Upper Cretaceous formations (Dakhla, Duwi, Quseir, Taref and Maghrabi) are ranged from fair to excellent source rocks for hydrocarbon generation. Oil and gas are mainly the future products of the thermally transformed organic matters within almost samples of the Cretaceous formations, where the Lower and Upper Cretaceous formations contain mixed type II/III and III kerogen besides type II kerogen in KomOmbo (B) and Dakhla formations. The thermal maturity parameters clarified that the Lower Cretaceous formations are belonged to marginally mature (in Sabaya and Abu Ballas formations), whereas the rocks of KomOmbo (B) Formation are mature source rocks and fall in the stage of oil generation and reach to the late stage of oil generation (R0 = 1.25). On the contrary the Upper Cretaceous formations are ranged from immature to marginally mature source rocks and reach only the early stage of oil generation in Maghrabi Formation. This study indicated that there is still a good chance to find oil generated from the Dakhla, Duwi, Maghrabi, Sabaya and Abu Ballas formations if buried in greater depths as well as, KomOmbo B and A intervals which are source rock potentials.

Evaluation of Eocene source rock for potential shale oil and gas generation in north Cambay Basin, India

Source rock potential of 108 representative samples from 3 m intervals over a 324 m thick shale section of middle Eocene age from the north Cambay Basin, India have been studied. Variation in total organic carbon (TOC) and its relationship with loss on ignition (LOI) have been used for initial screening. Screened samples were subjected to Rock-Eval pyrolysis and organic petrography. A TOC log indicated wide variation with streaks of elevated TOC. A 30 m thick organic-rich interval starting at 1954 m depth, displayed properties consistent with a possible shale oil or gas reservoir. TOC (wt%) values of the selected samples were found to vary from 0.68% to 3.62%, with an average value of 2.2. The modified van Krevelen diagram as well as HI vs. Tmax plot indicate prevalence of Type II to Type III kerogen. Tmax measurements ranged from 425 °C to 439 °C, indicating immature to early mature stage, which was confirmed by the mean vitrinite reflectance values (%Ro of 0.63, 0.65 and 0.67 at 1988 m, 1954 m, and 1963 m, respectively). Quantification of hydrocarbon generation, migration and retention characteristics of the 30 m source rock interval suggests 85% expulsion of hydrocarbon. Oil in place (OIP) resource of the 30 m source rock was estimated to be 3.23 MMbbls per 640 acres. The Oil saturation index (OSI) crossover log showed, from a geochemical perspective, moderate risk for producing the estimated reserve along with well location for tapping the identified resource.

Source Rock Assessment of Naokelekan Formation in Iraqi Kurdistan

The Callovian-Kimeridgian Naokelekan Formation is a heterogeneous sequence consisting principally of bituminous shales with bituminous limestone and dolomitic limestones. It is 48 m thick maximally in some parts of the area. One hundred forty four rock and cutting samples from six outcrops and eight boreholes in different parts of Iraqi Kurdistan have been studied using the Rock-Eval technique with the primary purpose of assessing their potentiality as promising source rocks for petroleum. The outcomes of the Rock-Eval study for examined samples shows that TOC ranges from 0.4 to 18.8 wt. % and types II and III kerogens are the main components of organic matter.Qualitative evaluations are also done by textural microscopy used in assessing amorphous organic matter for palynofacies. The organic matters are mature that have thermal alteration index of 2.6-3.2 by Pearson's scale with palynomorphs of dark orange and light brown colors and Tmax ranges between 434 to 493ºC. Thus the Naokelekan Formation can be considered as a source rock for generation and expulsion of oil and/or gas that has been charged largely oil fields in the area.Maturity increases toward the northeastern part of the studied area. Furthermore, the study revealed that Naokelekan Formation is within dry gas and/or late oil zone in the eastern part, early oil window in the central part and immature in the western part of the studied area.

Gas reservoir characteristics of the Lower Gondwana Shales in Raniganj Basin of Eastern India

In India, Raniganj basin has become a prime target for shale gas exploration. Investigated shale core samples obtained from 9 boreholes during exploratory drilling with laterally varying depth from 11 to 1480m. A substantial amount of organic matter in shale beds having cumulative thickness of 86m, 327m and 126m are found in Raniganj, Barren Measures and Barakar Formations respectively. The total organic content (TOC) of shales signifies poor to excellent (1.01–12.73wt%), while the values of S1 and S2 revealed poor to good source rock generation potential, accentuating thermally immature to moderately mature shale reservoir. The various plots like HI vs. OI, HI vs. TOC, S2 vs. TOC, PI vs. S1 and S2, implies that studied shales are gas prone containing type II/III and type III kerogen except sample no 17, which has shown type IV kerogen owing to effects of nearby igneous intrusive. Comparatively less sorption in Raniganj shales reflecting low TOC content, whereas Barren Measures and Barakar shales has moderate sorption capacities controlled by organic matter and clay minerals. Low pressure N2 adsorption-desorption isotherms are used to categorise pore geometry such as cylindrical, slit-shaped and bottle neck pores in Raniganj, Barren Measures and Barakar shales respectively. Organic content have no significant influence over the surface area, because intensified thermal stress could have caused the destruction of thinner organic pores which reduced the involvement of organic pores in surface area. The pores are classified into four types using scanning electron microscopy (SEM) taking into account the origin, size and shape of pores, i) dissolved pores – developed due to the effect of groundwater or de-carbonic acid, ii) open pores associated with organic matter - formed during thermal cracking of kerogen, iii) Intergranular pores - formed due to incomplete cementation and iv) micro fractures - owed to tectonic movements or structural activities in the basin. The in-situ gas content obtained from canister test varies from 1.937 to 2.307m3/t, 0.378–3.035m3/t and 0.424–1.937m3/t for Raniganj, Barren Measures and Barakar shales respectively however, large cumulative thickness, high TOC, moderate sorption capacity, well developed pore geometry and significant surface area encourages the exploration and production development of shale gas in Raniganj basin. The estimated recoverable shale gas resource is 30.76 billion cubic meter (BCM) for Raniganj, 103.76 BCM for Barren Measures and 41.69 BCM for Barakar shales. This study would help the operators to fulfil the gap of lack of adequate knowledge to develop the shale gas play in this basin.

Organic richness, hydrocarbon potentiality, maturity, and timing of petroleum generation of the Cretaceous and Miocene source rocks in the central Gulf of Suez, Egypt

ABSTRACTTotal organic carbon (TOC) and pyrolysis analysis of the Cretaceous and Miocene source rocks in the central Gulf of Suez were evaluated throughout the 25 rock samples collected from 6 formations, namely Wata, Raha, Nubia “A” (Cretaceous source rocks); and Nukhul, Zeit, and Belayim (Miocene source rocks) from Gharib-252, Gharib-153, Gharib-163, Gharib-164, Gharib-167, and Gharib-165 wells. These data are used to study the probabilities of the source rock in the Cretaceous and Miocene source rocks in the central Gulf of Suez for the hydrocarbon generation through identifying the organic richness, type of organic matters, and thermal maturation of these organic materials. The results revealed that the Cretaceous formations are immature source rocks, ranging from fair to good source rocks and have kerogen of type III and type III/II. Meanwhile, Miocene source rocks, ranging from immature to marginally mature source rocks, are considered to range from good to very good source rocks for potential generation of both oil and gas and are characterized by kerogen of type III/II and type II.

Hydrocarbon maturation modeling of Paleocene to Lower Miocene source rocks in the Niger Delta Basin: implications for hydrocarbon generation

This study evaluates the hydrocarbon generation potentials and time of generation for Paleocene to Lower Miocene source rock horizons from A-1, B-1, B-2, and C-1 wells in the Niger Delta Basin using 1D Petromod modeling software. Wells A-1, B-1 and B-2, and C-1 are located within the Central Swamp, the Coastal Swamp, and the Shallow Offshore depobelts, respectively. The thermal history was derived from the rifting–subsidence heat flow model. Maturity modeling were carried out by using Easy%Ro kinetic model and a heat flow history predicting present-day heat flow which were calibrated with measured temperature data. Results of the study suggest that these potential source rocks have attained maturity status to generate hydrocarbons, with vast differences existing in the timing of the onset of oil generation. Basin modeling suggests that Paleocene source rocks entered the oil generative window from the Oligocene to Miocene times with thermal maturity window that varies from gas generation to early-mature phase. The Eocene source rocks have also attained maturity from Miocene to Pliocene times, and their thermal maturity ranges from gas generation to early maturity stage. The Oligocene source rocks also began to generate oil during the Miocene and are currently within the early-mature to mid-mature stage. The thermal maturity window for the Lower Miocene source rocks ranges from immature to early-mature stage. The present modeling results reveals that higher levels of thermal maturity are attained in areas with high geothermal gradients and heat flow values while the cooler areas exhibits lower levels of maturation. The onset of the oil window lies at 2859 m at A-1 (Central Swamp), 3240 m at B-2 (Coastal Swamp), 4732 m at B-1 (Coastal Swamp), and 4344 m at C-1 (Shallow Offshore). The depth to the onset of oil window is found deeper in the Shallow Offshore and western parts of the study area than in the eastern and northwestern parts. The result of this study suggest that the Paleocene, Eocene, Oligocene, and Lower Miocene source rocks are the principal source rocks for oil and gas generation in the Niger Delta Basin.

Characterization of the source rocks of a paleo-petroleum system (Cameros Basin) based on organic matter petrology and geochemical analyses

The Cameros Basin is a paleo-petroleum system formed in the north-eastern Iberian Peninsula. The basin formed during the Mesozoic Iberian Rift and was later inverted during the Alpine orogeny. Hydrothermal events took place during the post-extensional and inversion stages, producing an important impact on the thermal history of the basin. In order to determine the source rock of the petroleum system of the basin, organic matter characteristics, the petroleum generation potential and the maturity of the basin infill are determined by means of petrology and geochemical analyses.Several organic rich units of the stratigraphic record of the basin are potential source rocks for hydrocarbons generation, although their characteristics differ depending on their location. Organic matter content in the northern sector is scarce and limited to vitrinite, inertinite and solid bitumen particles. The residual total organic carbon (TOC < 1%), the low hydrocarbon potential (S2 < 0.3 mg HC/g rock, HI < 50 mg HC/g TOC), the mature to overmature thermal stages (%Ro from 1.7 to 4.6) and the presence of solid bitumen particles indicate that hydrocarbons have been already generated by these rocks. In contrast, the southern sector of the basin is characterized by abundant organic matter remnants (TOC from 2 to 17%) and immature to early oil-window thermal conditions (0.38–0.75%Ro), indicating a high hydrocarbon potential for these rocks (S2 from 11 to 123 mg HC/g and HI values from 23 to 715 mg HC/g TOC).The different evolution of the source rocks in the basin is the result of the combination of differential subsidence rates, which determine different thermal histories and of the circulation of hydrothermal fluids in the northern-central sector during the evolution of the basin.

Constraining Late Cretaceous exhumation in the Eromanga Basin using sonic velocity data

Exhumation in sedimentary basins can have significant consequences for their petroleum systems. For example, source rocks may be more mature than their present-day burial depths suggest, increased compaction can result in reduced reservoir quality, and seal integrity problems are commonly encountered. The Eromanga Basin in central Australia experienced an important phase of exhumation during the Late Cretaceous, though the magnitude and spatial distribution of exhumation is poorly constrained. In this study exhumation magnitudes have been determined for 100 petroleum wells based on sonic transit time analyses of fine grained shales, siltstones and mudstones within selected Cretaceous stratigraphic units. Observed sonic transit times are compared to normal compaction trends (NCTs) determined for suitable stratigraphic units. The Winton Formation and the Bulldog Shale/Wallumbilla Formation were chosen for analysis in this study for their homogenous, fine-grained and laterally extensive properties. Exhumation magnitudes for these stratigraphic units are statistically similar. Results show net exhumation in the southern Cooper-Eromanga Basin (&lt;500 m [~1,640 ft]) and higher net exhumation magnitudes (up to 1,400 m [~3,937 ft]) being recorded in the northeastern margins of the basin. Gross exhumation magnitudes show significant variation across short distances suggesting different tectonic processes acting upon the basin. Independent vitrinite reflectance and apatite fission track analysis data, available for a subset of wells, give statistically similar exhumation magnitudes to those that have been calculated through the compaction methodology, giving confidence in these results. The effect on source rock generation is illustrated through 1D basin modelling where exhumation is shown to impact the timing and type of the hydrocarbons generated. The improved quantification of this exhumation permits a better understanding of the Late Cretaceous tectonics and palaeogeography of central Australia.

Multivariate geochemical and statistical methods applied to assessment of organic matter potentiality and its correlation with hydrocarbon maturity parameters (Case study: Safir-1x well, North Western Desert, Egypt)

The TOC-Rock–Eval pyrolysis and vitrinite reflectance measurements for “15” shale rock samples, as well as, multivariate statistical analysis are discussed to investigate hydrocarbon, source rock characteristics, correlation between the assessed parameters (S1, S2, HI, S1+S2, QI, BI, PI, TOC) and the impact of changes in the Tmax and Ro% on the assessed parameters in Safir exploratory-1x well in Safir oilfield. The geochemical analysis indicated that the Bahariya Formation is considered to be a poor source rock for oil generation with a low degree of thermal maturation in comparison with the Alam El Bueib and Khatatba Formations. However, Alam El Bueib is found to be a good source rock for oil generation with slightly higher thermal maturation. Interestingly, Khatatba Formation lies within the oil and gas generation window and shows an excellent source rock potential. Based on statistical findings of cluster and factor analysis, the source rocks in the study area are classified into two types corresponding to two different clusters. Cluster I includes Alam El Bueib and characterized by kerogen type II and II/III whereas, cluster II, characterized by kerogen type III, is subdivided into two subgroups (IIa and IIb) and represents Bahariya and Khatatba source rocks. Nonparametric tests (K-independent samples) between the dataset of 15 samples confirm that the distribution of values from respective parameters exhibits significant difference (P<0.05) except for PI and BI. On the other hand, the nonparametric tests (2-independent samples) showed that there is no significant difference (P>0.05) in the distribution of HI and QI values indicating that both HI and QI values remain constant with increasing thermal maturity. Unlike TOC and HI, Pearson’s and linear regression analysis indicated a significant correlation between TOC and S2. Nevertheless, two different trends were observed between S1 and S2. Moreover, the Ro% and Tmax were found to be positively correlated. Interestingly, our study showed no significant correlation between HI, QI, BI and thermal maturity (Ro% and Tmax), while, a good correlation between TOC, S2 and thermal maturity was observed.

Petroleum potential and kinetic models for hydrocarbon generation from the Upper Cretaceous to Paleogene Latrobe Group coals and shales in the Gippsland Basin, Australia

Pyrolysis experiments (open and closed systems) and kinetic modelling of primary cracking of kerogen have been carried out to investigate hydrocarbon generation characteristics and source rock facies variability within the Upper Cretaceous to Paleogene Latrobe Group in the Gippsland Basin. On the basis of Rock-Eval data, the interbedded coals, coaly shales and carbonaceous shales contain different types of kerogen (Type III, Type II–III, Type II) with variable potential for both gas and liquid hydrocarbon generation. Open system pyrolysis–gas chromatography data indicate that the organically lean marginal marine shales of the Santonian–early Campanian Tricolporites apoxyexinus and Nothofagidites senectus biozones produce gas and condensate. However, coal and coaly to carbonaceous shales sampled from the Paleocene Lygistepollenites balmei, Maastrichtian Forcipites longus, late Campanian Tricolporites lilliei and Turonian Phyllocladidites mawsonii palynological biozones are heterogeneous with the capacity to generate both low and high wax paraffinic–naphthenic–aromatic (P–N–A) oils, and paraffinic oils with a high wax content. The main phase of petroleum formation from these later biozones, assuming a constant geological heating rate of 3.3°C/Ma, is predicted to occur between 150–179°C, indicating different orders of kinetic stability as a result of different types of organic matter and their state of preservation. The thermally immature shales have variable bulk kinetic characteristics, but the measured compositional kinetics and phase behaviour show that they have the potential to generate black oils at early stages of kerogen cracking, and either light oils or wet gases at higher levels of thermal stress. These findings suggest that upon thermal maturation, the interbedded shales of the Latrobe Group may have contributed significant volumes of hydrocarbons to the oil and gas accumulations in the Gippsland Basin. In addition, this study not only supports the premise that over-reliance on Rock-Eval/TOC data alone can be misleading for assessment of petroleum generation, but also represents a strategy for kerogen type and generative potential determination for fluvio-deltaic coals and subordinate lithologies.

English

The present study evaluates the petroleum source rock generation potential of the Neogene Bhuban shales from Bangladesh. Organic geochemical and organic petrological methods were used for analyzing 11 drill core samples from 4 gas fields in the basin. Source rock potential, maceral composition, organic matter abundance, biomarker distribution, thermal maturity, hydrocarbon generation and depositional environment were evaluated. Kerogen in the studied shale samples is classified mainly as Type III with lesser amounts of Type II. Vitrinite is the dominant maceral group observed in the analyzed Bhuban samples followed by liptinite and inertinite. Vitrinite reflectance, Tmax and biomarker parameters indicate the thermal maturity ranges from just pre-oil window to mid-oil window. Based on its total organic carbon (TOC), extractable organic matter (EOM) and hydrogen index (HI), the analyzed Bhuban shales are ranked as mainly poor to fair source rocks but with good gas generation potential. The dominant terrestrial environment prevailed during the deposition of the studied Bhuban shales while the condition was sub-oxic as indicated by cross-plots of pristane versus phytane and sterane versus pristane/phytane ratios.

Seismic evidence of continental margin influence on the NinetyEast Ridge in the Bay of Bengal

AbstractThe NinetyEast Ridge (NER), one of the most enigmatic features in the Indian Ocean, is covered by thick Bengal Fan sediment north of 9°N. We present seismic reflection data on the eastern flank of the NER, at 10°N, that show the presence of 4–5 km thick sediments beneath the Bengal Fan sediments. These sediments can be imaged up to 60 km beneath the Andaman fore‐arc accretionary wedge, suggesting that the décollement lies above these sediments. The presence of thick sediments above the northernmost segment of the NER suggests that this segment was close to a continental margin during its emplacement. We propose that these sediments were deposited soon after the breakup of India and Antarctica, between 130 and 100 Ma, and might act as source rocks for oil and gas generation beneath recent Bengal Fan sediments. Furthermore, subducting thick sediments can significantly change the seismogenic behavior of the Andaman subduction zone.

Neural networks and their derivatives for history matching and reservoir optimization problems

In geosciences, complex forward problems met in geophysics, petroleum system analysis, and reservoir engineering problems often require replacing these forward problems by proxies, and these proxies are used for optimizations problems. For instance, history matching of observed field data requires a so large number of reservoir simulation runs (especially when using geostatistical geological models) that it is often impossible to use the full reservoir simulator. Therefore, several techniques have been proposed to mimic the reservoir simulations using proxies. Due to the use of experimental approach, most authors propose to use second-order polynomials. In this paper, we demonstrate that (1) neural networks can also be second-order polynomials. Therefore, the use of a neural network as a proxy is much more flexible and adaptable to the nonlinearity of the problem to be solved; (2) first-order and second-order derivatives of the neural network can be obtained providing gradients and Hessian for optimizers. For inverse problems met in seismic inversion, well by well production data, optimal well locations, source rock generation, etc., most of the time, gradient methods are used for finding an optimal solution. The paper will describe how to calculate these gradients from a neural network built as a proxy. When needed, the Hessian can also be obtained from the neural network approach. On a real case study, the ability of neural networks to reproduce complex phenomena (water cuts, production rates, etc.) is shown. Comparisons with second polynomials (and kriging methods) will be done demonstrating the superiority of the neural network approach as soon as nonlinearity behaviors are present in the responses of the simulator. The gradients and the Hessian of the neural network will be compared to those of the real response function.

Main Controlled Elements for Accumulation of Ultro-Low Permeability Sandstone Oil Reservoir, Zhenjing Oilfield, Ordas Basin

Ordos Basin is the second largest sedimentary basin in China with very rich oil and gas resources. The exploration targets are typical reservoirs of low permeability. To determine the accumulation mechanism of tight sandstone reservoir, thin section, SEM, numerical calculation were used. The result showed that sandstone should be ultro-low permeability reservoirs with the high content feldspar and lithic arkose or feldspathic litharenite. The reservoir became tight while oil filling, buoyant force is too small to overcome the resistance of capillary force. Therefore, overpressure induced by source rock generation is the accumulation drive force.

Accumulation Mechanism of Ultro-Low Permeability Sandstone Reservoir, Huaqing Oilfield, Ordas Basin

Ordos Basin is the second largest sedimentary basin in China with very rich oil and gas resources. The exploration targets are typical reservoirs of low permeability, low pressure and low output. To determine the accumulation mechanism of tight sandstone reservoir, thin section, fluid inclusion, porosity and permeability measurement, numerical calculation were used. The result showed that sandstone became tight while oil filling, buoyant force is too small to overcome the resistance of capillary force. Therefore, overpressure induced by source rock generation is the accumulation drive force.

Origin and thermal maturity of the organic matter in the Lower Palaeozoic rocks of the Pomeranian Caledonides and their foreland (northern Poland)

The clayey-muddy complex of the Ordovician and Silurian age in the Pomeranian Caledonides belt as well as the Cambrian, Ordovician and Silurian rocks at its foreland (the East European Craton) contain the same genetical type of the organic matter dominated by the syngenetic sapropelic material (oil-prone). The intensity and character of the thermal alterations in both stable organic matter mobile components show distinct analogies despite the different tectonic involvement of both regions. The reflectivity index of the vitrinite-like minerals shows an increase with a burial depth of the successive members of the Lower Palaeozoic. The local increase in thermal alteration of the organic matter is related to the zones of the increased tectonic activity. Assuming that the maximum burial depth of the studied sediments corresponds to their present depth, it can be concluded that the thermal palaeogradient for the Early Palaeozoic in the Pomeranian region was higher than the present-day one. The range of maximum palaeotemperatures which influenced the Lower Palaeozoic complex is very wide ranging from about 70 to 200oC in the Caledonian zone. The analysed deposits do not show a good quality as potential source rocks for hydrocarbon generation. Their low generation potential is probably caused by an earlier generation of a part of hydrocarbons.

Upper Paleozoic coal measures and unconventional natural gas systems of the Ordos Basin, China

Upper Paleozoic coal measures in the Ordos Basin consist of dark mudstone and coal beds and are important source rocks for gas generation. Gas accumulations include coal-bed methane (CBM), tight gas and conventional gas in different structural areas. CBM accumulations are mainly distributed in the marginal area of the Ordos Basin, and are estimated at 3.5 × 1012 m3. Tight gas accumulations exist in the middle part of the Yishan Slope area, previously regarded as the basin-centered gas system and now considered as stratigraphic lithologic gas reservoirs. This paper reviews the characteristics of tight gas accumulations: poor physical properties (porosity < 8%, permeability < 0.85 × 10−3 μm2), abnormal pressure and the absence of well-defined gas water contacts. CBM is a self-generation and self-reservoir, while gas derived from coal measures migrates only for a short distance to accumulate in a tight reservoir and is termed near-generation and near-reservoir. Both CBM and tight gas systems require source rocks with a strong gas generation ability that extends together over wide area. However, the producing area of the two systems may be significantly different.

Modeling of the tight sandstone gas accumulation for the Xujiahe Formation, Hechuan-Tongnan Area, Sichuan Basin

Abstract The tight sandstone gas accumulation is mainly driven by overpressure arising from the gas generation in source rocks. This paper proposes a quantitative computation model for the pressurization from gas generation in source rocks, establishes a dynamic equilibrium equation and a modeling process for tight sandstone gas accumulation, and simulates the gas generation quantity and source rock overpressure history in the Hechuan-Tongnan area of the Sichuan Basin. The modeling reveals that: (1) The gas generation intensity determines the degree of pressurization from gas generation, whereas the reservoir property determines the distribution of gas reservoirs; the conventional gas reservoir is complementary with the tight sandstone gas reservoir in terms of horizontal and vertical distribution, the former is mainly distributed at the top of reservoir with porosity over 7% on local structural highs while the latter is mainly distributed at the bottom of reservoir on local structural lows near source rocks of large gas generation quantity. (2) During the uplifting process from the maximum burial depth (65 Ma) to the current burial depth, because of the pressure drop of formation water and the increase of gas-water pressure difference, the tight sandstone gas migrates farther and increases in accumulation quantity; however, the conventional gas does not migrate basically and has no increase in accumulation quantity; (3) The quantity of the tight sandstone gas in the T3x2 is 5.9 times that of the conventional gas, and the undiscovered resource is mainly tight sandstone gas distributed in northeast of Hechuan, and north and southeast of Tongnan.

Late Cretaceous paleoenvironment and lake level fluctuation in the Songliao Basin, northeastern China

AbstractStudy of Late Cretaceous lacustrine sedimentary strata in the eastern Songliao Basin, China revealed that the paleoclimate was relatively arid and hot during sedimentation of the upper Santonian of the Yaojia Formation, but became relatively humid and warm during deposition of the lower Campanian Nenjiang Formation. The upper Yaojia Formation was deposited in a freshwater lake environment, while the lower Nenjiang Formation was deposited in a slightly brackish to brackish environment. The average total organic carbon content in the upper Yaojia Formation is 0.15%, while the hydrogen index is 36 mgHC/gTOC, implying poor source rock for oil generation and the organic matter comprised of a mixture of woody and herbaceous organic matter. In contrast, the hydrogen index of oil shale and black shale of the lower Nenjiang Formation is 619 mgHC/gTOC, and total organic carbon content on average is 3.37%, indicating a mixed algae and herbaceous source of kerogen and an increase in aquatic bioproductivity. The black shale and oil shale have low Pristane/Phytane and C29 5α,14α,17α(H) − stigmastane 20R/(20R + 20S) ratios, with maximum concentration of n‐alkanes at n‐C23, implying an anoxic depositional environment with algae, bacteria and higher plants providing most of the organic matter. Relatively abundant gammacerane and a higher Sr/Ba ratio in the oil shales suggest the presence of brackish water and development of salinity stratification in the lake. During sedimentation of the upper Yaojia through the lower Nenjiang Formations, the level of Songliao lake increased and a deep‐lake environment was formed with bottom waters being oxygen depleted. Concomitantly, as the lake deepened bottom conditions were changing from oxic to anoxic, and the input of organic matter changed from predominantly higher plants to a mixture of bacteria, algae and higher plants providing favorable conditions for oil source rock accumulation.

Pyrolysis and Catalyzed Pyrolysis in the Investigation of a Neogene Shale Potential from Valjevo-Mionica Basin, Serbia

The generative potential of a Neogene shale from Valjevo-Mionica Basin (Serbia) was investigated using conventional pyrolysis and pyrolysis in the presence of Pt(IV)- and Ru(III)-ions at temperatures 250 and 400 °C. Total liquid pyrolysate and hydrocarbon yields obtained in pyrolytic experiments, group composition of liquid pyrolysates, and distributions of saturated biomarkers and alkylaromatics in pyrolysates showed that the shale is in a catagenetic stage and may be a source of liquid hydrocarbons. It was estimated that similar shales found at a depth of 2300−2900 m would become active oil generating source rock where the minimum temperature necessary for catagenetic hydrocarbon generation is between 103 and 107 °C. The used metal ions, demonstrated significant positive effects on the yields of total liquid pyrolysate and corresponding hydrocarbons, at both temperatures 250 and 400 °C. Comparison of the results of alkylaromatics maturity parameters with maturity ratios calculated from distribution and ...