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1.
Cretaceous sedimentary rocks of the Mukalla, Harshiyat and Qishn formations from three wells in the Jiza sub-basin were studied to describe source rock characteristics, providing information on organic matter type, paleoenvironment of deposition and hydrocarbon generation potential. This study is based on organic geochemical and petrographic analyses performed on cuttings samples. The results were then incorporated into basin models in order to understand the burial and thermal histories and timing of hydrocarbon generation and expulsion.The bulk geochemical results show that the Cretaceous rocks are highly variable with respect to their genetic petroleum generation potential. The total organic carbon (TOC) contents and petroleum potential yield (S1 + S2) of the Cretaceous source rocks range from 0.43 to 6.11% and 0.58–31.14 mg HC/g rock, respectively indicating non-source to very good source rock potential. Hydrogen index values for the Early to Late Cretaceous Harshiyat and Qishn formations vary between 77 and 695 mg HC/g TOC, consistent with Type I/II, II-III and III kerogens, indicating oil and gas generation potential. In contrast, the Late Cretaceous Mukalla Formation is dominated by Type III kerogen (HI < 200 mg HC/g TOC), and is thus considered to be gas-prone. The analysed Cretaceous source rock samples have vitrinite reflectance values in the range of 0.37–0.95 Ro% (immature to peak-maturity for oil generation).A variety of biomarkers including n-alkanes, regular isoprenoids, terpanes and steranes suggest that the Cretaceous source rocks were deposited in marine to deltaic environments. The biomarkers also indicate that the Cretaceous source rocks contain a mixture of aquatic organic matter (planktonic/bacterial) and terrigenous organic matter, with increasing terrigenous influence in the Late Cretaceous (Mukalla Formation).The burial and thermal history models indicate that the Mukalla and Harshiyat formations are immature to early mature. The models also indicate that the onset of oil-generation in the Qishn source rock began during the Late Cretaceous at 83 Ma and peak-oil generation was reached during the Late Cretaceous to Miocene (65–21 Ma). The modeled hydrocarbon expulsion evolution suggests that the timing of oil expulsion from the Qishn source rock began during the Miocene (>21 Ma) and persisted to present-day. Therefore, the Qishn Formation can act as an effective oil-source but only limited quantities of oil can be expected to have been generated and expelled in the Jiza sub-basin. 相似文献
2.
The quality of source rocks plays an important role in the distribution of tight and conventional oil and gas resources. Despite voluminous studies on source rock hydrocarbon generation, expulsion and overpressure, a quality grading system based on hydrocarbon expulsion capacity is yet to be explored. Such a grading system is expected to be instrumental for tight oil and gas exploration and sweet spot prediction. This study tackles the problem by examining Late Cretaceous, lacustrine source rocks of the Qingshankou 1 Member in the southern Songliao Basin, China. By evaluating generated and residual hydrocarbon amounts of the source rock, the extent of hydrocarbon expulsion is modelled through a mass balance method. The overpressure is estimated using Petromod software. Through correlation between the hydrocarbon expulsion and source rock evaluation parameters [total organic carbon (TOC), kerogen type, vitrinite reflectance (Ro) and overpressure], three classes of high-quality, effective and ineffective source rocks are established. High-quality class contains TOC >2%, type-I kerogen, Ro >1.0%, overpressure >7Mpa, sharp increase of hydrocarbon expulsion along with increasing TOC and overpressure, and high expulsion value at Ro >1%. Source rocks with TOC and Ro <0.8%, type-II2 & III kerogen, overpressure <3Mpa, and low hydrocarbon expulsion volume are considered ineffective. Rocks with parameters between the two are considered effective. The high-quality class shows a strong empirical control on the distribution of tight oil in the Songliao Basin. This is followed by the effective source rock class. The ineffective class has no measurable contribution to the tight oil reserves. Because the hydrocarbon expulsion efficiency of source rocks is controlled by many factors, the lower limits of the evaluation parameters in different basins may vary. However, the classification method of tight source rocks proposed in this paper should be widely applicable. 相似文献
3.
In recent years, new oil reservoirs have been discovered in the Eocene tight sandstone of the Huilu area, northern part of the Pearl River Mouth basin, South China Sea, indicating good prospects for tight oil exploration in the area. Exploration has shown that the Huilu area contains two main sets of source rocks: the Eocene Wenchang (E2w) and Enping (E2e) formations. To satisfy the requirements for further exploration in the Huilu area, particularly for tight oil in Eocene sand reservoirs, it is necessary to re-examine and analyze the hydrocarbon generation and expulsion characteristics. Based on mass balance, this study investigated the hydrocarbon generation and expulsion characteristics as well as the tight oil resource potential using geological and geochemical data and a modified conceptual model for generation and expulsion. The results show that the threshold and peak expulsion of the E2w source rocks are at 0.6% vitrinite reflectance and 0.9% vitrinite reflectance, respectively. There were five hydrocarbon expulsion centers, located in the western, eastern, and northern Huizhou Sag and the southern and northern Lufeng Sag. The hydrocarbon yields attributed to E2w source rocks are 2.4 × 1011 tons and 1.6 × 1011 tons, respectively, with an expulsion efficiency of 65%. The E2e source rock threshold and peak expulsion are at 0.65% vitrinite reflectance and 0.93% vitrinite reflectance, respectively, with hydrocarbon expulsion centers located in the centers of the Huizhou and Lufeng sags. The yields attributed to E2e source rocks are 1.1 × 1011 tons and 0.2 × 1011 tons, respectively, with an expulsion efficiency of 20%. Using an accumulation coefficient of 7%–13%, the Eocene tight reservoirs could contain approximately 1.3 × 1010 tons to 2.3 × 1010 tons, with an average of 1.8 × 1010 tons, of in-place tight oil resources (highest recoverable coefficient can reach 17–18%), indicating that there is significant tight oil potential in the Eocene strata of the Huilu area. 相似文献
4.
There are two sets of carbonate source rocks in the Lower Carboniferous layers in Marsel: the Visean (C1v) and Serpukhovian (C1sr). However, their geochemical and geological characteristics have not been studied systematically. To assess the source rocks and reveal the hydrocarbon generation potential, the depositional paleoenvironment and distribution of C1v and C1sr source rocks were studied using total organic carbon (TOC) content, Rock-Eval pyrolysis and vitrinite reflectance (Ro) data, stable carbon isotope data, gas chromatography (GC) and gas chromatography-mass spectrometry (GC-MS) analysis data. The data were then compared with well logging data to understand the distribution of high-quality source rocks. The data were also incorporated into basin models to reveal the burial and thermal histories and timing of hydrocarbon generation. The results illustrated that the average residual TOC contents of C1v and C1sr were 0.79% and 0.5%, respectively, which were higher than the threshold of effective carbonate source rocks. Dominated by type-III kerogen, the C1v and C1sr source rocks tended to be gas-bearing. The two source rocks were generally mature to highly mature; the average Ro was 1.51% and 1.23% in C1v and C1sr, respectively. The source rocks were deposited in strongly reducing to weakly oxidizing marine–terrigenous environments, with most organic material originating from higher terrigenous plants and a few aquatic organisms. During the Permian, the deep burial depth and high heat flow caused a quick and high maturation of the source rocks, which were subsequently uplifted and eroded, stopping the generation and expulsion of hydrocarbons in the C1v and C1sr source rocks. The initial TOC fitted by the △logR method was recovered, and it suggests that high-quality source rocks (TOC ≥ 1%) are mainly distributed in the northern and central local structural belt. 相似文献
5.
Two petroleum source rock intervals of the Lower Cretaceous Abu Gabra Formation at six locations within the Fula Sub-basin, Muglad Basin, Sudan, were selected for comprehensive modelling of burial history, petroleum maturation and expulsion of the generated hydrocarbons throughout the Fula Sub-basin. Locations (of wells) selected include three in the deepest parts of the area (Keyi oilfield); and three at relatively shallow locations (Moga oilfield). The chosen wells were drilled to depths that penetrated a significant part of the geological section of interest, where samples were available for geochemical and source rock analysis. Vitrinite reflectances (Ro %) were measured to aid in calibrating the developed maturation models.The Abu Gabra Formation of the Muglad Basin is stratigraphically subdivided into three units (Abu Gabra-lower, Abu Gabra-middle and Abu Gabra-upper, from the oldest to youngest). The lower and upper Abu Gabra are believed to be the major source rocks in the province and generally contain more than 2.0 wt% TOC; thus indicating a very good to excellent hydrocarbon generative potential. They mainly contain Type I kerogen. Vitrinite reflectance values range from 0.59 to 0.76% Ro, indicating the oil window has just been reached. In general, the thermal maturity of the Abu Gabra source rocks is highest in the Abu Gabra-lower (deep western part) of the Keyi area and decreases to the east toward the Moga oilfied at the Fula Sub-basin.Maturity and hydrocarbon generation modelling indicates that, in the Abu Gabra-Lower, early oil generation began from the Middle- Late Cretaceous to late Paleocene time (82.0–58Ma). Main oil generation started about 58 Ma ago and continues until the present day. In the Abu Gabra-upper, oil generation began from the end of the Cretaceous to early Eocene time (66.0–52Ma). Only in one location (Keyi-N1 well) did the Abu Gabra-upper reach the main oil stage. Oil expulsion has occurred only from the Abu Gabra-lower unit at Keyi-N1 during the early Miocene (>50% transformation ratio TR) continuing to present-day (20.0–0.0 Ma). Neither unit has generated gas. Oil generation and expulsion from the Abu Gabra source rocks occurred after the deposition of seal rocks of the Aradeiba Formation. 相似文献
6.
Understanding the hydrocarbon accumulation pattern in unconventional tight reservoirs is crucial for hydrocarbon evaluation and oil/gas extraction from such reservoirs. Previous studies on tight oil accumulation are mostly concerned with self-generation or from source to reservoir rock over short distances. However, the Lucaogou tight oil in Jimusar Sag of Junggar Basin shows transitional feature in between. The Lucaogou Formation comprises fine-grain sedimentary rocks characterized by thin laminations and frequently alternating beds. The Lucaogou tight silt/fine sandstones are poorly sorted. Dissolved pores are the primary pore spaces, with average porosity of 9.20%. Although the TOC of most silt/fine sandstones after Soxhlet extraction is lower than that before extraction, they show that the Lucaogou siltstones in the area of study have fair to good hydrocarbon generation potential (average TOC of 1.19%, average S2 of 4.33 mg/g), while fine sandstones are relatively weak in terms of hydrocarbon generation (average TOC of 0.4%, average S2 of 0.78 mg/g). The hydrocarbon generation amount of siltstones, which was calculated according to basin modeling transformation ratio combined with original TOC based on source rock parameters, occupies 16%–72% of oil retention amount. Although siltstones cannot produce the entire oil reserve, they certainly provide part of them. Grain size is negatively correlated with organic matter content in the Lucaogou silt/fine sandstones. Fine grain sediments are characterized by lower deposition rate, stronger adsorption capacity and oxidation resistance, which are favorable for formation of high quality source rocks. Low energy depositional environment is the primary reason for the formation of siltstones containing organic matter. Positive correlation between organic matter content and clay content in Lucaogou siltstones supports this view point. Lucaogou siltstones appear to be effective reservoir rocks due to there relatively high porosity, and also act as source rocks due to the fair to good hydrocarbon generation capability. 相似文献
7.
《Marine and Petroleum Geology》2012,33(1):21-35
The petroleum generation and charge history of the northern Dongying Depression, Bohai Bay Basin was investigated using an integrated fluid inclusion analysis workflow and geohistory modelling. One and two-dimensional basin modelling was performed to unravel the oil generation history of the Eocene Shahejie Formation (Es3 and Es4) source rocks based on the reconstruction of the burial, thermal and maturity history. Calibration of the model with thermal maturity and borehole temperature data using a rift basin heat flow model indicates that the upper interval of the Es4 source rocks began to generate oil at around 35 Ma, reached a maturity level of 0.7% Ro at 31–30 Ma and a peak hydrocarbon generation at 24–23 Ma. The lower interval of the Es3 source rocks began to generate oil at around 33–32 Ma and reached a maturity of 0.7% Ro at about 27–26 Ma. Oil generation from the lower Es3 and upper Es4 source rocks occurred in three phases with the first phase from approximately 30–20 Ma; the second phase from approximately 20–5 Ma; and the third phase from 5 Ma to the present day. The first and third phases were the two predominant phases of intense oil generation.Samples from the Es3 and Es4 reservoir intervals in 12 wells at depth intervals between 2677.7 m and 4323.0 m were investigated using an integrated fluid inclusion workflow including petrography, fluorescence spectroscopy and microthermometry to determine the petroleum charge history in the northern Dongying Depression. Abundant oil inclusions with a range of fluorescence colours from near yellow to near blue were observed and were interpreted to represent two episodes of hydrocarbon charge based on the fluid inclusion petrography, fluorescence spectroscopy and microthermometry data. Two episodes of oil charge were determined at 24–20 Ma and 4–3 Ma, respectively with the second episode being the predominant period for the oil accumulation in the northern Dongying Depression. The oil charge occurred during or immediately after the modelled intense oil generation and coincided with a regional uplift and a rapid subsidence, suggesting that the hydrocarbon migration from the already overpressured source rocks may have been triggered by the regional uplift and rapid subsidence. The expelled oil was then charged to the already established traps in the northern Dongying Depression. The proximal locations of the reservoirs to the generative kitchens and the short oil migration distance facilitate the intimate relationship between oil generation, migration and accumulation. 相似文献
8.
Reinhard Gratzer Achim BechtelReinhard F. Sachsenhofer Hans-Gert LinzerDoris Reischenbacher Hans-Martin Schulz 《Marine and Petroleum Geology》2011,28(6):1171-1186
The Alpine Foreland Basin is a minor oil and moderate gas province in central Europe. In the Austrian part of the Alpine Foreland Basin, oil and minor thermal gas are thought to be predominantly sourced from Lower Oligocene horizons (Schöneck and Eggerding formations). The source rocks are immature where the oil fields are located and enter the oil window at ca. 4 km depth beneath the Alpine nappes indicating long-distance lateral migration. Most important reservoirs are Upper Cretaceous and Eocene basal sandstones.Stable carbon isotope and biomarker ratios of oils from different reservoirs indicate compositional trends in W-E direction which reflect differences in source, depositional environment (facies), and maturity of potential source rocks. Thermal maturity parameters from oils of different fields are only in the western part consistent with northward displacement of immature oils by subsequently generated oils. In the eastern part of the basin different migration pathways must be assumed. The trend in S/(S + R) isomerisation of ααα-C29 steranes versus the αββ (20R)/ααα (20R) C29 steranes ratio from oil samples can be explained by differences in thermal maturation without involving long-distance migration. The results argue for hydrocarbon migration through highly permeable carrier beds or open faults rather than relatively short migration distances from the source. The lateral distance of oil fields to the position of mature source rocks beneath the Alpine nappes in the south suggests minimum migration distances between less than 20 km and more than 50 km.Biomarker compositions of the oils suggest Oligocene shaly to marly successions (i.e. Schoeneck, Dynow, and Eggerding formations) as potential source rocks, taking into account their immature character. Best matches are obtained between the oils and units a/b (marly shale) and c (black shale) of the “normal” Schöneck Formation, as well as with the so-called “Oberhofen Facies”. Results from open system pyrolysis-gas chromatography of potential source rocks indicate slightly higher sulphur content of the resulting pyrolysate from unit b. The enhanced dibenzothiophene/phenanthrene ratios of oils from the western part of the basin would be consistent with a higher contribution of unit b to hydrocarbon expulsion in this area. Differences in the relative contribution of sedimentary units to oil generation are inherited from thickness variations of respective units in the overthrusted sediments. The observed trend towards lighter δ13C values of hydrocarbon fractions from oil fields in a W-E direction are consistent with lower δ13C values of organic matter in unit c. 相似文献
9.
The Triassic formation is a possible new giant hydrocarbon generated formation in Northwest China and Mid-Asia. Taking the Upper Triassic formation in the Sikeshu Sag in Junggar Basin as an example, based on the comprehensive analysis on the geochemical characteristics of the cores and the dark mudstone of the outcrops and reservoir formation conditions, we have evaluated the Upper Triassic source rocks by comparing with those in the Ulungu Depression, and reached the following findings. Firstly, the Upper Triassic formation is mainly composed of dark mudstone and sandy mudstone deposits, and the hydrocarbon source rock is mainly distributed in the middle and upper parts with a thickness range of 100–150 m and area of 3500 km2. Secondly, the source rock, moderate in organic matter abundance (with TOC range of 1%–3%), has the material basis for hydrocarbon generation. Thirdly, the organic matter has high percentage of sapropelinite, and is dominated by type II2. Fourthly, the degree of the thermal evolution is moderate, and the source rock with Ro higher than 0.7% has a distribution area of about 1800 km2, providing the conditions of massive hydrocarbon generation. Fifthly, the source rock has great burial depth and wide distribution; the source rock with a Ro of higher than 0.7% and thickness of more than 100 m has an area of around 1400 km2, implying huge resource potential. Sixthly, the next step exploration should focus on highly mature hydrocarbon generation central area in the Upper Triassic - Lower Jurassic in the east of the sag to search for and confirm favorable traps. The research findings have important reference value for promoting the resource status of, deepening the understanding of reservoir formation, and clarifying the exploration direction in the Sikeshu Sag and other periphery Mid-Asia areas. 相似文献
10.
Geochemical characteristics and hydrocarbon generation modeling of the Jurassic source rocks in the Shoushan Basin, north Western Desert, Egypt 总被引：1，自引：0，他引：1
Mohamed Ragab ShalabyMohammed Hail Hakimi Wan Hasiah Abdullah 《Marine and Petroleum Geology》2011,28(9):1611-1624
The Shoushan Basin is an important hydrocarbon province in the Western Desert, Egypt, but the origin of the hydrocarbons is not fully understood. In this study, organic matter content, type and maturity of the Jurassic source rocks exposed in the Shoushan Basin have been evaluated and integrated with the results of basin modeling to improve our understanding of burial history and timing of hydrocarbon generation. The Jurassic source rock succession comprises the Ras Qattara and Khatatba Formations, which are composed mainly of shales and sandstones with coal seams. The TOC contents are high and reached a maximum up to 50%. The TOC values of the Ras Qattara Formation range from 2 to 54 wt.%, while Khatatba Formation has TOC values in the range 1-47 wt.%. The Ras Qattara and Khatatba Formations have HI values ranging from 90 to 261 mgHC/gTOC, suggesting Types II-III and III kerogen. Vitrinite reflectance values range between 0.79 and 1.12 VRr %. Rock−Eval Tmax values in the range 438-458 °C indicate a thermal maturity level sufficient for hydrocarbon generation. Thermal and burial history models indicate that the Jurassic source rocks entered the mature to late mature stage for hydrocarbon generation in the Late Cretaceous to Tertiary. Hydrocarbon generation began in the Late Cretaceous and maximum rates of oil with significant gas have been generated during the early Tertiary (Paleogene). The peak gas generation occurred during the late Tertiary (Neogene). 相似文献
11.
The evaporite-cored Hoodoo Dome on southern Ellef Ringnes Island, Sverdrup Basin, was examined to improve the understanding of its structural geological history in relation to hydrocarbon migration. Data from geological mapping, reflection seismic, thermal maturity and detrital apatite (U–Th)/He cooling ages are presented. Five stages of diapirism are interpreted from Jurassic to Recent times:1. 180 to 163 Ma (pre-Deer Bay Formation; development of a diapir with a circular map pattern).2. 163 to 133 Ma (Deer Bay to lower Isachsen formations; development of salt wings).3. 115 to 94 Ma (Christopher and Hassel formations; ongoing diapirism and development of an oval map pattern)4. 79 Ma (Kanguk Formation; reactivation of the central diapir).5. 42 Ma to 65 Ma (Eurekan Orogeny; tightening of the anticline).During phase1, the Hoodoo diapir was circular. During phase 2, salt wings formed along its margin. During phase 3, the Hoodoo Dome geometry evolved into a much larger, elongate, doubly plunging anticline. Phase 4 is inferred from thermochronology data as indicated by a cluster of cooling ages, but the extent of motion during that time is unknown. During Phase 5 the dome was tightened creating approximately 700 m of structural relief. Denudation since the end of the Eurekan Orogeny is estimated to be about 600 m.A one dimensional burial history model predicts hydrocarbon generation from Middle and Late Triassic source rocks between 140 and 66 Ma, with majority of hydrocarbon expulsion between 117 and 79 Ma. Hydrocarbon generation post-dates salt wing formation, so that this trap could host natural gas expelled from Triassic source rocks. 相似文献
12.
The Late Miocene Zeit Formation is exposed in the Red Sea Basin of Sudan and represents an important oil-source rock. In this study, five (5) exploratory wells along Red Sea Basin of Sudan are used to model the petroleum generation and expulsion history of the Zeit Formation. Burial/thermal models illustrate that the Red Sea is an extensional rift basin and initially developed during the Late Eocene to Oligocene. Heat flow models show that the present-day heat flow values in the area are between 60 and 109 mW/m2. The variation in values of the heat flow can be linked to the raise in the geothermal gradient from margins of the basin towards offshore basin. The offshore basin is an axial area with thick burial depth, which is the principal heat flow source.The paleo-heat flow values of the basin are approximately from 95 to 260 mW/m2, increased from Oligocene to Early Pliocene and then decreased exponentially prior to Late Pliocene. This high paleo-heat flow had a considerable effect on the source rock maturation and cooking of the organic matter. The maturity history models indicate that the Zeit Formation source rock passed the late oil-window and converted the oil generated to gas during the Late Miocene.The basin models also indicate that the petroleum was expelled from the Zeit source rock during the Late Miocene (>7 Ma) and it continues to present-day, with transformation ratio of more than 50%. Therefore, the Zeit Formation acts as an effective source rock where significant amounts of petroleum are expected to be generated in the Red Sea Basin. 相似文献
13.
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. 相似文献
14.
《Marine and Petroleum Geology》2012,36(1):154-165
This study aims at investigating hydrocarbon generation potential and biological organic source for the Tertiary coal-bearing source rocks of Pinghu Formation (middle-upper Eocene) in Xihu depression, East China Sea shelf basin. Another goal is to differentiate coal and mudstone with respect to their geochemical properties. The coal-bearing sequence has a variable organofacies and is mainly gas-prone. The coals and carbonaceous mudstones, in comparison with mudstones, have a higher liquid hydrocarbon generation potential, as reflected by evidently higher HI values (averaging 286 mg HC/g C) and H/C atomic ratios (round 0.9). The molecular composition in the coal-bearing sequence is commonly characterized by unusually abundant diterpenoid alkanes, dominant C29 sterane over C27 and C28 homologues and high amount of terrigenous-related aromatic biomarkers such as retene, cadalene and 1, 7-dimethylphenanthrene, indicating a predominantly terrigenous organic source. The source rocks show high Pr/Ph ratios ranging mostly from 3.5 to 8.5 and low MDBTs/MDBFs ratios (<1.0), indicating deposition in an oxic swamp-lacustrine environment. The coals and carbonaceous mudstones could be differentiated from the grey mudstones by facies-dependent biomarker parameters such as relative sterane concentration and gammacerane index and carbon isotope composition. Isotope and biomarker analysis indicate the genetic correlation between the Pinghu source rocks and the oils found in Xihu depression. Moreover, most oils seem to be derived from the coal as well as carbonaceous mudstone. 相似文献
15.
Coals are oil source rocks in many of the Tertiary basins of Southeast Asia. The precursors of these hydrogen rich and oxygen poor coals are coastal plain peats which have mainly developed in an everwet and tropical climate. In these environments water flow and reworking can concentrate liptinitic kerogen in preference to vitrinitic kerogen. The distribution, petrography and chemistry of the coaly Miocene source rocks present in the Kutai Basin are described. The recognition of environmental controls on the accumulation of potentially oil-prone coals and coaly shales in deltaic environments is an aid to predictive source bed recognition in petroleum exploration. Comments on the environment of deposition of coaly sediments in the basins of the Norwegian Sea are discussed with reference to their possible oil and/or gas sourcing potential. The Triassic - Jurassic coals of the Haltenbanken area may become more oil-prone towards the delta margins, and facies mapping could aid oil exploration in this area. 相似文献
16.
Reservoir potential of Late Cretaceous terrestrial to shallow marine sandstones,Taranaki Basin,New Zealand 总被引：2，自引：0，他引：2
Late Cretaceous coals and coaly source rocks are the main source of hydrocarbons in the Taranaki Basin, yet to date there have not been any hydrocarbon discoveries within Cretaceous strata, and sandstone distribution and reservoir quality for this interval have been poorly understood. The Late Cretaceous sediments were deposited in several sub-basins across Taranaki, with their distribution largely determined by sediment supply, subsidence, and sea level change. In this study, we describe potential reservoir facies in well penetrations of Cretaceous strata in Taranaki, as well as from outcrop in northwest Nelson, on the southern edge of the basin. 相似文献
17.
《Marine and Petroleum Geology》2012,32(1):27-42
The gas generative potential of organic matter is one key parameter for the calculation of total gas in place (GIP) when evaluating thermogenic shale gas plays. Having first demonstrated that late gas-forming structures are present in coals of anthracite rank (>2% R0) we go on to examine other rocks at the immature stage of maturity and report on how to recognise which might generate significant amounts of late dry gas at geologic temperatures well in excess of 200 °C in the zone of metagenesis (R0 > 2.0%), i.e. subsequent to primary and secondary gas generation by thermal cracking of kerogen or retained oil. Such a distinction could clearly be of major value when assessing risks and pinning down “sweet spots”. A large selection (51 samples) of source rocks, i.e. shales and coals, stemming from different depositional environments and containing various types of organic matter which contribute to the formation of petroleum in putative gas shales were investigated using open- and closed-system pyrolysis methods for the characterisation of kerogen type, molecular structure, and late gas generative behaviour. A novel, rapid closed-system pyrolysis method, which consists of heating crushed whole rock samples in MSSV-tubes from 200 °C to 2 different end temperatures (560 °C; 700 °C) at 2 °C/min, provides the basis for a newly proposed approach to discriminate between source rocks with low, high, or intermediate late gas potential. It is noteworthy that late gas potential goes largely unnoticed when only open-system pyrolysis screening-methods are used. High late gas potentials seem to be mainly associated with heterogeneous admixtures or structures in terrestrially influenced, in some cases marine, Type III and Type II/III coals and shales. Aromatic and/or phenolic signatures are therefore indicative of the possible presence of elevated late gas potential at high maturities. High temperature methane was calculated to potentially contribute an additional 10–40 mg/g TOC, which would equal up to 30% of the total initial primary petroleum potential in many cases. Low late gas potentials are associated with homogeneous, paraffinic organic matter of aquatic lacustrine and marine origin. Source rocks exhibiting intermediate late gas potentials might generate up to 20 mg/g TOC late dry gas and seem to be associated with heterogeneous marine source rocks containing algal or bacterial derived precursor structures of high aromaticity, or with aquatic organic matter containing only minor amounts of aromatic/phenolic higher land plant material. 相似文献
18.
In order to investigate the hydrocarbon generation process and gas potentials of source rocks in deepwater area of the Qiongdongnan Basin, kinetic parameters of gas generation(activation energy distribution and frequency factor) of the Yacheng Formation source rocks(coal and neritic mudstones) was determined by thermal simulation experiments in the closed system and the specific KINETICS Software. The results show that the activation energy(Ea) distribution of C1–C5 generation ranges from 50 to 74 kcal/mol with a frequency factor of 2.4×1015 s–1 for the neritic mudstone and the Ea distribution of C1–C5 generation ranges from 49 to 73 kcal/mol with a frequency factor of 8.92×1013 s–1 for the coal. On the basis of these kinetic parameters and combined with the data of sedimentary burial and paleothermal histories, the gas generation model of the Yacheng Formation source rocks closer to geological condition was worked out, indicating its main gas generation stage at Ro(vitrinite reflectance) of 1.25%–2.8%. Meanwhile, the gas generation process of the source rocks of different structural locations(central part, southern slope and south low uplift) in the Lingshui Sag was simulated. Among them, the gas generation of the Yacheng Formation source rocks in the central part and the southern slope of the sag entered the main gas window at 10 and 5 Ma respectively and the peak gas generation in the southern slope occurred at 3 Ma. The very late peak gas generation and the relatively large gas potential indices(GPI:20×108–60×108 m3/km2) would provide favorable conditions for the accumulation of large natural gas reserves in the deepwater area. 相似文献
19.
Eight lacustrine Type I kerogen samples from the Songliao Basin were pyrolyzed using the Rock-Eval equipment, and parallel first-order reaction models including the model with a single frequency factor and a discrete distribution of activation energies (SFF model) and the model with multiple frequency factors and a discrete distribution of activation energies (MFF model) were adopted to analyze kinetic characteristics of hydrocarbon generation of the Type I kerogen samples. The results show that the MFF and SFF models can satisfactory simulate hydrocarbon generation under laboratory conditions and the Type I kerogen shows relatively concentrated activation energy distributions (activation energies of MFF model range from 190 kJ/mol to 250 kJ/mol, activation energies of SFF model range from 220 kJ/mol to 240 kJ/mol), which indicates a homogeneous chemical bond structure of the Type I kerogen. The hydrocarbon generated curves from Type I kerogen were calculated by using the two models with a linear heating rate (3.3 K/Ma). It indicates that the hydrocarbon generation potentials (reaction fractions) are underestimated by using the SFF model during the kerogen thermal degradation for the components with chemical bond of lower and higher activation energies, while this problem can be avoided by using the MFF model. The calculated temperatures for 50% transformation ratio (TR) of all samples differ by as much as 20 °C. For the SFF model, the hydrocarbon generation curve obtained by using the weighted averaged kinetic parameters and the SFF model almost includes every curve calculated by using its own kinetic parameters. While the curve obtained by using the weighted averaged kinetic parameters and the MFF model cannot include every curve for all samples, it lies at the position of the averaged curve of all samples. The application of the MFF model in Songliao Basin shows that if TR 10% is taken as the onset of hydrocarbon generation, the threshold depth of hydrocarbon generation is about 1700 m, which is consistent with other geochemical parameters, such as S1/TOC, S1/(S1 + S2) and HC/TOC. 相似文献
20.
Ever since a breakthrough of marine shales in China, lacustrine shales have been attracting by the policy makers and scientists. Organic-rich shales of the Middle Jurassic strata are widely distributed in the Yuqia Coalfield of northern Qaidam Basin. In this paper, a total of 42 shale samples with a burial depth ranging from 475.5 m to 658.5 m were collected from the Shimengou Formation in the YQ-1 shale gas borehole of the study area, including 16 samples from the Lower Member and 26 samples from the Upper Member. Geochemistry, reservoir characteristics and hydrocarbon generation potential of the lacustrine shales in YQ-1 well were preliminarily investigated using the experiments of vitrinite reflectance measurement, maceral identification, mineralogical composition, carbon stable isotope, low-temperature nitrogen adsorption, methane isothermal adsorption and rock eval pyrolysis. The results show that the Shimengou shales have rich organic carbon (averaged 3.83%), which belong to a low thermal maturity stage with a mean vitrinite reflectance (Ro) of 0.49% and an average pyrolytic temperature of the generated maximum remaining hydrocarbon (Tmax) of 432.8 °C. Relative to marine shales, the lacustrine shales show low brittleness index (averaged 34.9) but high clay contents (averaged 55.1%), high total porosities (averaged 13.71%) and great Langmuir volumes (averaged 4.73 cm−3 g). Unlike the marine and marine-transitional shales, the quartz contents and brittleness index (BI) values of the lacustrine shales first decrease then increase with the rising TOC contents. The kerogens from the Upper Member shales are dominant by the oil-prone types, whereas the kerogens from the Lower Member shales by the gas-prone types. The sedimentary environment of the shales influences the TOC contents, thus has a close connection with the hydrocarbon potential, mineralogical composition, kerogen types and pore structure. Additionally, in terms of the hydrocarbon generation potential, the Upper Member shales are regarded as very good and excellent rocks whereas the Lower Member shales mainly as poor and fair rocks. In overall, the shales in the top of the Upper Member can be explored for shale oil due to the higher free hydrocarbon amount (S1), whereas the shales in the Lower Member and the Upper Member, with the depths greater than 1000 m, can be suggested to explore shale gas. 相似文献