Mature Source Rocks Research Articles

Diagenesis and reservoir quality of Cambrian carbonates in the Tarim Basin, northwestern China

Quantitative petrographic analysis revealed the diagenetic controls on the reservoir quality of deep (>5,000 m) carbonate reservoirs in the Tarim Basin. Dolostones were formed by the extensive dolomitization of originally low-energy (siliciclastic mudrocks, calcimudstones, and wackestones) and moderate-to-high-energy (peloidal, intraclastic, and/or bioclastic packstones to grainstones, rarely microbialites) deposits. Replacement of primary and diagenetic constituents by dolomite occurred in multiple phases. Eogenetic dolomitization precipitated microcrystalline to finely crystalline dolomite, followed by dolomite overgrowth during shallow mesogenesis. Saddle, coarse, and radial undulose dolomite precipitated during deep mesogenesis under increasing temperature and pressure and were locally replaced by microcrystalline quartz. Primary porosity is absent, but these carbonates can display vuggy, intercrystalline, and fracture porosity due to dolomite dissolution and local fracturing. Secondary porosity can be partially or totally filled by saddle dolomite and/or quartz. Petrological and fluid-inclusion data indicated that three ascending fluids considerably influenced the diagenetic evolution and quality of the Cambrian reservoirs, namely, organic acid-rich fluids from the maturation of source rocks, SO2-rich fluids derived from the dissolution of calcium sulfate and hydrothermal fluids. The structurally controlled percolation of SO2-rich fluids was the main process responsible for creating porosity in deep carbonate reservoirs in the Tarim Basin. The influence of hydrothermal fluids is not ubiquitous, and it had a dual impact on reservoir quality, i.e., the hydrothermal fluids enhanced the porosity through dolomite dissolution and decreased the porosity through dolomite and quartz precipitation.

Reconstruction of oil charging history in the multi-source petroleum system of the Beidagang buried-hill structural belt in the Qikou Sag, Bohai Bay Basin, China: Based on the integrated analysis of oil-source rock correlations, fluid inclusions and geologic data

The Beidagang buried-hill structural belt (BBHSB), located in the central part of the Qikou Sag, Bohai Bay Basin, hosts a multi-source and structurally complex petroleum system, in which the interpretation of oil-source relationships and the definition of hydrocarbon accumulation features are challenging due to the highly variable composition of oils and complex oil migration pathways. In this study, we use biomarkers, fluid inclusions, and geologic data to address the complexities of petroleum system analysis in BBHSB. Based on hierarchical cluster analysis, four genetic groups of oils (A, B, C and D) with distinct molecular compositions were identified. Group A, B, and C oils are originated from the source rocks in the third member (Es 3 ) of the Eocene Shahejie Formation (Es), the lower (Es 1 x ) section of the first member (Es 1 ) of Es, and the middle (Es 1 z ) section of Es 1 , respectively. Group D oils are mixed oils contributed by the source rocks of Es 1 x and the second member (Es 2 ) of Es. Bounded by geological settings, the charging histories of the four groups of oils were different. Fluid inclusion analysis suggests that Group A oils have two charging stages, i.e., the late Oligocene and the Pliocene-present. During the first stage, Group A oils mainly accumulated in Es 3 with relatively low maturity. During the second stage, the Group A oils vertically migrated along the fault in a large scale, resulting in its accumulation in the middle-shallow formations near the fault. Due to the late maturity of source rocks, Group B, C, and D oils have one accumulation stage that occurred during the Pliocene-present. Due to the blocking effect of the reverse drag anticline on the migration of oils to the fault, the accumulation of Group B and C oils were limited to inner source-layers and the distribution of Group D oils in the northeastern BBHSB was limited in Es 1 x . • The crude oils can be separated into four genetic groups (A, B, C, and D) with distinct sources. • Group A oils have two charging stages and the other three group oils have only one. • Constrained by geological conditions, the four group oils have different migration features. • The charging history of the four groups of oils has been constructed.

Origin and isotopic fractionation of shale gas from the Shanxi Formation in the southeastern margin of Ordos Basin

The Ordos Basin is abundant in natural gas resources, and the Shanxi Formation with the transitional facies is considered as a potential stratum for shale gas reservoir. However, the origin and geochemical characteristics of the Shanxi Formation shale gas remains unclear. In this study, 22 shale gas samples were collected from the SX-1 well in the southeastern margin of Ordos Basin, and tested for gas components and compositions of stable carbon isotope. Moreover, five rock samples were measured for total organic carbon (TOC), the vitrinite reflectance (Ro), kerogen type, porosity, permeability, and methane adsorption capacity. The shale gas in the Shanxi Formation has a high proportion of methane which is consistent with the high maturity of source rocks. The contradictory relationship between the carbon isotopes of ethane (δ13C2) from the Shanxi Formation shale gas and kerogen types of rock samples may be caused by the complex sedimentary environment, multiple provenance systems, and high maturity. The carbon isotopes of methane (δ13C1), δ13C2 and alkane gas components indicate that the shale gas near coal seams is coal-derived gas, the gas at the bottom of the Shanxi Formation is oil-type gas and the gas in mudstones among the sandstone layer at the top of the Shanxi Formation may be mixed with natural gas migrating from other layers or mixed with gas generated in the later period. Meanwhile, the carbon isotopes of carbon dioxide (δ13CCO2) suggest that the CO2 generated with hydrocarbons in the coal-measures is mainly of organic origin. The carbon isotopic fractionation of methane is commonly observed in shale gas samples. This fractionation is mainly controlled by the diffusion effect which can be promoted by high porosity and permeability. Furthermore, the positive correlation between the TOC values and the degree of fractionations may be attributed to the high TOC values in the samples, which can improve the development of organic pores and increase the content of adsorbed gas.

Error correction of vitrinite reflectance in matured black shales: A machine learning approach

Vitrinite reflectance (Ro) analysis is a maturity indication parameter for oil or gas prone source rocks in evaluating hydrocarbon potentials. As a result of challenges in Ro calculations from pyrolysis, finding a way to estimate the maturity of source rocks has been an interesting subject for researchers. The is a current need to improve the Ro calculated from the temperature at which the maximum rate of hydrocarbon generation occurs (Tmax) in matured shale formations. As this will go a long way to accelerate decision making and help avoid excessive expenditure costs on maturity determination for source rock samples while saving time. After the application of the conventional multiple linear regression analysis, the present study employed machine learning methods of random forest (RF), decision tree (DT), gradient boosting machine (GBM), ensembles and bagger (EnB), and multivariate adaptive regression splines (MARS) models for improving the calculated Ro of matured black shales. Oxygen index (OI), the amount of carbon dioxide produced during pyrolysis of kerogen (S3), and vitrinite reflectance measurement (Ro) were used as inputs to estimate the error margin between the calculated vitrinite reflectance and measured vitrinite reflectance. The predictions from the models were then summed with the calculated vitrinite reflectance to produce an improved vitrinite reflectance measurement. The model that generated the most improved vitrinite reflectance measurement, thus, having the least amount of statistical error was selected. EnB achieved the highest accuracy with a correlation coefficient (R) of 0.82 and coefficient of determination (R2) of 0.67 for the improved Ro model. Therefore, a conclusion can be drawn from the results that EnB can adequately improve the Ro of matured rocks through error correction.

Bulk petroleum geochemistry of shales from the onshore Rio del Rey Basin, Cameroon

Petroleum production in the Rio del Rey Basin, which is an extension of the Niger Delta of Nigeria into Cameroon, has been limited to the Tertiary offshore portion since the late 1970s. Owing to declining reserves in this offshore portion, the onshore Cretaceous portion of the basin attracted significant attention in the last decade. In the present study, shales from outcrops in the onshore portion of the basin were analyzed to evaluate their potential as source rocks, assess hydrocarbon generation, and highlight their significance for exploration. Outcrop observations, total organic carbon (TOC) measurements, and Rock-Eval pyrolysis were used to generate data for these investigations. Rock-eval S2 values (0.42–3 mg HC/g rock) based on measured present-day TOC values (0.58–2.44 wt%) of the shales studied signify poor to fair source rock potentials, whereas calculated S2 values (1.74–8.19 mg HC/g rock) based on estimated original TOC values (0.67–2.87 wt%) produced fair to good source rocks containing Type Ⅱ/III kerogen, which were transformed by maturity to the present-day Type Ⅲ/Ⅳ kerogen. Maturity of the samples based on Tmax values varying between 439 and 471 °C are equivalent to maturity values ranging between 0.74% Rr and 1.32% Rr, and these represent the peak oil to condensate/wet gas zones of hydrocarbon generation. These results demonstrate that mature source rocks are present in the onshore part of the Rio del Rey Basin, and thus, it is suitable for petroleum exploration.

BIOMARKER GEOCHEMISTRY OF PALEOGENE CRUDE OILS AND SOURCE ROCKS FROM THE RAOYANG SAG, BOHAI BAY BASIN, NE CHINA: AN OIL – SOURCE ROCK CORRELATION STUDY

This study presents a systematic geochemical analysis of Paleogene crude oils and source rocks from the Raoyang Sag in the Jizhong sub‐basin of the Bohai Bay Basin (NE China). The geochemical characteristics of fifty‐three oil samples from wells in four sub‐sags were analysed using gas chromatography (GC) and gas chromatography – mass spectrometry (GC‐MS). Twenty core samples of mudstones from Members 1 and 3 of the Eocene‐Oligocene Shahejie Formation were investigated for total organic carbon (TOC) content and by Rock‐Eval pyrolysis and GC‐MS to study their geochemistry and hydrocarbon generation potential. The oils were tentatively correlated to the source rocks.The results show that three groups of crude oils can be identified. Group I oils are characterized by high values of the gammacerane index and low values of the ratios of Pr/Ph, Ts/Tm, 20S/(20S+20R) C29 steranes, ββ/(ββ+αα) C29 steranes, C27 diasteranes/ C27 regular steranes and C27/C29 steranes. These oils have the lowest maturity and are interpreted to have originated from a source rock containing mixed organic matter deposited in an anoxic saline lacustrine environment. The biomarker parameter values of Group III oils are the opposite to those in Group I, and are interpreted to indicate a highly mature, terrigenous organic matter input into source rocks which were deposited in suboxic to anoxic freshwater lacustrine conditions. The parameter values of Group II oils are between those of the oils in Groups I and III, and are interpreted to indicate that the oils were generated from mixed organic matter in source rocks deposited in an anoxic brackish–saline or saline lacustrine environment.The results of the source rock analyses show that samples from Member 1 of the Shahejie Formation were deposited in an anoxic, brackish – saline or saline lacustrine environment with mixed organic matter input and are of low maturity. Source rocks in Member 3 of the Shahejie Formation were deposited in a suboxic to anoxic, brackish – saline or freshwater lacustrine environment with a terrigenous organic matter input and are of higher maturity. Correlation between rock samples and crude oils indicates that Group I oils were probably derived from Member 1 source rocks, while Group III oils were more likely generated by Member 3 source rocks. The Group II oils with transitional characteristics are likely to have a mixed source from both sets of source rocks.

Application of Machine Learning Algorithms in Predicting Pyrolytic Analysis Result

Geochemical studies of organic matter in source rocks play an important role in predicting the oil and gas accumulation of any territory, especially in oil and gas shale. For deep understanding, pyrolytic analyses are often carried out on samples before and after extraction of hydrocarbon with chloroform. However, extraction is a laborious and time-consuming process and the workload of laboratory equipment and time doubles. In this work, machine learning regression algorithms is applied for forecasting S2ex based on the pyrolytic analytic result of non-extracted samples. This study is carried out using more than 300 samples from 3 different wells in Bazhenov formation, Western Siberia. For developing a prediction model, 5 different machine learning regression algorithms including Multiple Linear Regression, Polynomial Regression, Support vector regression, Decision tree and Random forest have been tested and compared. The performance of these algorithms is examined by R-squared coefficient. The data of the X2 well was used for building a model. Simultaneously, this data is divided into 2 parts – 80% for training and 20% for checking. The model also was used for prediction of wells X1 and X3. Then, these predictive results were compared with the real results, which had been obtained from standard experiments. Despite limited amount of data, the result exceeded all expectations. The result of prediction also showcases that the relationship between before and after extraction parameters are complex and non-linear. The proof is R2 value of Multiple Linear Regression and Polynomial Regression is negative, which means the model is broken. However, Random forest and Decision tree give us a good performance. With the same algorithms, we can apply for prediction all geochemical parameters by depth or utilize them for well-logging data.

Source rock maturity and hydrocarbon potential of Abu Rudeis-Sidri area, central province, Gulf of Suez, Egypt

Source rock maturity and hydrocarbon potential of Abu Rudeis-Sidri area, central province, Gulf of Suez, Egypt

Methylation and demethylation of naphthalene homologs in highly thermal mature sediments

Molecular compositions of naturally matured source rocks from the Carboniferous Keluke Formation in the Qaidam Basin and laboratory matured samples from the Cretaceous Qingshankou Formation in the Songliao Basin were analyzed to investigate the thermal evolution behaviors of methylation and demethylation of naphthalene homologs. Sediments in the Keluke Formation were variably mature with measured vitrinite reflectance (Ro) ranging from 0.74% to 1.88%. Concentrations of alkylated naphthalene homologs, including dimethylnaphthalenes (DMNs), trimethylnaphthalenes (TMNs), tetramethylnaphthalenes (TeMNs) and pentamethylnaphthalenes (PMNs), exhibit an increasing trend with thermal maturation below 1.1 %Ro, but present an abrupt shift with decreasing concentrations above 1.1 %Ro. The isomerization, methylation and demethylation processes play significant roles in the distribution of alkylnaphthalenes, but dominates at different thermal maturity levels. Isomerization and methylation play dominant roles at relatively low thermal maturity levels (Ro < 1.1%) whereas demethylation dominates the distribution of alkylnaphthalenes in highly mature sediments (Ro > 1.1%) when less stable isomers of alkylnaphthalenes, such as 1,2,5-TMN, 1,2,5,6-TeMN and 1,2,3,5-TeMN, are almost eliminated and more stable isomers dominate the remaining homologs. The transition from methylation to demethylation of alkylnaphthalenes occurs at ca. 1.1 %Ro, which is lower than that of alkylphenanthrenes (1.35 %Ro) due to thermally induced condensation of aromatic hydrocarbons. The demethylation of alkylnaphthalenes at higher thermal maturity levels (Ro > 1.1%) results in the failure of thermal maturity parameters derived from alkylnaphthalenes, such as TMNr and TeMNr.

Integration of methyldibenzothiophene and pyrolysis techniques to determine thermal maturity in sulfur-rich Type II-S source rocks and oils

Isomer ratios between certain polycyclic aromatic compounds in produced oils and bitumen extracts change according to the maturity of the source rock, similar to results obtained from visual vitrinite reflectance and pyrolysis. For example, empirical relationships between methyldibenzothiophene (MDBT) and methylphenanthrene compounds correlate to these parameters. However, isomer ratios and their corresponding empirical relationships are not universally applicable. Their concentrations are source-specific, influenced by maceral type, and change with the kinetics of the source rock that is generating the hydrocarbon. The organosulfur content in kerogen can strongly affect the kinetics by lowering the activation energy, resulting in the generation of hydrocarbons at lower temperatures than other source rocks. This can cause uncertainty in the calibration of basin models for predicting the timing of hydrocarbon generation, expulsion, and migration, especially for Type II-S sources. Presented are the results of a study conducted on Type II-S carbonate organofacies from the United States and the Middle East that integrates the MDBTs extracted from bitumen and measured in produced oil with other ancillary maturity indicators. The MDBT isomers show a correlation between Tmax and hydrogen index that allows for the development of maturity models to accurately predict a %Ro equivalent from immature to condensate/wet gas maturity. Results indicate the often-utilized empirical equations developed from the methylphenanthrenes are not applicable for determining maturity of marine Type II-S organofacies. Instead, the MDBT-HI and MDBT-Tmax methods provide more reliable estimates of maturity for the Type II-S, marine carbonate organofacies to aid in validating basin model predictions for hydrocarbon generation.

Reservoir Quality of Upper Jurassic Corallian Sandstones, Weald Basin, UK

The Upper Jurassic, shallow marine Corallian sandstones of the Weald Basin, UK, are significant onshore reservoirs due to their future potential for carbon capture and storage (CCS) and hydrogen storage. These reservoir rocks, buried to no deeper than 1700 m before uplift to 850 to 900 m at the present time, also provide an opportunity to study the pivotal role of shallow marine sandstone eodiagenesis. With little evidence of compaction, these rocks show low to moderate porosity for their relatively shallow burial depths. Their porosity ranges from 0.8 to 30% with an average of 12.6% and permeability range from 0.01 to 887 mD with an average of 31 mD. The Corallian sandstones of the Weald Basin are relatively poorly studied; consequently, there is a paucity of data on their reservoir quality which limits any ability to predict porosity and permeability away from wells. This study presents a potential first in the examination of diagenetic controls of reservoir quality of the Corallian sandstones, of the Weald Basin’s Palmers Wood and Bletchingley oil fields, using a combination of core analysis, sedimentary core logs, petrography, wireline analysis, SEM-EDS analysis and geochemical analysis to understand the extent of diagenetic evolution of the sandstones and its effects on reservoir quality. The analyses show a dominant quartz arenite lithology with minor feldspars, bioclasts, Fe-ooids and extra-basinal lithic grains. We conclude that little compactional porosity-loss occurred with cementation being the main process that caused porosity-loss. Early calcite cement, from neomorphism of contemporaneously deposited bioclasts, represents the majority of the early cement, which subsequently prevented mechanical compaction. Calcite cement is also interpreted to have formed during burial from decarboxylation-derived CO2 during source rock maturation. Other cements include the Fe-clay berthierine, apatite, pyrite, dolomite, siderite, quartz, illite and kaolinite. Reservoir quality in the Corallian sandstones show no significant depositional textural controls; it was reduced by dominant calcite cementation, locally preserved by berthierine grain coats that inhibited quartz cement and enhanced by detrital grain dissolution as well as cement dissolution. Reservoir quality in the Corallian sandstones can therefore be predicted by considering abundance of calcite cement from bioclasts, organically derived CO2 and Fe-clay coats.

The origins of paraffinic oils collected from oilfields in the western Siberian Basin, Russia: implications from geochemical and physical characteristics

Four oil samples were collected from oilfields in the western Siberian Basin, and analyzed using conventional geochemical and physical methods. The results of this study were used to evaluate the oil samples, focusing on the characteristics of their source rocks, including the origin of organic matter input; redox depositional conditions and degree of thermal maturity of their probable source rock were studied. The obtained SARA results show that the examined oils are paraffinic oils owing to their high saturated hydrocarbon fraction values of greater than 70% volume. The observed API gravity values (23.55° to 32.57°) and low sulfur content of less than 0.25% wt indicate that the examined oils are sweet oils and were generated from source rock containing Type-II, with low sulfur content. The low sulfur content combined with the vanadium (V) and nickel (Ni) ratios indicates that the examined oils were scoured from a mixture of aquatic and terrestrial organic matter, depositing under generally suboxic environmental conditions. The n-alkane and isoprenoid distributions, with their ratios and parameters further suggest that the examined oil samples were generated from source rock containing a mixed organic matter input and deposited under suboxic to relatively oxic environmental conditions. Bulk compositions and distributions of n-alkane and isoprenoid indicate that the oil samples were generated from mature source rock.

Ammassalik Composite Tectono-Sedimentary Element, southern East and SE Greenland Rifted Margin, Denmark Strait

Abstract The Ammassalik Composite Tectonic-Sedimentary Element (CTSE) comprises the Ammassalik and the Kangerlussuaq rift basins located on the southern East and SE Greenland margin. The offshore Ammassalik Basin is one of the last virtually undescribed segments of the NE Atlantic continental margins with a very sparse seismic coverage. The basin is compartmentalized into smaller sub-basins up to at least 4 km deep blanketed by Paleocene–Eocene basalt towards the east. Albian sediments cored in the basin suggest, at least partly, a Cretaceous age, making the Ammassalik Basin a likely analogue to basins on the conjugate outer British continental margin. However, the deeper, undated succession could include pre-Cretaceous strata. Located onshore southern East Greenland, the Kangerlussuaq Basin contains a Barremian/Aptian–Danian succession of estuarine–marine strata overlain by Paleocene fluvial sediments, basalts and thinner marine interludes. The sedimentary succession is less than 1 km thick. Cenozoic uplift and erosion affected both basins. Unlike the Kangerlussuaq Basin, the Ammassalik Basin may contain a working petroleum system. Together with the very large fault structures identified in the basin, this makes the Ammassalik Basin an interesting future exploration target with the main challenge being to demonstrate a mature source rock, together with qualifying the effects of Paleocene–Eocene magmatism and Cenozoic exhumation on the potential petroleum system.

Differences on Geochemical Characteristics and Their Implicating Significances of Nitrogen in Coal-Derived Gas and Oil-typed Gas in China

Natural gases in China are mainly coal-derived gas, with assistance from oil-typed gas. At present, many genetic identification methods, from hydrocarbon composition and isotope to light hydrocarbon and biomarker indexes, have been formed, but combined methods from non-hydrocarbon gases are lacking. Based on compositions and isotopes geochemical characteristics and the differences of non-hydrocarbon nitrogen gas in coal-derived gas and oil-typed gas, and combining the isotopic geochemical characteristics of non-hydrocarbon helium, the comprehensive identification methods of coal-derived gas and oil-typed gas for hydrocarbon gases according to the associated non-hydrocarbon gases of nitrogen and helium are established and the preliminary applications have been engaged. The main recognitions are as follows:1)Coal-derived gas generally has relatively lower nitrogen abundance, mainly distributed from 0 to 31.2% with main frequency from 0 to 2%. Oil-typed gas, on the other hand, usually has relatively higher nitrogen abundance, mainly distributed from 1.1 to 57.1% with main frequency from 2 to 16%. 2) Coal-derived gas generally has relatively heavier nitrogen isotope values, mainly distributed from -8 to 19.3‰ with main frequency from -8 to 8‰.Oil-typed gas usually has relatively lower nitrogen isotope values, mainly distributed from -10.6 to 4.6‰ with main frequency from -8 to 4‰.3)The geochemical characteristic differences of coal-derived gas and oil-typed gas are mainly due to the fact that the sapropel parent material is relatively rich in nitrogen element and rich in light δ14N, while the humic parent material is relatively poor in nitrogen element and rich in heavy δ15N. The differences on thermal maturity of source rocks, the redox conditions of source rock sedimentary environment, and the salinity of water body are also important effective factors.4)Differences on nitrogen abundances and isotopes in coal-derived gas and oil-typed gas have great significance in genetic identification. The genetic identification chart of R/Ra-δ15N for organic and inorganic nitrogen in natural gas and the comprehensive joint identification charts of R/Ra-δ15N-N2 of nitrogen and helium for coal-derived gas and oil-typed gas have been established, and are of great reference in investigating the origins and sources of natural gas and guiding natural gas exploration in China.

Role of zooclasts in the kerogen type and hydrocarbon potential of the lower Paleozoic Alum Shale

This study investigates the role of zooclasts in the bulk organic matter composition, kerogen type, and hydrocarbon generation potential of the lower Paleozoic marine Alum shale in Baltoscandia, northwestern Europe. The results show that graptolite periderm is composed of non-granular cuticles and granular filling. The graptolite cuticle is non-fluorescing and has a well-polishing measurable surface, while the graptolite granular fraction is semi-translucent and has brownish fluorescence, suggesting remaining hydrocarbon generation potential. The graptolite granular fraction shows similar optical characteristics to fluorescing diagenetic solid bitumen. Both the graptolite granular fraction and diagenetic solid bitumen have low intensity yellow to brown fluorescence and contribute to generative potential (Rock-Eval S2). The sum of semi-quantitative zooclastic cuticle (non-granular graptolite cuticle, chitinozoan cuticle, and vitrinite-like) and diagenetic solid bitumen content, obtained from maceral point-counting, correlates with the non-generative organic carbon content. Enrichment of zooclastic cuticle in the samples is displayed as enrichment of inert organic carbon, and hence bulk geochemical kerogen of type III. This refractory carbon-rich maceral enrichment results represents autochthonous ‘refractory organic carbon dilution’ and will lead to Hydrocarbon Index (HI) underestimation. Confined hydrous pyrolysis was used to compare the hydrocarbon generation process of a zooclastic cuticle-lean sample (0.2 vol%) and a zooclastic cuticle-rich (1.6 vol%) sample. Results indicate that there are four stages of hydrocarbon generation in the artificial maturation of unconventional source rock of the Alum Shale. The zooclastic cuticle-lean sample has higher hydrocarbon generation potential and more oil-prone than the zooclastic cuticle-rich sample, which is gas-prone and generates more CO2. This difference in hydrocarbon generation is attributed to differences in the organic constituent composition.

Accumulation characteristics and large-medium gas reservoir-forming mechanism of tight sandstone gas reservoir in Sichuan Basin, China: Case study of the Upper Triassic Xujiahe Formation gas reservoir

Tight sandstone gas reservoirs of Xujiahe Formation in central Sichuan Basin have generally high water saturation. The characteristics of natural gas migration and accumulation, as well as gas reservoirs with high water saturation formation mechanism, were investigated using test data from natural gas geochemistry analysis and nuclear magnetic resonance (NMR) high pressure filling simulation experiment. The findings reveal that: (1)The Xujiahe Formation established the foundation for oil and gas near-source accumulation by interacting superimposed large areas of source rock and reservoir. As the maturity of source rocks increases, the wetness becomes smaller and the δ13C1 value becomes heavier of natural gas, indicating a near-source accumulation. (2)The gas saturation of Xujiahe Formation gas reservoirs ranges from 50% to 65%, with a pore radius of the reservoir space 0.1–10 μm. The larger the proportion of relatively large pore size, the higher the gas saturation will be. (3)As charging pressure is increased, natural gas accumulates in tight sandstone by progressively aggregating from large pore diameter to small pore diameter space, culminating “three-stage” charging characteristics of rapid increase, moderate increase and basically stable charge. The coupling between low-pressure drive and relatively large pore reservoir is the fundamental reason why the Xujiahe Formation of natural gas can form large-medium gas reservoirs but high water saturation in central Sichuan Basin. The findings will provide theoretical and technical support for the exploration of tight sandstone.

MATURITY OF POTENTIAL CRETACEOUS SOURCE ROCKS AT THE ISIS FIELD, OFFSHORE EASTERN TUNISIA: INFLUENCE OF HYDROTHERMAL FLUIDS

An increase in source rock thermal maturity is in general linked to burial‐related heating according to the regional geothermal gradient, but maturities may also locally be influenced by high‐temperature hydrothermal fluids or igneous intrusions. In the present study of the Isis field located in the Gulf of Gabes (offshore Tunisia), we combine an analysis of organic matter maturity indicators and clay mineral signatures to constrain possible fluid/rock interactions and to define controls on the maturity of potential source rocks. Cuttings samples were collected from source rock intervals in the Cretaceous Bahloul (Cenomanian – Turonian) and underlying Fahdene (Albian – Cenomanian) Formations at the PM borehole, and detailed organic geochemical and clay mineralogical analyses of source rock samples and extracts were carried out. Samples from the Bahloul Formation (2381 m to 2400 m) consist of black to dark grey claystones and globigerinid limestones. Those from the Fahdene Formation (2400 m to 2700 m) comprise alternating claystones and chalky limestones containing globigerinids including Ticinella primula. Both source rock intervals have similar mineralogical compositions consisting of calcite, quartz, albite, anorthite, minor anatase, pyroxene and pyrite. The clay mineralogy of the formations is composed of abundant smectite (two generations), subordinate kaolinite and minor illite and/or mica. The Fahdene source rock contains organic matter consisting of mixed kerogen Types II/III; Type II OM is present in the Bahloul Formation.At the borehole location, the source rock intervals in the Fahdene and Bahloul Formations have been affected by hydrothermal fluids which are derived from an unconformably overlying basalt succession which is &gt;300 m thick. Based on bulk mineral assemblages, the Bahloul Formation has been modified by the hydrothermal fluids more significantly than the underlying Fahdene Formation. Analyses of the clay minerals compositions indicate that interactions between the hydrothermal fluids and the host rocks were very rapid and were localized within fractures and micropores. The Bahloul Formation source rocks have reached an advanced stage of thermal maturity (overmature or end‐ oil window) compared to the thermally immature source rocks in the Fahdene Formation.The results show that the main control on source rock maturation at the studied well was maximum palaeotemperature and this may locally have been influenced by short‐term hydrothermal and magmatic heating as well as by the regional geotherm. Clay minerals were less affected by hydrothermal heating compared to organic matter indices; this may be because mineral components are slower to react to short‐term higher temperature conditions than organic matter.Thus magmatic activity and hydrothermal fluids may locally accelerate the thermal maturation of source rocks even at shallow depths. The study also shows that a combination of clay mineral characterization and organic matter indicators can be useful for the assessment of thermal maturity in potential source rocks.

SOURCE ROCK EVALUATION AND BASIN MODELLING IN THE GORGAN PLAIN, SE SOUTH CASPIAN BASIN, NORTHERN IRAN

Hydrocarbon exploration in the Gorgan Plain to the SE of the South Caspian Basin (northern Iran) has taken place since the 1960s but no economic resources of petroleum have yet been discovered in this area and few studies of potential source rocks have been carried out. In this study, the generation potential and thermal maturity of potential Cenozoic source rocks are investigated on the basis of Rock‐Eval analyses of core and cuttings samples and organic petrographic observations. Hydrocarbon generation, migration and entrapment are evaluated from 2D basin modelling along two seismically‐derived profiles, oriented east‐west and north‐south across the Gorgan Plain area. The models used input data from ten wells.Rock‐Eval analysis of 65 samples from well C in the Gorgan Plain show that organic‐rich intervals with source rock potential are present in the Paleocene‐Eocene section (1.1% TOC) and in the Pliocene Cheleken Formation (1.5% TOC). These intervals in general contain organic matter of terrigenous origin (kerogen Type III) but have poor hydrocarbon generation potential (i.e. Rock‐Eval S1+S2). There is no evidence for an organic‐rich interval in the Oligocene – Miocene succession equivalent to the Maikop Group – Diatom Formation which is a major source rock in eastern Azerbaijan and the adjacent offshore.Results of 2D basin modelling indicate that potential source rocks in the Paleocene – Eocene and Pliocene (Cheleken Formation) intervals are thermally immature throughout most of the study area, but that their maturity increases westwards towards the centre of the South Caspian Basin due to the increasing thickness of the overburden. The source rocks may be sufficiently mature in kitchen areas (at depths of more than 4000 m) to have generated hydrocarbons which may have migrated laterally updip to the basin margins.

Inversion Characteristics of Hydrocarbon Gases Carbon Isotopes Varying With Temperature and Implications for Shale Exploration

In order to understand the influence of source rock types and maturity on hydrocarbon gases carbon isotope change more objectively, a closed-system pyrolysis experiment was carried out on six samples from 250 to 550°C. The values of δ13C1, δ13C2, and δ13C3 were ranged from −73.3 to −29.8%, from −36.3 to −9.5%, and from −38.5 to −12.4%, respectively. The range of δ13C1 was the largest, reaching a top value of 43.5%. The results showed that the temperature has an effect on the carbon isotope value of pyrolysis gas. With the increase of the degree of thermal evolution, the carbon isotope value of methane in all samples, except for huangxian gangue, had a change trend from heavy to light firstly, then got heavier. In addition, the carbon isotope values of methane, ethane and propane had the features of δ13C1 &amp;lt; δ13C2 &amp;lt; δ13C3 when the temperatures were under 550°C, which were made up of a series of positive carbon isotopes. However, when the temperature increased above 550°C, there was an inversion of the simulated gas carbon isotope values in Huangxian coal gangue, Minqin oil shale and Huaan carbonaceous shale, i.e., δ13C2 &amp;gt; δ13C3 and δ13C2 &amp;gt; δ13C1. It indicates that the secondary cracking has occurred at high maturity or over maturity stage.

Peculiarities of Tertiary petroleum systems evolution under prograding shelf environment on the continental margin of the East Siberian Sea

The upper part of the sedimentary cover within the East Siberian Sea shelf comprises Cenozoic clinoform deposits, which accumulated in passive continental margin settings. In the Eastern Arctic, the productivity of clinoform deposits has been proved on the Alaska North Slope and in the Beaufort–Mackenzie Basin. Considering that Cenozoic clinoform deposits are widely represented in the Russian part of the Eastern Arctic, they undoubtedly attract considerable interest from the standpoint of hydrocarbons prospecting. However, despite increasingly closer attention to this interval of the sedimentary section, it is still poorly understood due to its complicated geology. The lack of drilled wells in the region imposes a considerable limitation on an understanding of sedimentary basins development. In this situation, geophysical data become the primary source of information for building geologic models in the Russian sector of the Eastern Arctic. An assessment of hypothetical Cenozoic petroleum systems of the East Siberian Sea is the main objective of this paper. It is to be said research performed under high uncertainty of input data. The results obtained from basin analysis and numerical modeling indicate the possibility that an active petroleum system may exist in the Cenozoic sedimentary wedge of the East Siberian Sea. The outlook for the clinoform complex largely depends on the source rock maturity, i.e., higher prospects should be expected in areas where the prograding wedge has maximum thickness. Considering all factors (reservoir quality prediction, proximity to a hydrocarbon kitchen, timing), the Eocene–Oligocene part of the sedimentary section appears to offer the greatest promise within the study area. Here, predominantly oil accumulations may be expected at a depth of 2.5–3.5 km below sea bottom.