Hydrocarbon Expulsion Research Articles

Generation and evolution of overpressure caused by hydrocarban generation in the Jurassic source rocks of the central Junggar Basin, northwestern China

The Jurassic black mudstone and coal beds in the central Junggar Basin, northwestern China, are the major source rocks for the basin with type II2 and type III (gas-prone) kerogens. Widespread overpressures are developed in the Jurassic stratigraphic interval. Sonic and resistivity logs display strong characteristic responses of overpressure in the mudstones, with anomalously high acoustic traveltimes and low resistivity compared with the normally pressured mudstones. The overpressured Jurassic sediment sequences appear to have undergone normal compaction because the mudstones exhibit no anomalously low bulk density. The overpressured mudstones deviate from the normally pressured mudstones in density–effective vertical stress space. The overpressure in the Jurassic source rocks is, therefore, not caused by disequilibrium compaction. The overpressured Jurassic sandstone reservoirs are predominantly oil and gas saturated or oil bearing. The well-log responses of the overpressured mudstones and seismic velocity characteristics indicate that the top depth of the overpressure zone ranges from 3800 to 4600 m (12,500 to 15,100 ft), corresponding to formation temperatures of approximately 94°C to 111°C (∼201°F to 232°F), with estimated vitrinite reflectance values of 0.6% to 0.75%. The Jurassic source rocks with overpressure are capable of generating hydrocarbons at present and are currently overpressured. All the evidence suggests that the overpressure in the Jurassic source rocks in the central Junggar Basin is caused by hydrocarbon (HC) generation. The overpressure evolution was modeled quantitatively in response to pressure changes caused by HC generation during basin evolution. The results indicate that multiple episodes of overpressure development and release occurred within the Jurassic source rocks, suggesting multiple episodes of HC expulsion. The timing and numbers of these episodes of HC expulsion were thus determined from the modeled overpressure evolution.

Quantification models of overpressuring in Paleogene source rocks of the Raoyang Depression, Bohai Bay Basin, China

Abstract Much progress in studies on the quantifications of overpressuring has been made during the past decades, and various quantitative models for the overpressure have been built based on overpressure transfer, tectonic extrusion, disequilibrium compaction, hydrocarbon generation, and other processes. In the Raoyang Depression of the Bohai Bay Basin in China, overpressure is mainly generated due to disequilibrium compaction and hydrocarbon generation. However, the overpressure-generation mechanism varies significantly in the overpressured formations and sags. The overpressure genesis in the Dongying Formation (Ed) occurs by disequilibrium compaction, but the overpressure mechanism in the first member (Es1) and third member (Es3) of the Shahejie Formation is a combination of disequilibrium compaction and hydrocarbon generation. The overpressure is caused by the difference in hydrocarbon generation before and after hydrocarbon expulsion. On the basis of the law of volume conservation, three quantitative models have been established for the under-compacted interval, the hydrocarbon-generation-to-expulsion interval, and the post-hydrocarbon-expulsion interval. The contribution of hydrocarbon generation differs in four sags developed in the Raoyang Depression due to differences in the hydrocarbon-generation capacity. Calculations based on these quantitative models indicated that the contributions of hydrocarbon generation to overpressure at the bottom of the Es1 and Es3 members in the Maxi Sag are 54.3% and 39.1%, respectively. The excessive pressure in the lower strata was stronger than that in the upper strata due to the fact that the contribution ratio of hydrocarbon generation to overpressure in the Es1 member is lower than that in the Es3 member, unlike in the case when the pressure in the upper strata is stronger than that in the lower strata. Therefore, it indicated that hydrocarbon generation plays an important role in the overpressure-generation mechanism.

Shale gas content evolution in the Ordos Basin

Gas content is a crucial parameter for shale reservoir evaluation and shale gas accumulation. Taking Shanxi and Taiyuan Formation shale samples from the Ordos Basin of China as an example, this research used thermal simulation, Rock-Eval pyrolysis, total organic carbon content (TOC) measurement, vitrinite reflectance (Ro) measurement, X-ray diffraction analysis, and methane isothermal adsorption based on formation conditions to study the evolution of shale gas content. A thermogenic gas content model was established through thermal simulation, Rock-Eval pyrolysis, and Ro measurement, while the influential factors of adsorbed gas content were analysed and a model was established through TOC and Ro measurements, X-ray diffraction analysis, methane isothermal adsorption, and reservoir conditions. Then, the research characterized the evolution of thermogenic gas, gas-in-place (GIP), adsorbed gas, and free gas through geologic time using a combination of thermogenic gas content, hydrocarbon expulsion and adsorbed gas content models.

The pore structure of the transitional shale in the Taiyuan formation, Linxing area, Ordos Basin

The in-depth study of the pore structure and its controlling factors of shale reservoir has important guiding significance for further exploration and exploitation of shale gas. Therefore, 10 transitional shale samples were collected from the Taiyuan formation in the Linxing area, Ordos Basin, and experiments on geochemical constitution, low-temperature gas adsorption were carried out. Based on the experimental results, the material composition, pore features and its controlling factors of the transitional shale were analyzed. The results show that the total organic carbon (TOC) content of the transitional shale in the Linxing area ranges from 0.73% to 10.20%, and the thermal evolution of organic matter (OM) is in a stage of mature to highly mature. In addition to small quantities of feldspar, siderite and pyrite, the two main components of this shale are 52–71% of clay minerals and 24–45% of quartz. The clay minerals are composed of kaolinite, accounting for 23%–74% of the total clay minerals, followed by an illite mixed layer, illite and chlorite. Mesopores are the major contributor to pore volume (PV), while macropores contribute the least to the PV. The contribution of micropores to the specific surface area (SSA) is greater than 78%, followed by mesopores. Macropores have almost no contribution to the development of the SSA. The OM types, hydrocarbon expulsion intensity control the influence of TOC content on pores development. The total amount of clay minerals is beneficial to the development of PV and SSA, which is mainly attributed by chlorite and illite mixed layer. Compared with the marine shale, the brittle minerals inhibit the development of pores in the transitional shale.

Petrographic and sorption-based characterization of bituminous organic matter in the Mandal Formation, Central Graben (Norway)

The Upper Jurassic Mandal Fm. of the Central Graben, Norway represents an important source rock that charged major petroleum accumulations in the North Sea, including the giant Ekofisk field. Nevertheless, exploration to date has been less successful than expected in marginal basin position such as the Cod Terrace, the Mandal High or the Søgne Basin, probably due to higher proportions of thermally stable (type III) kerogen. In an attempt to delineate changes in initial kerogen composition from later effects such as delayed expulsion of hydrocarbons, traditional organic petrography and scanning electron microscopy were combined with organic geochemical proxies and gas adsorption tests. The kerogen composition of the Mandal Fm. shows considerable variation. Samples hosting autochthonous coaly layers were found in wells from the Søgne Basin and the Cod Terrace, for which less generative potential was previously postulated. Nevertheless, samples hosting mainly vitrodetrinite were also found in basinal wells. A correlation of total organic carbon contents with liptinite percentages highlights enhanced bioproductivity or preservation efficiency for samples with abundant algal organic matter, that were likely deposited under deeper water and possibly oxygen-depleted conditions. By combining organic geochemical proxies with nitrogen sorption data, it could be proven that in case of the Mandal Fm., the (bituminous) organic matter fraction represents the controlling factor on abundance of micro- and mesopores and hence adsorptive gas retention. The amount of bitumen extractable from the Rock-Eval S2 peak (S2bitumen) shows a strong correlation with the total inner surface area, suggesting that small mesopores (<10–15 nm) are mainly associated with the high-molecular bituminous fraction represented by the S2bitumen, which appears non-porous at SEM-scale. Furthermore, the total inner surface area decreases strongly with thermal maturity, documenting a change in pore characteristics of the organic matter fraction (growth of mesopores and occurrence of macropores) by advancing hydrocarbon generation. Pyrobitumen-rich Upper Visean reference samples at peak oil and early wet gas window maturity show intense sponge-like pyrobitumen-hosted porosity coinciding with a low relative proportion of S2bitumen (high petroleum quality). Pyrobitumen is not affected by solvent extraction, thus not contributing high-molecular weight compounds to the extracted fraction. Such inert meso- to macroporous residues might contribute only relatively little to gas sorption capacity, but might represent important storage space for free gas, as well as flow pathways during expulsion.

Hydrocarbon generation and expulsion characteristics of the source rocks in the third member of the Upper Triassic Xujiahe Formation and its effect on conventional and unconventional hydrocarbon resource potential in the Sichuan Basin

Abstract The third member of the Upper Triassic Xujiahe Formation (T3x3) is a typical source-reservoir-cap unit for natural gas exploration in the Sichuan Basin. However, most previous studies mainly focused on the T3x3 as a source rock, ignoring its role as a reservoir. As a result, the evaluation of hydrocarbon resource potential was not accurate. This study established a hydrocarbon generation and expulsion model through analyzing the geological and geochemical characteristics of the T3x3 source rocks, and calculated the resource potential of conventional gas, tight gas and shale gas systematically with combining the lower boundary of buoyancy-dominated accumulation (LBBA). The results indicated that the thickness of the source rocks dominated by mudstone was distributed widely, with an average value of more than 45 m. The sedimentary environment was salty lacustrine deposits. They have a high content of total organic carbon (TOC) with an average value of 4.80 wt%, the kerogen is mainly type III with minor type II, and the thermal evolution has entered the high to over mature stage. The hydrocarbon generation threshold was determined to be 0.5%Ro, while the hydrocarbon expulsion threshold and the LBBA were determined to be 0.83%Ro and 1.12%Ro, respectively. The efficiency of hydrocarbon expulsion was relatively high, with an average of about 56%. Also, the maximum hydrocarbon generation and expulsion intensity reached to 110 × 108 m3/km2 and 53 × 108 m3/km2. The amounts of hydrocarbon generation, expulsion and residual associated with the T3x3 source rocks were 125.68 × 1012m3, 70.38 × 1012m3, and 55.30 × 1012m3, respectively. Under the criterion condition of the LBBA, the conventional gas resource was 7.21 × 1010m3, the tight gas resource was 294.34 × 1010m3, and the shale gas resource was 2488.50 × 1010m3. It indicated good prospects for exploration.

The characteristics and hydrocarbon-generation model of Paleogene\u2013Neogene System saline lacustrine facies source rocks in the Western Qaidam Basin, China

To further understand the characteristics and hydrocarbon-generation model of Paleogene–Neogene System salt-lake facies source rocks in the Western Qaidam Basin, selecting argillaceous source rock samples from the Lower Ganchaigou Formation, the Upper Ganchaigou Formation, and the Upper Youshashan Formation in the Western Qaidam Basin, relevant experimental studies have been carried out, including pyrolysis of rocks, analysis of soluble components, and simulation of hydrocarbon generation and expulsion. According to the analysis of the experimental results, the selected sample thermal evolution degree stays in the low-mature–immature stage and shows good hydrocarbon-generation ability. There was a positive correlation between chloroform bitumen “A,” moderate salt content and carbonate content, and cumulative liquid hydrocarbon production. The hydrocarbon-generation peaks of the Paleogene–Neogene salt-lake facies source rocks in the Western Qaidam Basin are significantly advanced compared to the traditional model. The result clearly defines the hydrocarbon-generation model of Paleogene–Neogene salt-lake facies source rocks in the study area, which is important to direct the oil and gas exploration in the Western Qaidam Basin.

Full-scale pore structure and its controlling factors of the Wufeng-Longmaxi shale, southern Sichuan Basin, China: Implications for pore evolution of highly overmature marine shale

Shale gas primarily exists in nanopores in shale as different occurrence phases. Studies on pore structure characterization and its controlling factors are the key to understand shale gas occurrence and gas accumulation mechanism. Mercury intrusion capillary pressure (MICP), low-pressure N2 and CO2 adsorption were applied to quantify pore structure of all sizes for Wufeng-Longmaxi shale from southern Sichuan Basin, China. These shales are currently highly overmature, and their total organic carbon (TOC) contents range from 0.04% to 5.19%. Quartz content is positively correlated with TOC content in the clay-poor shales, whereas it exhibits no correlation with TOC in the clay-rich shales. Different relationships are likely due to difference in quartz origins, since the clay-poor shales contain more biogenic quartz than the clay-rich shales. Furthermore, multimodal pore size distributions were observed. Total pore volume, ranging from 1.41 to 3.03 cm3/100 g, is mainly provided by pores less than 10 nm in diameter, whereas most of the specific surface area, ranging from 19.55 to 36.64 m2/g, is provided by pores less than 2 nm in diameter. Organic matter contributes mostly to micro- and mesopore development. Clay minerals, mainly illite, also make a contribution to pore structure, especially in the organic-lean shales. The porosity development of micro- and mesopores is also controlled by thermal evolution of organic matter. Micro- and mesopores were developed at the immature to early mature stages due to pore rearrangement, expulsion of liquid hydrocarbon, and dissolution of unstable minerals. The following decrease during the late mature stage was mainly caused by oil and bitumen infill. Both micro- and mesopores were reopened at the postmature stage, which was driven by the secondary cracking of residual oil and bitumen. The final significant decline of micro- and mesopore volumes at the overmature stage was caused by persistent compaction and OM carbonization.

Spatial-temporal coupling between high-quality source rocks and reservoirs for tight sandstone oil and gas accumulations in the Songliao Basin, China

The spatial-temporal relationship between high-quality source rocks and reservoirs is a key factor when evaluating the formation, occurrence, and prospectivity of tight oil and gas reservoirs. In this study, we analyze the fundamental oil and gas accumulation processes occurring in the Songliao Basin, contrasting tight oil sand reservoirs in the south with tight gas sand reservoirs in the north. This is done using geochemical data, constant-rate and conventional mercury injection experiments, and fluid inclusion analyses. Our results demonstrate that as far as fluid mobility is concerned, the expulsion center coincides with the overpressure zone, and its boundary limits the occurrence of tight oil and gas accumulations. In addition, the lower permeability limit of high-quality reservoirs, controlled by pore-throat structures, is 0.1 × 10−3 μm2 in the fourth member of the Lower Cretaceous Quantou Formation (K1q4) in the southern Songliao Basin, and 0.05 × 10−3 μm2 in the Lower Cretaceous Shahezi Formation (K1sh) in the northern Songliao Basin. Furthermore, the results indicate that the formation of tight oil and gas reservoirs requires the densification of reservoirs prior to the main phase of hydrocarbon expulsion from the source rocks. Reservoir “sweet spots” develop at the intersection of high-quality source rocks (with high pore pressure) and reservoirs (with high permeability).

Lithologic heterogeneity of lacustrine shale and its geological significance for shale hydrocarbon-a case study of Zhangjiatan Shale

Abstract The Zhangjiatan shale of the Southeastern Ordos Basin, which deposits in deep lake facies, has strong lithologic heterogeneity; it represents as shale, sandy laminae shale and thin sandstone. Shale with mm- to cm-scale sandy laminae is defined as Sandy Laminae Shale (SLS). However, the relationship between lithologic heterogeneity and hydrocarbon accumulation has never been studied. This study shows that lithologic heterogeneity, especially the occurrence of SLS will influence the accumulation of hydrocarbons within the shale system. SLS commonly has a larger pore size, higher porosity and better connectivity than thick and homogeneous shale. SLS commonly contains fewer residual hydrocarbons than homogeneous thick shale, indicating comparative ease in hydrocarbon expulsion. SLS commonly generates more bedding fractures. More fractures can be incurred when fracture extending into SLS. The occurrence of SLS can provide more storage spaces for fluids and gases, including oil, water, adsorbed gas, dissolved gas and free gas. SLS has been the pilot exploration and development target for shale hydrocarbon in the southeastern Ordos Basin. Homogeneous and thick shales, which have a large content of residual hydrocarbons, would be the targets for future exploration.

The influence of the thermal aureole asymmetry on hydrocarbon generative potential of coal beds: Insights from Raniganj Basin, West Bengal, India

The aim of the present study is to uncover hydrocarbon generation potential of an area intruded by lamprophyre dyke. Lamprophyre dyke induced a short-distance asymmetric thermal aureole in coal beds with more intense impact along the dip direction. Large ash yield, carbon content, lower volatile matter content, hydrogen indices, presence of natural coke, disordered kaolinite peaks, less pronounced aliphatic peaks, higher aromaticity under Fourier Transform Infra-Red spectroscopy (FTIR); highly rugged surface and large pores with the aid of Atomic force microscopy (AFM); abundant calcium carbonate mineral phases (calcite, dolomite, ankerite) and high-temperature silica phases (tridymite, sanidine) under X-ray diffraction (XRD) are the consequences of pronounced thermal effect and expulsion of hydrocarbons. Furthermore, the estimated vitrinite reflectance (EVRo) calculated through maximum pyrolysis temperature (Tmax) and measured mean random vitrinite reflectance (VRo) show the maximum difference in the heat-affected coal samples. In addition, parameters for source rock reconstruction and indices for quantification of FTIR spectra i.e. index of aliphaticity (IAL), index of aromaticity (IAR) and index for hydrocarbon generation (IHG) are introduced for coals. The distant (i.e. least-heat-affected) coals collected opposite to the dip direction of the coal bed have a higher potential for hydrocarbon generation. The igneous intrusion thus played a significant role in enhancing the maturity of the organic material, in turn, augmenting the hydrocarbon generation potential for targeting hydrocarbon plays of the area although at the expense of proximal samples.

Stable isotope reversal and evolution of gas during the hydrous pyrolysis of continental kerogen in source rocks under supercritical conditions

Semi-closed hydrous pyrolysis experiments were conducted to investigate the isotopic evolution of shale gas produced from continental organic-rich shales with increasing thermal maturity and prospecting potential. The δ13C values of methane, ethane, propane and n-butane became heavier with increasing thermal maturity and showed good relationships with vitrinite reflectance (VR). Gases expelled from type-I, type-II, and type-III kerogens followed the normal carbon sequence (δ13CC1 < δ13CC2 < δ13CC3 < δ13CnC4) and the hydrogen isotopic sequence (δ2HC1 < δ2HC2 < δ2HC3 < δ2HnC4 < δ2HiC4) among the alkanes at VRs lower than 2.14% Ro, 2.42% Ro, and 1.87% Ro respectively. The isotopically reversed gases (δ13CC1 < δ13CC2 < δ13CnC4 < δ13CC3) were observed in type-I kerogen with a VRs above 2.14% Ro and in type-II kerogen with a VR above 2.42% Ro. In type-III kerogen, isotopically reversed gases (δ13CC1 < δ13CnC4 < δ13CC3 < δ13CC2) were observed with a VR above 2.94% Ro. These results suggest four stages in the stable carbon isotope reversal of ethane, propane, and n-butane with increasing maturity. The isotopically reversed gases (δ13CC1 < δ13CC2 < δ13CnC4 < δ13CC3) may represent lower maturity and higher productivity shale gas than the isotopically reversed gases (δ13CC1 < δ13CnC4 < δ13CC3 < δ13CC2), indicating that continental type-I kerogen has the highest potential productivity for shale gas, and continental type-III kerogen has the lowest. Stable hydrogen isotope composition did not respond to the stable carbon isotope reversal in isotopically reversed gases. We suggest that indigenous generation and mixing may be the dominant mechanisms responsible for the stable carbon isotope reversal, and adsorption/desorption during hydrocarbon expulsion may promote the stable isotope reversal under semi-closed conditions. Overall, these results suggest that this study is an important contribution to continental shale gas exploration.

Carbonate source rock with low total organic carbon content and high maturity as effective source rock in China: A review

Carbonate rocks with high maturity and low total organic carbon content are widely distributed in China. Whether they can be effective source rocks remains controversial, but they have great significance for the evaluation of hydrocarbon generation potential and exploration prospects of carbonate rocks. Dataset reveals that as the depth or maturity increases, total organic carbon (TOC) content, atomic H/C ratio, and hydrocarbon generation potential of carbonate source rocks with low total organic carbon (CSRLTOC) all decrease because of hydrocarbon expulsion. Moreover, some pyrolysis experiments also indicate that the CSRLTOC are able to generate and expel a quantity of hydrocarbons. The above studies indicate that CSRLTOC can be effective source rocks for oil/gas pools. The unique features of carbonate rocks and CSRLTOC demonstrate that they are easier to expel hydrocarbons and contribute to oil/gas reservoirs than shale, and thus, the lower limit of TOC (LLTOC) of effective carbonate source rocks could be smaller than shale (0.5%). The LLTOCs of effective carbonate source rocks with type I-II1 kerogen (mainly sapropelic group) at the levels of immaturity and low maturity, maturity, high maturity and over maturity are TOC = 0.5%, 0.5–0.3%, 0.3–0.2%, and 0.2–0.1%, respectively. If the carbonate source rocks are at the high-over mature stage, we could take 0.2% as the LLTOC. The present organic-poor source rocks with high maturity are possibly moderate or good source rocks at the low mature level in the geological periods, especially carbonate source rocks if type I-II1 kerogen. Some typical oil and gas fields in China derive partly or mostly from the CSRLTOC, proving that CSRLTOC could be effective source rock in China.

Diagenesis of the Sappington Formation in the Bridger Range, Montana: Implications for the burial and thermal history of the Western Crazy Mountain Basin

The Devonian-Mississippian Sappington Formation in the Bridger Range, Montana was investigated for its paragenetic sequence and thermal history. These results were used to establish a burial history for the area and compared to data from nearby oil and gas wells. The paragenetic evolution of the Sappington includes early diagenetic feldspar dissolution, formation of quartz overgrowths, and illite precipitation during early diagenesis at temperatures &lt; 50 °C. Subsequent burial diagenesis resulted in the precipitation of non-ferroan and ferroan dolomite, followed by calcite cementation and replacement, pyrite replacement, and hydrocarbon generation and expulsion at temperatures &gt; 130 °C. Devonian formations were the source of the non-ferroan dolomite cement and began precipitating in the latest Mississippian. Subsequent growth of ferroan dolomite resulted from clay transformation reactions in the Upper and Lower Sappington Members and was initiated during rapid burial in the late Cretaceous. The Bridger Range and the adjacent Western Crazy Mountain Basin underwent similar Paleozoic and Mesozoic burial histories. Vastly different Cenozoic burial histories resulted from movement along the Cross Range and Pass thrusts that caused the Bridger Range to begin uplift prior to the cessation of deposition of the Livingston Group in the early Paleocene. The discrepancies in burial history caused the Sappington Formation to reach a maximum temperature of ~135 °C in the Bridger Range and ~230 °C in the western Crazy Mountain Basin.

Hydrocarbon accumulation conditions and key exploration and development technologies for PL 19–3 oilfield

The PL 19–3 Oilfield is the only super-large monolithic oilfield with oil and gas reserves up to 1 × 109 t in the Bohai Bay Basin, and it has been successfully developed. Exploration and development practices have provided abundant data for analyzing formation conditions of this super-large oilfield. On the basis of the exploration and development history, fundamental reservoir features, and with available geological, geophysical and test data, the hydrocarbon accumulation conditions and key exploration & development technologies of the PL 19–3 Oilfield were discussed. The key conditions for forming the super-large Neogene oilfield include four aspects. Firstly, the oilfield is located at the high position of the uplift that contacts the brachy-axis of the multi-ridge slope in the biggest hydrocarbon-rich sag in the Bohai Bay Basin, thus it has sufficient hydrocarbon source and extremely superior hydrocarbon migration condition. Secondly, the large-scale torsional anticlines which formed in the Neogene under the control of the Tanlu strike-slipping movement provide sufficient storage spaces for oil and gas preservation. Thirdly, the “multiple sets of composite reservoir-caprock assemblages” developing in the special shallow-water delta further contributes greatly to the effective storage space for oil and gas preservation. Fourthly, due to the coupling of the uplift and strike slip in the neotectonic period, extensive faulting activities constantly released the pressure while the late period massive hydrocarbon expulsion of the Bozhong took place at the same time, which assures the constant and intense charging of oil and gas. The super-large PL 19–3 Oilfield was controlled by the coupling effects of all those special geologic factors. In view of this oilfield's features (e.g. violently reformation caused by strike slip, and the special sedimentary environment of shallow-water delta), some key practical technologies for exploration and development have been developed. Such technologies include: the special prestack depth migration processing for gas cloud zones, the prediction of thin interbed reservoirs based on high-precision inversion of geologic model, the reservoir description for the shallow-water braided river delta, the quantitative description for remaining oil in the commingled oil reservoirs with wide well spacing and long well interval, and the well pattern adjustment for formations during high water cut period in the complex fluvial-facies oilfields.

Petroleum generation and expulsion in the Lower Palaeozoic petroleum source rocks at the SW margin of the East European Craton (Poland)

In this work, 1-D numerical modelling of petroleum generation and expulsion processes in the Upper Ordovician and Lower Silurian source rocks was carried out in over sixty wells along the SW margin of the East European Craton ( EEC) in Poland. Lower Palaeozoic sediments were subjected to rapid burial in the Palaeozoic and then were uplifted in several phases, but with the predominance of the late Variscan tectonic inversion. The thermal maturity of organic matter in the Lower Palaeozoic strata indicates the advancement of the generation processes from the phase of low-temperature thermogenic processes in the NE part of the Baltic and Podlasie-Lublin basins to the overmature stage along the zone adjacent to the Teisseyre-Tornquist Zone (TTZ). The results of modelling of generation and expulsion show that these processes took place mainly in the Devonian and Carboniferous periods and in the westernmost part (along the TTZ), even in the latest Silurian. The hydrocarbon expulsion took place with a small – delay after generation. During the Mesozoic and Cainozoic, generation processes practically were not resumed or intensified. Nevertheless, it was found that zones with an increased shale gas potential can occur only in a relatively narrow belt on the SW slope of the EEC, parallel to the edge of the TTZ. The most promising seem to be Caradocian, Llandovery and the Wenlock between the Lebork IG-1 and Kościerzyna IG-1 wells in the Baltic Basin, and the Wenlock source rocks in the Podlasie-Lublin Basin between the Okuniew IG-1, Łopiennik IG-1 and Narol IG-1 wells. Most of the hydrocarbons were subjected to expulsion and possible migration. As a result, there was a large dispersion of the hydrocarbons generated. The chance of preservation of these hydrocarbons in the source rocks is small.

Geochemical characteristics and resource potential analysis of Chang 7 organic-rich black shale in the Ordos Basin

AbstractThe Ordos Basin is the largest and most important intracontinental sedimentary depression in China, and a significant amount of crude oil resources has developed within this Mesozoic formation. High-grade organic-rich shale is prevalent in the large-scale areas of the Chang 7 sedimentary stage and provides essential hydrocarbon resources for abundant oil enrichment in the Mesozoic. This research investigated the geochemical characteristics of Chang 7 shale using core samples and well logs and via laboratory tests. In addition, the microscopic components of the shale organic matter (OM), biological marker compounds, carbon isotopes, enrichment grade of trace elements, and elemental ratio were analysed systematically. Moreover, the aspects related to the shale OM source, sedimentary environment and resource potential were evaluated. Our results revealed that spherical alginate and calcium spherical alginate were predominant in the micropetrological components of the shale. Many biomarkers, including n-alkanes, steranes and terpanes, were detected in the gas chromatography – mass spectrometry spectra. An analysis of n-alkanes, regular sterane shapes (C21−/C22− and C26+C27/C28+C29), odd–even predominance index (OEP) and carbon preference index (CPI) values and carbon isotope distributions showed that OM was produced from aquatic organisms. The indicators of trace elements, such as Sr/Ba and V/V+Ni, combined with the biomarker compound in Pr/Ph and the gammacerane index showed the presence of a semi-deep – deep lake environment containing fresh–brackish water. In addition, the hydrocarbon conversion rate index and shale rock pyrolysis parameters revealed that Chang 7 has a high hydrocarbon generation ability and hydrocarbon expulsion efficiency.

The effect of diagenetic environment on hydrocarbon generation based on diagenetic mineral assemblage in mudstone

The diagenetic mineral assemblages in mudstones during diagenesis can indicate the changing diagenetic environmental characteristics, providing possibility to study the influence of the diagenetic environment on the evolution of organic matter (OM). In the present study, mudstones from the Dongying Depression were selected and evaluated by X-ray diffraction (XRD), thin section, and scanning electron microscopy (SEM). The SEM and XRD results indicated that detrital minerals are depositional minerals, whereas clay minerals are diagenetic minerals; carbonate are a combination of depositional and diagenetic minerals. According to the diagenetic mineral content and content change rates, three diagenetic mineral assemblages were distinguished: I. smectite/I-S (1,000–2,000 m); II. Smectite/I-S + illite + kaolinite (2,000–3,000 m); III. Smectite/I-S + illite + chlorite + ankerite (>3,000 m). Kaolinite is formed in acidic environments, while the other diagenetic minerals are formed and stable under alkaline conditions. Therefore, the evolution of the diagenetic environment was investigated using the K/(I + Ch + A) ratio (K:Kaolinite; I:Illite; Ch:Chlorite; A:Ankerite), and the formations were found to have undergone alkaline-acidic-alkaline changes. For OM with different chemical properties, huge differences exist in hydrocarbon generation between acidic and alkaline diagenetic environments. Therefore, for hydrocarbon generation, attention should be paid to the changes in diagenetic environment, which are important for understanding the hydrocarbon generation, hydrocarbon expulsion and hydrocarbon accumulation in mudstones.

Source rock evaluation and thermal maturity modeling of Jake oil fields, Fula sub-basin, Muglad Basin, Sudan

Comprehensive source rock evaluation, burial history modeling, and thermal maturity of oil generation have been investigated in petroleum system of Jake oil fields. The consideration of geological, geochemical, and palynofacies data was used for source rock and thermal maturity. Basin Mod® software was applied to construct the burial and thermal histories and to determine the timing of hydrocarbon generation and expulsion. The modeling was achieved through transient heat flow and collaborated with measured %Ro. The Lower Cretaceous Abu Gabra Formation was believed to be organic-rich shale and characterized by source rock of excellent abundance and potential that possesses total organic carbon (TOC) ranging from 0.37 to 6.27 wt% and production yield 1.31–49.23 mg HC/g rock. Kerogens can be classified as oil-prone types I–II. Vitrinite reflectance (Ro) and Tmax values suggested that most samples were of early maturation for oil generation. Palynofacies and geochemical combination indicated that amorphous phytoclasts of plant debris were dominated by high TOC and hydrogen index (HI), whereas assemblage kerogens confirmed the presence of oil source rock. Geohistory models showed the highest rapid subsidence rates during the Early-Late Cretaceous. The results demonstrated that petroleum could be generated in the upper (1950–2500 m) and the lower intervals (2550 total depth) of Jake South field. Maturity and hydrocarbon generation modeling indicated that the source rocks reached the early maturation stage in the Early Cretaceous (127 Ma) at a temperature of 90 °C. The middle maturation stage began in the Late Cretaceous (64 Ma) with a temperature of 110 °C. Essential oil generation started approximately 63 Ma ago and continues to the present day.

Data for: Organic geochemistry of the Upper Triassic T3x5 source rocks and the hydrocarbon generation and expulsion characteristics in Sichuan Basin, Central China

Abstract The Upper Triassic Xujiahe Formation is a key target layer for development of tight sandstone gas reservoirs in the Sichuan Basin. Most of the previous work focused on the main reservoirs such as T3x2 and T3x4 with lack of research attention on T3x5, an equally important source-reservoir unit. Here we examine the organic matter and source rock distribution in the T3x5 using rock pyrolysis, asphalt extraction, and gas chromatography. The thickness of T3x5 source rocks reduces from west and northwest Sichuan Basin to east and southeast Sichuan Basin. The main sedimentary facies are salt lakes and deltas, of which the organic matter originated from aquatic organisms and a small amount of terrestrial matter. The abundance of total organic carbon (TOC) in T3x5 is relatively high, at values of 0.07%–7.2%. According to the vitrinite reflectance (Ro), pyrolysis, and gas chromatography measurement results, the T3x5 source rocks are at the stage of mature to over-mature, and their hydrocarbon expulsion threshold and hydrocarbon expulsion peak correspond to Ro of 1.05% and 1.23%, respectively. Furthermore, a hydrocarbon generation center and a hydrocarbon expulsion center are formed horizontally, with the maximum hydrocarbon generation intensity of 50 × 108 m3/km2 and the maximum hydrocarbon expulsion intensity of 48 × 108 m3/km2. The natural gas resource is 3.19–5.36 × 1012 m3, indicating great exploration potential.