Hydrocarbon Source Rocks Research Articles

Investigating the controls on architecture and facies distribution of a carbonate ramp to shelf system: Insights from stratigraphic forward modeling of the Jurassic Smackover Formation, Gulf of Mexico

To develop a better understanding of the controls on the stratigraphic architecture of carbonate systems, it is necessary to quantify the impact of the physical and chemical variables responsible. The growth, distribution, and nature of carbonate factories are dependent on various space and time-dependent variables, such as paleotopography, accommodation, sediment supply, energy and slope of the system, and water chemistry.The Upper Jurassic Smackover Formation is a heterogeneous hydrocarbon source rock and reservoir in the semi-restricted Conecuh Embayment of southwestern Alabama. It consists of a lower transgressive unit composed of microbialite and mudstone/wackestone, and an upper regressive mixed carbonate-siliciclastic unit composed of oolitic packstone-grainstone, microbialite, bioturbated to laminated carbonate mudstone, and shale. The physiographic setting of the Conecuh Embayment, along with the variability in the carbonate factory types, eustatic sea level fluctuations, and sea-water circulation presents an exceptional site for evaluating the controls on carbonate platform/shelf margin to slope architecture.Stratigraphic forward modeling using DionisosFlow, calibrated with a geologic cross-section built from well log and core data, was carried out to test the impact of antecedent topography, accommodation, and carbonate factory type on the facies distribution and architecture of the carbonate shelf. Results of our study indicate that geometries in the transgressive Smackover shelf are controlled by accommodation and rate of carbonate production, while limited accommodation controlled the stratigraphic architecture of the regressive system.

Total Organic Carbon Logging Evaluation of Shale Hydrocarbon Source Rocks in the Shan 1 Section of the Sulige Gas Field, Ordos Basin, China

The mass fraction of total organic carbon (TOC) is one of the key indicators for evaluating the hydrocarbon generation potential of shale source rocks. Experimental measurements to evaluate the TOC content require significant cost and time. Furthermore, the experimental data are often fragmented and may not provide an accurate depiction of the source rocks throughout the entire block. To solve the above problems, this paper proposes to use the combination of conventional logging data and experimental data after an in-depth study of the geophysical characteristics of hydrocarbon source rocks in the Ordos Basin. A quantitative model between logging data and source rocks is established, and then the continuous distribution value of the TOC content in the hydrocarbon source rock interval is calculated. Firstly, the mud shale formation of the Permian–Shanxi Formation in the Upper Paleozoic, located in the Jingbian area of the Ordos Basin, is selected as the research target using the “Jinqiang method”. The model is constructed by selecting appropriate logging curves (acoustic time difference logging, resistivity logging, and density logging) and experimental results based on the response relationship between logging data and TOC data. This method provides more accurate and comprehensive data for source rock studies, combining experimental sampling to contribute to a better evaluation of TOC in source rock. The shale hydrocarbon source rock logging data from 10 wells are selected, and the model is used to realize the full-well section of the logging data to find the hydrocarbon source rock TOC, which is compared with the TOC data from the experimental core tested at a sampling point. The results demonstrate that the model is highly effective and accurate, with a mere 2.7% percentage error observed across 185 sample data points. This method greatly improves the accuracy and completeness of TOC evaluation compared with the results of previous studies and provides a guide for subsequent TOC logging evaluation of source rocks in other areas. With the study in this paper, continuous TOC values of source rocks are obtained, discarding the TOC values representing the whole set of hydrocarbon source rocks with a limited number of sample averages. This method can reflect the contribution of the layers with high and low organic matter abundance, and the calculated reserves are more accurate. By utilizing the measured TOC values of the study area to invert the model to find the parameters, this study contributes to the decision-making of hydrocarbon exploration in domestic and international basins.

Subsurface structures and nature of seafloor mounds in the northern South China Sea margin: Implications for Mesozoic hydrocarbon exploration

The Chaoshan Depression in the northern South China Sea (SCS) margin hosts thick (ca. 4–9 km) Mesozoic strata including two sets of hydrocarbon source rocks (the Late Triassic-Early Jurassic and Late Jurassic marine facies sequences). It was predicted to be petroliferous but unproven. Numerous submarine mounds are distributed on its seafloor, but whether they are mud volcanoes or magmatic volcanoes remains controversial due to poor knowledge of the subsurface structures. To reveal the nature of these mounds and the Mesozoic hydrocarbon potential in the Chaoshan Depression, multi-channel seismic (MCS) and ocean bottom seismometer (OBS) data along line CS-L1 across three seafloor mounds are processed and analyzed. The MCS profile reveals the existence of fuzzy reflection zones (FRZs) within the Mesozoic strata beneath these mounds. The overlying sedimentary sequences appear uplifted and deformed. The OBS velocity results exhibit that these FRZs feature significantly lower velocities than their host strata with velocity differences ranging from ∼0.25 km/s to 0.71 km/s, likely resulting from vigorous fluid charging rather than magma intrusion. Thus these FRZs are identified as mud-fluid diapirs. Between these diapirs and the overlying seafloor mounds, numerous high-angle faults exist, serving as vertical fluid feeder conduits. Additionally, several bright spots, acting as indicators of gas reservoirs, are observed near these faults. Moreover, bottom simulating reflectors with reverse polarity are imaged within the shallow strata around the seafloor mounds on an adjacent MCS profile, indicating rich gas trapping and/or gas hydrate accumulation. Therefore, we propose that these seafloor mounds are mud volcanoes with fluids coming from the underlying diapirs. As the diapirs extend downward into the Jurassic and Triassic strata, the hydrocarbon gases feeding the mud volcanoes and diapirs are reasoned to originate from the deep Mesozoic source rocks, implying significant Mesozoic hydrocarbon potential in the Chaoshan Depression of the SCS.

Technological issues in shale oil development using horizontal wells in Ordos Basin, China

The PetroChina Changqing Oilfield Company has successfully achieved large-scale economical development of continental low-pressure freshwater lake interlayer shale oil in the Ordos Basin, China, targeting the gravity-flow sandstone thin interlayers in the organically rich mud shale formation of the seventh member of Yanchang Formation (Chang 7 Member) of Triassic,. Their significant discovery of the 1-billion-ton-level Qingcheng shale oil field, with a proven reserve of 1.052 × 109 t, has marked the establishment of China's first million-ton shale oil development zone. However, the extensive growth in production and construction has brought attention to notable challenges, including geological variances, low initial production, rapid decline, low recovery rates, and high development costs. Based on extensive field experience, this paper identifies several technological issues in shale oil development and offers comprehensive recommendations through systematic analysis. The encounter rate of horizontal shale oil wells, crucial for enhancing individual well productivity, can be improved both vertically and horizontally by prioritizing the extension direction of high-quality reservoirs during the deployment of horizontal wells. The contribution of fracturing fluid elasticity to the recovery rate is relatively low. Reservoir modification should not overemphasize large sand volume, fluid volume, or discharge. Additionally, optimizing parameters such as well spacing, vertical interlayer distribution, and fracture development is essential for maximizing the efficiency of fracturing scale, operation discharge, and other parameters. Variability in hydrocarbon source rock quality and the strength of diagenesis significantly impact oil saturation in sand bodies, affecting the selection of favorable areas and the distribution of high-quality reservoirs. Furthermore, the utilization of pre-fracturing with CO2 proves to be an effective approach in reducing viscosity and increasing the ultimate recovery rate. To ensure the efficient development of shale oil in the Changqing Oilfield, this paper emphasizes the necessity of deepening integrated geological studies, clarifying the main controlling factors of shale oil heterogeneous accumulation, and meticulously depicting three-dimensional sweet spots while exploring more effective development methodologies.

Newly discovered Botryococcus-rich source rocks in the western Qaidam Basin, NW China and their implications for shale oil exploration in saline lacustrine basins

Owing to the high hydrocarbon content and photosynthetic efficiency of phytoplankton, planktonic microalgae account for the main source of petroleum hydrocarbons in marine and continental petroliferous basins. Therefore, the presence of algal residues in such basins is considered an important indicator of high-quality hydrocarbon source rocks. The southwestern region of the Qaidam Basin, characterized by lacustrine deposits from the Paleogene, has substantial petroleum resources. However, studies on the development of source rocks and the mechanisms involved in their organic matter enrichment are insufficient, thus hampering ongoing shale oil exploration efforts. Herein, abundant Botryococcus fossils were discovered in the main source rocks of the upper member of Xiaganchaigou Formation of Paleogene in Southwest Qaidam, accounting for >50 % of the total organic matter content. The palynofacies assemblages reflected relatively distal and oxygen-rich sedimentary environments. The algae-rich rocks usually exhibited distinctive laminated structures alternately composed of quartz-feldspathic, clay and carbonate laminae, indicating periodic climate fluctuations. The Botryococcus, which was mainly preserved in the coarse-grain quartz-feldspathic laminae, probably reflected heavy precipitation conditions and subsequently high nutrient inputs. Finally, the oxygen-rich, low salinity and eutrophic water was likely taking form which benefit the growth of these hydrobiontic algae. These algal-rich shales exhibited typically high hydrogen index (IH) and total organic carbon (TOC) values, indicating their high hydrocarbon-generation potential. Thus, they are important marker beds for high-quality source rocks in petroliferous basins. Concurrently, the coarse-grained detrital mineral laminae displayed excellent reservoir physical properties, probably providing sufficient reservoir space for planktonic algae-derived liquid hydrocarbon. Therefore, these Botryococcus-rich source rocks might represent important targets for ongoing shale oil exploration.

Petrographic and geochemical analysis of Barmer Basin Paleogene lignite deposits: Insights into depositional environment and paleo-climate

The current study attempts to characterize the samples from Kapurdi, Giral and Sonari lignite mines of Barmer Basin within Rajasthan Tertiary Lignite deposits using petrographic and geochemical techniques. The data generated has been studied in order to better understand the geochemical properties, hydrocarbon potential, depositional environment and paleo-climatic condition of the paleo-mires of these lignites. The proximate analysis of the samples reveals that the average ash content of the Barmer Basin is 11.93 %, the average moisture content is 14.08 %, average volatile matter yield is 42.03 % and the average fixed carbon is 31.95 %, which suggesting that the physical properties of lignite are dominated by volatile matter on dry basis. The ultimate investigation reveals the chemical properties of the lignite with the average carbon content found to be 58.79 wt%, hydrogen value 3.83 wt%, nitrogen percentage 1.60 wt% and sulphur content 2.75 wt%. This clearly indicates high sulphur concentration in Barmer lignite deposits, based on dry basis. The lignite samples subjected to FTIR studies identified aliphatic CH group, aromatic CO group, hydroxyl OH and Aldehyde HCO group. The Rock-Eval pyrolysis studies have been carried out to know the coalification profile of the deposits and hydrocarbon source rock potential. The varying behaviour between brown coal lithotype are primarily reflected by changes in oxygen index values, whereas hydrogen index values demonstrate a more pronounced correlation with coal type rather than the level of maturation. The results show the average total organic carbon (TOC) 47.29 %, S1 peak 2.18 mg HC/g, S2 peak 88.70 mg HC/g, S3 peak 19.22 % mg CO2/g, Tmax 410.53 °C, hydrogen index 219.2 mg HC/g TOC and oxygen index 46.33 mg CO2/g TOC. According to petrographic investigations, the huminite macerals dominate followed by liptinite and inertinite maceral groups in mineral matter-free basis. In all the three different lignite mines, the huminite group dominates with preserved sub-maceral ulminite indicating less transformation of structured plant matter. Reconstruction of depositional environment and paleo-climatic condition of the paleo-mires has been attempted by using organic petrographic indices. The high gelification index (GI) and low tissue preservation index (TPI) values suggest a prolonged wet environment during the decomposition of organic material, accompanied by a gradual subsidence process. The ground water influence index (GWI) and vegetation index (VI) denote ombrotrophic to mesotrophic hydrological conditions of basin at the time of deposition.

Studi Material Organik batuan Induk Sebagai Sumber Batuan Hidrokarbon Lapangan 'X' Berdasarkan Data Geokimia

The need for oil and gas has led to increased exploration to produce hydrocarbons in various basins and discover new reserves. This was also done in the Kutai basin on the eastern island of Kalimantan using a quantitative correlation between geophysical logs and rock core data and qualitative analysis by analyzing geochemical data derived from the host rock. To determine the characteristics of the hydrocarbon source rock in the three test wells, three types were analyzed, namely organic material richness, organic material type, and maturity level. For the Maau-1, Wahau-1, and Tengkawang-1 test wells, the organic material content has an excellent type to become source rock. The three wells are of medium-special hydrocarbon potential in organic material, making them very likely to produce oil and gas. As for the nature of the material content, the three wells have a mature level of the source rock, making them very potential as the very good source rock. The need for oil and gas has led to increased exploration to produce hydrocarbons in various basins and discover new reserves. This was also done in the Kutai basin on the eastern island of Kalimantan using a quantitative correlation between geophysical logs and rock core data and qualitative analysis by analyzing geochemical data derived from the host rock. To determine the characteristics of the hydrocarbon source rock in the three test wells, three types were analyzed, namely organic material richness, organic material type, and maturity level. For the Maau-1, Wahau-1, and Tengkawang-1 test wells, the organic material content has an excellent type to become source rock. In terms of organic matter, all three wells have medium-special hydrocarbon potential and, therefore, high potential to produce oil and gas. As for the nature of the material content, the three wells have a mature level of the source rock, making them very potential as the very good source rock.

Cross-basin Mo and U analysis of the Upper Mississippian Bowland Shale, UK

Abstract The Bowland sub-basin is a target for hydrocarbon exploration, but to a large extent it remains unexplored. To determine the economic potential of the Bowland sub-basin, it is important to identify the oceanographic processes involved in the deposition of the Bowland Shale Formation in the Late Mississippian ( c. 330 Ma). Palaeoceanographic processes are known to be a major control on the development of hydrocarbon source rocks. This study investigates core (Preese Hall-1 and Becconsall-1Z) materials from the Upper Bowland Shale, and makes a comparison with previously published data (outcrop Hind Clough), all from the Bowland sub-basin, Lancashire, UK. The sedimentology and geochemistry of this formation were determined via a multi-technique approach including X-ray fluorescence, sedimentology, gamma-ray spectra, X-ray diffraction and Rock-Eval pyrolysis. Key trace metal abundances and enrichment factors were used to assess sediment provenance and to determine the bottom-water redox conditions during the deposition of the Upper Bowland Shale. Our results support interpretations of contemporaneous anoxia developing in bottom waters in at least three sites in the Bowland sub-basin. In a comparison with the Fort Worth Basin (Barnett Shale, USA), the Bowland sub-basin was apparently less restricted and deposited under a much higher mean sediment accumulation rate. Knowledge from this study will improve future resource estimates of the Bowland Shale Formation, and challenge the early assumptions that the Barnett Shale is an analogue of the Bowland Shale.

Periods and Processes of Oil and Gas Accumulation in the HZ-A Structure Double Paleogene Field, Pearl River Mouth Basin

The source of oil and gas and the stages of oil and gas accumulation in the “double-Paleo” field of the HZ-A structure in the Pearl River Mouth Basin are analyzed, and the spatiotemporal coupling relationship of the key conditions of oil and gas accumulation are discussed to reconstruct the process of oil and gas accumulation. Based on previous research results, which are based the characteristics of biomarker compounds, the oil and gas in the HZ-A structure double Paleogene field came from the Paleogene Wenchang Formation hydrocarbon source rocks in the HZ26 sub-sag. By means of the casting thin section identification and inclusion homogenization temperature measurement, this paper reveals the three major hydrocarbon accumulation periods and corresponding fluid charging types in the “double-Paleo” field of the HZ-A structure in the Pearl River Mouth Basin. The results show that 13.8–10 Ma is the charging period of low mature crude oil, 10–5.3 Ma is the charging period of mature crude oil, and from 5.3 Ma is the natural gas charging period. Based on actual geological, drilling, logging, and seismic data, the key conditions for hydrocarbon accumulation in the HZ-A structure “double-Paleo” field are sorted out; that is, the source conditions are characterized by high-quality lacustrine source rocks generating early oil and late gas and a near-source continuous hydrocarbon supply. The reservoir conditions are characterized by weathering and superposition of a fracture zone that transforms into a reservoir, and a large-scale sandstone rock mass that transforms into a reservoir. The caprock conditions are characterized by the stacking of several thin mudstones that form a seal and the combination of multiple lithologies that block hydrocarbon migration. The trap conditions are characterized by multistage uplift structure traps and fracture-lithology combination control traps. The transport conditions are characterized by multi-stage cross-bed transport of source-connected faults and lateral differential transport of shallow sand in deep fractures. Finally, oil and gas accumulation models of the HZ-A structure double Paleogene field were established, and the accumulation process was reconstructed. The overall process involved three stages, with the first stage being the localized oil-displacing-water mode, the second being the large-scale oil-displacing-water mode, and the third being the late progressive gas-displacing-oil mode.

Effects of Emeishan Large Igneous Province on organic matter accumulation, Sichuan Basin, China

Volcanic activity is often associated with the formation of organic-rich sedimentary deposits. However, the relationships between volcanism and depositional events of hydrocarbon source rock during geological history remain unclear. To fill the knowledge gap, we investigated the relationships based on a case study of the Emeishan Large Igneous Province (ELIP) during the late Guadalupian. We carried out a detailed petrological and geochemical investigation of the upper Maokou Formation (i.e., the Mao III Member) in the Shangsi section, Sichuan Province, China. The Mao III Member has a relatively high abundance of organic matter (OM), good OM type, and appropriate thermal maturity that is conducive to hydrocarbon generation. Paleoenvironmental reconstructions based on multiple geochemical proxies indicate that the Mao III Member records relatively high primary productivity, enhanced anoxic conditions, intense upwelling but weak water mass restriction, decreased detrital input and sedimentation rate, and fluctuations in volcanic and hydrothermal activity. The marked positive correlations between primary productivity, redox conditions, and OM abundance suggest that the former two factors controlled OM accumulation. In addition, the detrital input has a slight dilution effect on the OM abundance. No direct relationship was observed between hydrothermal activity and OM abundance. In contrast, volcanic activity related to ELIP had a major role in enhancing the primary productivity and more reducing conditions, which is confirmed by the marked correlations between Hg/TOC, Cuauth, and Vauth values. This suggests that ELIP volcanism had a significant positive effect on OM enrichment in the Mao III Member, which may be a common feature associated with large volcanic events at other times in Earth's history.

Environmental controls on organic matter enrichment of the lower Cambrian source rocks in the Tarim Basin, Northwest China

In the Tarim Basin, the largest petroliferous basin in China, a set of organic-rich deposition hosted in the lower Cambrian Yuertusi Formation is considered to be the main hydrocarbon source rocks. However, the limited and scattered distribution of the lower Cambrian constrains present studies mostly on some certain sections where samples are accessible, inhibiting a systematic understanding of characteristics of these source rocks and controls on organic matter enrichment. Here, we conduct a systematic study on a drillcore in northwestern margin of the Tarim Basin (Taxibei), integrated with previously published data from other available sections. These data show the Yuertusi Formation was mainly composed of mudstone/shale, carbonate and siliceous rocks, and distributed dominantly in the Taxibei, northern (Tabei) and eastern-northeastern areas of the Tarim Basin (Tadong-Tadongbei) with an increased thickness (mean 30 m to mean 60 m) towards the Tadong-Tadongbei areas. High total organic carbon (TOC) contents (up to 30%) were found in the mudstone/shale dominated intervals in both the Taxibei and Tabei areas, characterized by I-II kerogen and highly to over-matured thermal maturity. Paleo-redox reconstruction based on high V/(V + Ni) ratios (>0.6) and FeHR/FeT ratios (>0.38) suggests anoxic watermass conditions occurred during the deposition of the organic-rich intervals along with moderate sedimentation rate, providing consistently good preservation for organic matter accumulation. Based on a combined analysis, we infer primary productivity in surface waters exerted a key control on TOC contents of the organic-rich intervals, which was driven by nutrient supplies from hydrothermal activities with partial upwelling effects in the Taxibei area, and from upwelling waters in the Tabei area.

Links between marine incursions, lacustrine anoxia and organic matter enrichment in the Upper Cretaceous Qingshankou Formation, Songliao Basin, China

There is a general relationship between the formation of terrestrial hydrocarbon source rocks and marine incursions during the Mesozoic–Cenozoic in China. To better understand this scientific issue, this study focused on the little-studied Upper Cretaceous Qingshankou Formation (early Late Cretaceous) in the Songliao Basin, China, which was investigated using organic petrological and organic and inorganic geochemical methods. The mudstone and shale in the Qingshankou Formation were deposited in an anoxic, reducing, slightly brackish water environment and contain benthic macroalgae, which is a typical marine fossil in Qingshankou Member I. The δ34S values are generally similar to those of Late Cretaceous marine sulfate, and the total N contents and isotopic compositions (δ15N) are both high, suggesting that the Qingshankou Formation was affected by marine incursions that triggered lake anoxia. The total organic carbon (TOC) contents of the mudstones and shales in the Qingshankou Formation are 0.21–3.86 wt%, with an average value of 1.91 wt%, which meet the criterion of a very good–excellent source rock. The organic matter varies from type I to III kerogen but is mainly types I and II, which generate oil. The hydrocarbon-generating bio-precursors are mainly planktonic and benthic algae. The hydrocarbon generation potential of the Qingshankou Member I is high, mainly due to the high productivity during its deposition. Increased productivity caused by marine intrusions, water stratification caused by high salinity, and reducing bottom-water environment provided favorable conditions for organic matter enrichment. The marine incursions during deposition of the Qingshankou Formation (especially Member I) improved the quality of the source rocks by enhancing the primary productivity, which might be a common feature of terrestrial source rocks affected by such incursions in general.

Sedimentology and geochemistry of Eocene source rocks in the east China sea: Controls on hydrocarbon generation and source rock preservation

As an important source rock for oil and gas generation, coal measure source rock has attracted much attention due to its high hydrocarbon generation potential. Therefore, we conducted a comprehensive evaluation of the source rocks based on organic geochemical and petrological data to clarify the sedimentary, geochemical, and hydrocarbon generation characteristics of the coal measure source rocks of the Pinghu Formation in the Xihu Depression. The source rocks were deposited in a shallow freshwater sedimentary environment with weak reduction-oxidation conditions. The organic matter is mainly derived from terrestrial higher plants, with less contribution from phytoplankton and bacteria. Compared to carbonaceous mudstone and mudstone, coal was deposited in an environment with stronger oxidation conditions, and stronger bacterial transformation. Within the study area, sag A receives relatively high contributions from phytoplankton and high liptinite content, whereas sag C receives the largest contribution from terrestrial higher plants. Sag A is dominated by source rocks with a relatively high oil generation potential and oil reservoirs, whereas other regions have limited oil generation capacity and are characterized by gas reservoirs and condensate gas reservoirs. The E2p2 member, with more terrestrial organic matter input, has a higher TOC content and hydrocarbon generation potential than the E2p1 and E2p3 members. Thick organic-rich mudstone is developed in the E2p2 member due to a high accommodation space, abundant terrestrial organic matter, corresponding to a high relative base-level. The vast intertidal setting is conducive to the development of peatlands, developing widely distributed carbonaceous mudstone and coal. The study interval is characterized by a coal measure source rock development model of ‘strong supply - rapid burial - facies-controlled’ in the Xihu Depression.

Deep learning integrated approach for hydrocarbon source rock evaluation and geochemical indicators prediction in the Jurassic - Paleogene of the Mandawa basin, SE Tanzania

The world's energy demands are growing at an unprecedented rate, and the exploration of new hydrocarbon sources is more important than ever. Therefore, the objective of this study was first to quantitatively analyze hydrocarbon source rock potentiality of the Triassic-Jurassic of Mandawa Basin based on the generalized group method of data handling neural network (g-GMDH), Machine learning, and Geochemical using well logs data. Then a novel g-GMDH was presented to predict a continuous geochemical log profile of TOC, Tmax, S1, and S2. It was observed that the basin's hydrocarbon source rocks are classified as fair to very good source rocks with TOC contents ranging from 0.5 to 8.7 wt%. The source rocks contain mixed kerogen type II and III, which are oil and gas-prone, ranging from immature to mature source rocks. The results of the predictive models indicated that the g-GMDH model trained better whilst generalizing well throughout the testing data than both GPR and SVM models. Specifically, the g-GMDH when tested on unseen data had the least value of MSE = 0.18, 2.35, 0.08, and 61.74 for TOC, Tmax, S1, and S2 respectively, and MAE = 0.45, 1.37, 0.17 and 11.55 for TOC, Tmax, S1 and S2 respectively. The g-GMDH model was further applied to assess the source rock and predict the geochemical information in the East Lika well, which lacks core data. The proposed model can offer rapid and real-time values of geochemical indicators and are independent of laboratory-dependent parameters therefore, can be adopted as an improved technique for evaluating source rocks in frontier basins.

Physical Properties of Hydrocarbon Source Reservoir in the Lucaogou Formation in Junggar Basin (China) and Its Influence on Adsorption Ability and Surface Free Energy

A physical property of a shale gas reservoir affects shale gas content, then restricts the shale gas resource potential. In this paper, lithofacies and spatial distribution of the southern margin of the Junggar Basin in Xinjiang Province are identified and occurrence strata, gas content, and reservoir properties of shale gas are studied. Based on adsorption potential theory, adsorption and surface free energy of all the sample is discussed. The conclusions are as follows. (1) All the shale samples can be divided into five lithological phases. For example, black oil shale/shale (lithology) phase and gray-black-gray/dolomite mudstone (lithology) phase are the most developed; compared with the middle and lower sections, the vertical development continuity of the upper hydrocarbon source rock is better. Lithology of this section is mainly composed of shale mixed with marlstone and dolomite interlayer. From the horizontal view of this section, the overall trend is gradually thickening from west to east and from north to south. (2) Semi-deep lake-phase is the most developed, indicating a decreasing trend of thickness from sedimentary center to surrounding strata. (3) Sedimentary period of Lucaogou Formation is a deep water area of the lake basin; then, the TOC content is affected by the sedimentary environment. As sedimentary water depth increases, TOC content will increase, which results in the highest TOC content in the area. A specific surface area is roughly positively correlated with porosity, clay mineral content, and percentage of illite/montmorillonite interlayer ratio and negatively correlated with TOC content. (4) During the adsorption process, adsorption potential decreases with an increase in equilibrium pressure, and adsorption space increases with an increase in equilibrium pressure. Maximum adsorption space of all the sample were 0.20~0.25 cm3·g−1; then, its value is larger than the maximum adsorption space of other coal samples (0.025~0.20 cm3·g−1). In the same adsorption space, the corresponding adsorption potential of the coal sample is much larger than that of other samples. The reason is that the porosity permeability of this sample is relatively larger, leading to its better physical properties.

Organic facies and hydrocarbon source rock potentiality of the Neogene succession in the Central South Mediterranean, offshore Nile Delta Basin, Egypt

Neogene succession in the offshore Nile Delta region is essential to the hydrocarbon petroleum system. Up to date, little is known about the nature and distribution of organic matter and its potential to generate hydrocarbon. This potential is tested through extensive palynofacies and organic geochemical analyses in a new approach in this region. Based on the palynofacies analysis, the samples from NDOB-1 and Baltim-1wells are discriminated into four types using the statistical application of cluster and principal component analyses. These four types are distal-High Oxic type A, proximal-suboxic type B, proximal-dysoxic type C, and distal-oxic type D. In addition, the analysis leads to identifying the proximal-distal and oxygen depletion trends based on the values of the principal component analysis (axis 1). This palynofacies analysis is used as an environmental framework for hydrocarbon source rock evaluation. This evaluation is integrated with the organic geochemical parameters by pyrolysis (Rock-Eval and gas chromatography) and spectroscopic (Fourier Transform Infrared) methods. This study reveals that the dominant kerogen types are IV (inert) and III (gas-prone) which are remarked by the opaque and brown translucent phytoclasts palynofacies types A and D, respectively. Kerogen type II is presented in a minor abundance in palynofacies types B and C that are distinguished with AOM. However, kerogen type II organic matter is much diluted with kerogen type IV and III, leading to poor to fair organic geochemical quality (S2 and hydrogen index). Both wells' maturity levels are detected within the Kafr El Shiekh Formation. Nevertheless, the poor hydrocarbon source rock quality becomes important if considered with the volume and thickness of the Neogene sediment, as indicated by the source potential index that has a cumulative value of 2.5 t HC/m2 in NDOB-1 well and 2.8 t HC/m2in Baltim-1 well. These values are comparable to some of the prolific hydrocarbon fields in other places.

Analysis of the Spatial Distribution Characteristics of Crude Oils with Different Freezing Points and the Genetic Mechanism of High-Freezing-Point Crude Oils in the Dongying Sag.

The freezing point of crude oils is an important factor affecting the process of exploration, development, and transportation of crude oils. In the Dongying Sag, the freezing point of crude oils varies greatly in space, and high-freezing-point crude oils have been found in many structural belts. The freezing point of crude oils in the Dongying Sag is generally high, ranging from -40 to 80 °C. The distribution of high-freezing-point crude oils in the Dongying Sag is scattered, and they have been found at different depths, layers, and structural belts, with relatively more occurrences in specific areas. Based on the relationship between the wax content and the resin + asphaltene content, the high-freezing-point crude oils in the Dongying Sag can be classified into three types (type A, type B, and type C). Type A, type B, and type C high-freezing-point crude oils are mainly found in the gentle slope zone, depression zone, and uplift zone, respectively. The contents of wax and resins + asphaltenes in crude oils are the key factors controlling the freezing point of crude oils in the Dongying Sag. Oil source correlation using biomarkers and n-alkane carbon isotopes demonstrates that different types of high-freezing-point crude oils are generated from different source rocks, indicating that the source of crude oils is not the only factor controlling the freezing point of crude oils. The hydrocarbon-generating parent material of hydrocarbon source rocks developed in different depositional environments of the Dongying Sag is generally characterized by the dominance of bacteria and algae and is supplemented by terrestrial higher plants. This lays the material foundation for the formation of waxes during the maturation of hydrocarbon source rocks. The change of temperature and pressure conditions during the process of oil expulsion from source rocks and migration in the carrier bed will lead to phase fractionation and composition changes of oils, thus forming type A freezing point crude oils in the slope zone and type B freezing point oils in the depression zone. The increase in resin and asphaltene content caused by biodegradation and water washing in shallower buried oil reservoirs is the reason for the formation of type C high-freezing-point crude oils. The research results indicate that the organic matter composition and hydrocarbon alteration during migration and accumulation jointly control the formation of high-freezing-point crude oils in lacustrine basins. The extensive input of terrestrial organic matter into the source rocks of the lacustrine basin laid the foundation for the formation of high-freezing-point crude oils, and the migration fractionation and biodegradation of the crude oils further promoted the formation of high-freezing-point crude oils.

Studies on the Source and Phase Characteristics of Oil and Gas: Evidence from Hydrocarbon Geochemistry in the Pingbei Area of Xihu Sag, the East China Sea Shelf Basin, China

The Pingbei area is the main accumulation area of oil and gas in the Xihu Sag. The phase characteristics of oil and gas in this area are complex, and the understanding of their genesis is still unclear. In this paper, based upon discussions of crude oil and natural gas geochemical data, integrated with local geological features, we discuss the sources, migration, and phase state characteristics of oil and gas in the Pingbei area of the Xihu Sag. The study results show that the crude oil and natural gas in the Pingbei area are coal-derived and the oil and gas produced by the humic organic matter during the mature stage. The oil and gas source correlation showed that crude oil and natural gas have good affinity with the Eocene Pinghu Formation (PH) coal-bearing source rocks. Crude oil has the characteristics of near-source accumulation and short-distance migration while natural gas is supplied from a dual source: the coal-derived hydrocarbon rocks of PH in the deep part of the study area, supplemented by the coal-derived hydrocarbon rocks of PH on the bottom of the slope, and adjacent hydrocarbon-bearing sub sag. The distribution characteristics and geochemical migration indices of hydrocarbon show that the oil generated from the hydrocarbon source rocks of PH in the deep Pingbei area mainly migrates vertically along the fault connecting the reservoir and the source rocks to the trap, where it accumulates, while the natural gas exhibits deep and large faults that mainly migrate vertically, supplemented by its lateral migration along the composite transport system composed of faults and sandstone layers in the slope zone. The whole area presents the phase characteristics of “upper oil and lower gas, west oil and east gas”. The mechanisms of produced-exhausted and geochromatographic effects (PGE), as well as evaporative fractionation (EF) and phase-controlled migration fractionation (PMF), result in the obvious discrepancy of hydrocarbon’s properties on the vertical profiles.

Diagenesis of the Marinoan cap dolostone, Southern Amazon Craton: An unconventional petroleum system in the evolution of the Araras-Alto Paraguai Basin

The post-snowball Earth world favors the development of hydrocarbon source rock intimately linked to periods of post-glacial marine transgression generating important potential petroleum plays. In the Southern Amazon Craton, hydrocarbons occur in one of the most spectacular examples of post-Marinoan cap carbonate, related to the mid-Ediacaran to Early Cambrian (c. Post 635 Ma) interval associated with the early stabilization of the Gondwana Supercontinent. The Puga cap carbonate consists of the basal portion of the Araras Group exposed in the Araras Alto-Paraguai Basin inserted as a reservoir in an unconventional petroleum system. The cap dolostone overlies diamictites and is overlaid by bituminous limestone and shales (source-rock), and dolostone in the top of a 700 m-thick depositional sequence. The cap dolostone has a diachronic relation with the limestone beds typifying as a secondary reservoir characterized by bitumen-filled fenestral and interpeloidal porosity. The upper dolostone has a closed framework and acts as sealing rocks. This study aims to establish paragenesis sequence and decipher its control on the quality of the cap dolostone as a microbialites-dominated reservoir. Drill core and outcrop samples were analyzed using microfacies, scanning electron microscopy, and cathodoluminescence to unravel the diagenetic history. Aftermath, the Marinoan events favored dolomuds precipitation in the shallow platforms, preserving primary porosity and permeability reduced by early gypsum cementation during oversaturation events. Other destructive processes, such as mechanical and chemical compaction (e.g., stylolites) and authigenesis of pyrite and low-Mg ferroan calcite cementation, occurred during burial and mesodiagenesis. The low permeability restricts hydrocarbon migration concentrated in the upper cap dolostone, and the early cementation increases the potential for preserving these carbonate deposits. Hydrocarbon maturation was triggered during the burial and uplift of the Araras-Alto Paraguai basin. The cementation phases described here enhance our understanding of the mechanisms behind syndepositional diagenesis in microbially-induced reservoirs. This study uses proxies associated with diagenetic studies to quantify the quality of microbially induced dolostone reservoir linked to the evolution of the Neoproterozoic unconventional petroleum system. In addition, this conception will promote a guide for future exploration and understanding of petroleum plays and suggests a possible Precambrian source rocks component of traditional Phanerozoic Petroleum systems in the central part of Brazil.

Source Rock Evaluation of Hydrocarbons in Deep-Water Offshore Areas Based on a BP Neural Network

Due to the lack of drilling data and poor quality of seismic data in deep-water offshore areas, conventional methods cannot effectively predict the total organic carbon (TOC) content. In this paper, the BP neural network method is used to predict the TOC of the strata overlying the target layer, which adds to the TOC information in the study area. Then, the highest TOC value of the strata overlying the target layer is used to select the most sensitive seismic attributes. Finally, the sensitive seismic attributes are used to evaluate the source rocks with no or few wells. A set of TOC prediction technology flows is established for TOC combined with seismic attributes under the condition of no wells and few wells in deep-water areas. The application example shows the reliability of TOC prediction by this technical process, and the study has a certain reference significance for the evaluation of hydrocarbon source rocks in offshore deep water.