Free Hydrocarbons Research Articles

Differential enrichment of middle-low maturity lacustrine shale oil in the late Eocene Shahejie Formation, Bohai Bay Basin

The Tertiary lacustrine shales in China display middle-low maturity but have significant resources potential for shale oil compared to North American marine shales. The accumulation mechanism of hydrocarbons in shales of middle-low maturity is of importance for the evaluation of shale oil resources and exploration. This study employs a comprehensive range of geological and geochemical methods to analyze the aggregation characteristics of hydrocarbons in the middle-low maturity lacustrine shales of the late Eocene first member of the Shahejie Formation (EOS shales) in the Bohai Bay Basin. Based on this analysis, the study proposes an aggregation pattern for hydrocarbons specifically in middle-low maturity lacustrine shales. The EOS shales are dominated by felsic minerals followed by clay and carbonate, and enriched Type II1 and Type II2 organic matter with an average TOC content of 2.03%. The presence of halite exhibits a positive correlation with the organic matter content, suggesting its important role in the preservation and concentration of organic material. The content of ankerite is negatively correlated with ΔS1 and positively correlated with OSI, indicating that ankerite promotes hydrocarbon enrichment. The free hydrocarbon index（ΔS1）was used to evaluate the hydrocarbon migration in EOS shales, and show differential enrichment in vertical profile as verified by multiple indicators. The mineral, lithology and lithofacies affect the enrichment of hydrocarbons. In the differential enrichment model, the hydrocarbons of Group Ⅰ enriched from outside, and the hydrocarbons of Group II were self-generated, while the hydrocarbons of Group Ⅲ expelled outward. This study clarifies the differential enrichment characteristics of hydrocarbons in middle-low maturity lacustrine shales, and proposed the enrichment model, which provides powerful support for the in-depth exploration and effective development of lacustrine shale oil.

An integrated convolutional neural network prediction framework for in situ shale oil content based on conventional logging data

The quantification of total organic carbon (TOC) and the free hydrocarbon content (S 1 ) is crucial for evaluating the shale oil generation and bearing properties of source rocks. This study aimed to enhance the accuracy of TOC and S 1 quantification in shale oil evaluations. The scope encompassed the development of a novel deep learning framework to overcome the limitations of traditional physical and machine learning or deep learning methods. This paper proposes an integrated swarm optimization algorithm–convolutional neural network/machine learning framework. This framework uses a swarm optimization algorithm for the hyperparameter optimization of a convolutional neural network or machine learning framework, utilizing experimental data from core samples preserved in liquid nitrogen alongside well logging data. The application of the proposed framework to the H11 well in the Subei Basin, China, using 110 core samples, demonstrated a superior performance. The results validate the framework's effectiveness in predicting the TOC and S 1 contents at various depths. The proposed framework stands out for its convenient methodology, wide application range and high precision in prediction. These attributes contribute significantly to the field of petroleum engineering and development, offering a novel approach that promises to enhance both the efficiency and accuracy of well logging evaluation.

Influence of thermal intrusion on the Alum Shale from south central Sweden

This study investigates the geochemical and petrological characteristics of solid bitumen in the DBH15/73 core from the Furongian (upper Cambrian) and Miaolingian (middle Cambrian) Alum Shale in Billingen, south central Sweden. At Billingen a > 30 m thick Permian diabase (dolerite sill) intruded approximately 100 m above the Alum Shale that promoting the formation of solid bitumen in the uppermost half of the Alum Shale due to enhanced heat flow. The bitumen has been classified into bituminite/diagenetic solid bitumen (DSB), initial-oil solid bitumen (IOSB), and primary-oil solid bitumen (POSB) based on their genesis, morphology and random solid bitumen reflectance (BRo). The Miaolingian shale, constituting the lower part of the Alum Shale, is immature and contains solely bituminite and DSB, with measured BRo ranging from 0.40% to 0.48%. In contrast, the Furongian shale exhibits enrichment in IOSB and POSB and range from marginally mature to peak oil generation with towards the top of the section. Characteristics of uneven heating is seen in the IOSB (BRo: 0.97–1.08%) including oxidation rims and abnormally high maturity surrounding fractures. The POSB (BRo: 0.63–2.01%) is present not only in the Alum Shale but also in the overlying Ordovician Latorp limestone and the underlying Kakeled Limestone Bed, and shows flow structures which is further evidence for migration. The abundance of POSB and IOSB is determined through maceral point counting, revealing POSB as the dominant bitumen type (1.54–7.13 vol%), while IOSB constitutes the minority (0.05–0.31 vol%) within the Furongian shale. This distribution suggests rapid thermal evolution of organic matter within the oil generation window. Additionally, a reduction in free hydrocarbons (Rock-Eval S1), potential hydrocarbons (Rock-Eval S2), and unexpectedly low Tmax was observed in the Furongian shale. Results indicate that hydrocarbon generation resulting from thermal intrusion contributes to the relatively low S2. Migration of POSB and generated oil to adjacent layers leads to the loss of S1, while the reduced Tmax may be attributed to high uranium content which weakens carbon chain bond energy. These anomalies result in an underestimation when evaluating thermal maturity and kerogen type conversion based on Rock Eval data alone.

Hydrocarbon microseepages in the kerkennah islands, Eastern Tunisia: Integrated surface geochemical and geoelectrical prospecting approaches

Oil exploration is usually carried out using conventional techniques such as seismic reflection and exploratory drilling. However, these techniques are very costly with a high risk of dry holes or failure to find commercial quantities of hydrocarbons. Here we aim to evaluate surface geochemical prospection (SPG) methods which serve as preliminary step to derisk an area by exploring hydrocarbon micro-seeps. This approach helps to identify potential areas of interest when you have limited amount of money to explore a given area. This paper reports on surface gas micro-seepages in the Kerkennah archipelago, part of the Tunisian Pelagian Platform. 33 gas and soil samples were collected on a 1 × 1 km grid over Chergui Island. Both free gas and adsorbed soil gas techniques were used. Free hydrocarbon gas concentrations ranged from 0 to 21 ppm. Adsorbed gases showed concentrations up to 11 ppm. The presence of all light hydrocarbon gas components from methane to pentane, the values of the gas ratios C1/C2, C1/ΣC2+, (C3/C1) x 1000 and C1/(C2 + C3), and the Pixler and triangular diagrams together indicate that these gases are of thermogenic origin and have migrated from subsurface accumulations. Anomalous concentrations of hydrocarbon gases occurred in the middle and west of the study area. Both free and adsorbed gas anomalies have the same planar shape and form linear anomalies with a NW-SE trend. This orientation corresponds to that of the major fault system affecting the Kerkennah archipelago. Subsequent independent VES surveys and re-interpreted seismic lines confirmed the presence of a surface fault as suggested by the surface gas anomalies. In conclusion, our study has confirmed the presence of thermogenic hydrocarbon gas microseepage to the surface. The gases are interpreted to have migrated to the surface along faults. SPG methods were thus able to identify active hydrocarbon migration and can be considered as a useful low-cost approach to hydrocarbon exploration.

Multiple isotopes (C-S-N-H) and bound biomarkers in asphaltenes: New constraints on the classification and genesis of reservoir bitumens from the northwestern Sichuan Basin, South China

Reservoir bitumens in the northwestern Sichuan basin are significant for elucidating the sources and charging history of oil and gas, given their widespread occurrence in multiple strata in the area and abundant biomarkers. The debate regarding the origin and genesis of these bitumens has persisted for a long time, due to severe biodegradation and the development of multiple sets of high maturity source rocks with few biomarkers for oil-source correlation. To resolve these questions, asphaltenes, which are more resistant to biodegradation than free hydrocarbons, were systematically analyzed with the bulk multi-isotopes (C-S-N-H), bound molecules and the carbon isotopic compositions of bound individual n-alkanes. These characteristics were then compared to those of bulk bitumen and free hydrocarbons, leading to three main conclusions. In most samples, relatively abundant 25-norhopanes and 17-nortricylic terpanes were identified along with n-alkanes in free hydrocarbons, suggesting at least two oil charging events. In the samples having free n-alkanes, the carbon isotopic compositions of asphaltene-bound n-alkanes closely resemble those of corresponding free n-alkanes. Moreover, the bulk C-S-N isotopic compositions of asphaltene also approach those of corresponding bulk bitumen. These results suggest that the source of the oil charges occuring at different times are mostly the same for an individual sample, though different bitumen samples may have distinct sources. Free hydrocarbons, including n-alkanes and biomarkers, may have been produced by the secondary cracking of asphaltenes. Second, the integration of bulk C-S-N isotopic compositions of the asphaltenes and bitumens has enabled the studied samples to be classified into four groups. Source facies is the primary control of the distinct isotopic compositions with other factors like biodegradation, thermal maturity and migration having only minor influence. In combination with biomarkers, the organic matter and sedimentary environment of source rocks could be characterized for each group. A careful comparison of the bulk C-S-N isotopic compositions of asphaltenes and bitumens with those previously reported for source rocks (organic C and S and bulk N isotopes) suggests the main source rocks in the Upper Ediacarian-Lower Cambrian Formations, supporting the conclusions of previous studies. Furthermore, those source rocks in much younger formations, such as the Middle Permian as well as the Middle Devonian Formations, may also have contributed significantly to the widespread reservoir bitumens in the region. These findings highlight the usefulness of bulk C-S-N isotopic composition of asphaltenes for distinguishing oils with complex genesis and large gas exploration potential of the Upper Paleozoic source rocks in the region.

Shale oil development techniques and application based on ternary-element storage and flow concept in Jiyang Depression, Bohai Bay Basin, East China

The ternary-element storage and flow concept for shale oil reservoirs in Jiyang Depression of Bohai Bay Basin, East China, was proposed based on the data of more than 10 000 m cores and the production of more than 60 horizontal wells. The synergy of three elements (storage, fracture and pressure) contributes to the enrichment and high production of shale oil in Jiyang Depression. The storage element controls the enrichment of shale oil; specifically, the presence of inorganic pores and fractures, as well as laminae of lime-mud rocks, in the saline lake basin, is conducive to the storage of shale oil, and the high hydrocarbon generating capacity and free hydrocarbon content are the material basis for high production. The fracture element controls the shale oil flow; specifically, natural fractures act as flow channels for shale oil to migrate and accumulate, and induced fractures communicate natural fractures to form complex fracture network, which is fundamental to high production. The pressure element controls the high and stable production of shale oil; specifically, the high formation pressure provides the drive force for the migration and accumulation of hydrocarbons, and fracturing stimulation significantly increases the elastic energy of rock and fluid, improves the imbibition replacement of oil in the pores/fractures, and reduces the stress sensitivity, guaranteeing the stable production of shale oil for a long time. Based on the ternary-element storage and flow concept, a 3D development technology was formed, with the core techniques of 3D well pattern optimization, 3D balanced fracturing, and full-cycle optimization of adjustment and control. This technology effectively guides the production and provides a support to the large-scale beneficial development of shale oil in Jiyang Depression.

Outcrops as windows to petroleum systems: Insights from the southern Bida Basin, Nigeria

The study assessed petroleum systems in the southern Bida Basin, Nigeria, focusing on the Cretaceous sediments. Reservoirs comprise Lokoja and Patti Formation sandstones, while shales, claystone, and siltstone serve as source rocks and stratigraphic traps/seals. Detailed studies delineating the key elements of the petroleum systems in the basin have not been conducted due to a lack of subsurface data. The goal of the current study was to use field observations, Scanning Electron Microscopy (SEM), X-ray diffraction (XRD), and geochemical and geomechanical data to evaluate key components of petroleum systems in the southern Bida Basin. The results presented in this investigation are intended to attain specific objectives, especially those lacking in the basin's study sections. Petrophysical analysis revealed that the Lokoja Sandstone has porosity of 37%–39.5% and moderate permeability of 23.22–42.29 mD. The Patti Formation sandstone reservoirs exhibited high porosity (38%–42%) and moderate to good permeability (31.54–66.48 mD), suggesting good potential reservoirs. SEM results revealed intragranular pores and micro-fractures in the Patti Shale, whereas the sandstone reservoirs in the Lokoja and Patti formations displayed fractures, facilitating hydrocarbon migration. Quartz was the dominant mineral in the sandstone units of both formations. XRD analysis revealed that brittle and clay minerals influenced the microstructure of Patti Shale. Geochemical analysis indicated promising petroleum potential in the Patti Shale, with a total organic carbon (TOC) content of 1.87 wt%, free hydrocarbon from kerogen (S1) of 0.41 mg/g, hydrogen index (HI) of 0.75 mg HC/g TOC, and production index (PI) of 0.17. The Patti and Lokoja formations' shale, claystone, and siltstone exhibited sealing potential, with a plasticity index of 24–35 and coefficient permeability of 2.8 × 10−4- 3.6 × 10−4 cm/s. Field studies, XRD, geochemical data, and geomechanical index values have confirmed the key components of the petroleum system, which in turn facilitate hydrocarbon generation, migration, accumulation, and entrapment in the basin.

ГИДРОТЕРМАЛЬНАЯ КОНВЕРСИЯ ОРГАНИЧЕСКОГО ВЕЩЕСТВА НИЗКОПРОНИЦАЕМОЙ ДОМАНИКОВОЙ СЛАНЦЕВОЙ ПОРОДЫ В ГАЗООБРАЗНЫЕ И ЖИДКИЕ УГЛЕВОДОРОДЫ В СРЕДЕ УГЛЕКИСЛОГО ГАЗА

A study was conducted to determine whether temperature influences the nature of organic matter transformation in low-permeable rock of the Mendym deposits Upper Devonian of the Tavel oil field (Tatarstan). An experiment was conducted at 250°C, 300°C, and 350°C in a carbon dioxide environment with a 1:1 water to rock ratio and an exposure time of 24 hours in a carbon dioxide environment. The degree of kerogen conversion in the rock was determined, changes in the composition of the formed gases, group and hydrocarbon composition were assessed extracts (composed of saturated and aromatic hydrocarbons) from the rock before and after hydrothermal experiments. It was established that under these experimental conditions at a temperature of 250°C, a decrease in the content of saturated hydrocarbons and an increase in asphaltenes is observed in the extract composition, which indicates the process of desorption of asphaltenes from the kerogen surface and extraction of free hydrocarbons from the rock. At a temperature of 300°C, the yield of the extract increases slightly, however, as a result of the destruction of kerogen and high-molecular components (mainly resins), new hydrocarbons are formed, the content of saturated hydrocarbons increases from 14.53 to 27.34% compared to the original extract. The greatest changes in the composition of gaseous products and extract occur at 350°C, which is reflected in the almost complete extraction of hydrocarbons from the rock, the greatest increase in the yield of hydrocarbon and inorganic gases, and an increase in the content of light hydrocarbons in the composition of the extracts obtained. The content of saturated hydrocarbons increases to 35.29%, aromatic hydrocarbons from 23.11 to 31.11%, while the asphaltenes content decreases by more than 2.5 times. According to the molecular weight distribution data of aromatic hydrocarbons, it has been established that the transformation of organic matter at 350°C is most accompanied by the separation of di-, tricyclic and heterocyclic sulfur-containing aromatic fragments from polycondensed structures.

Petroleum Retention, Intraformational Migration and Segmented Accumulation within the Organic‐rich Shale in the Cretaceous Qingshankou Formation of the Gulong Sag, Songliao Basin, Northeast China

AbstractIn this study, organic geochemical and petrological analyses were conducted on 111 shale samples from a well to understand the retention, intraformational migration and segmented accumulation (shale oil enrichment in different intervals is unconnected) features of shale oil within the organic‐rich shale in the Qingshankou Formation of the Gulong Sag. Our study shows that retained petroleum characteristics in the investigated succession are mainly influenced by three factors: organic richness, intraformational migration and segmented accumulation. Organic matter richness primarily controls the amount of retained petroleum, especially the ‘live’ component indicated by the S2 value rather than the total organic carbon (TOC) figure alone. The negative expulsion efficiencies determined by mass‐balance calculations of hydrocarbons reveal that petroleum from adjacent organic‐rich intervals migrates into the interval of about 2386–2408 m, which is characterized by high free hydrocarbon (S1), OSI and saturated hydrocarbons content, along with a greater difference in δ13C values between polar compounds (including resins and asphaltenes) and saturated hydrocarbons. The depth‐dependent heterogeneity of carbon isotope ratios (δ13C) of mud methane gas, δ13C of extracts gross composition (SARA), δ13C of kerogen and SARA content of extracts suggest that the studied succession can be subdivided into four intervals. The shale oil sealing enrichment character in each interval is further corroborated by the distinct δ13C values of mud methane gas in different intervals. Due to the migration of petroleum into the 2386–2408 m interval, the S1, OSI and saturated hydrocarbons content of the interval show higher relative values. The maturity of organic matter in the 2471–2500 m interval is at the highest with the smaller size molecular components of the retained petroleum. Thus, favorable ‘sweet spots’ may be found in the 2386–2408 m interval and the 2471–2500 m interval, according to the experiment results in this study.

Phase behavior and GOR evolution using a natural maturity series of lacustrine oil-prone shale: Implications from compositional modelling

For the exploration of shale oil, there is still an urgent need to relate hydrocarbon generation reactions and changing phase behavior to exact levels of thermal maturity. Six organic-rich shale samples from the Cretaceous Qingshankou Formation, Songliao Basin spanning the maturity range with vitrinite reflectance (Ro) 0.58%–1.16% were studied for petroleum generation characteristics using the PhaseKinetics, PhaseSnapshot, and GORFit approaches. All samples show very good petroleum potential and contain Type I kerogen with total organic carbon contents ranging between 1.5% and 5%. A full spectrum of light to heavy hydrocarbons, consistent with live oils, occurs in thermal extracts of all samples. Gas chromatography fingerprints of samples with Ro > 0.7% closely resemble waxy oils derived from lacustrine organic matter (OM); fingerprints of lower maturity samples are not yet as wax rich. The inferred petroleum type organofacies of all samples is paraffinic high wax with low organic sulfur levels. Hydrocarbon generation from the least mature sample is characterized by one dominant activation energy at 55 kcal/mol, accounting for 87% of the total bulk reaction. Assuming a simplified geological scenario, i.e., a 3 K/My linear heating rate, primary petroleum is generated (transformation ratio, i.e., TR: 10%–90%) over a narrow temperature interval of only 23 °C. Onset (10% TR), maximum (Tpeak), and completion (90% TR) temperatures and Ro values are 141 °C at Ro 0.85%, 155 °C at Ro 1.08%, and 164 °C at Ro 1.2%, respectively. Primary gas generation (148–172 °C) occurs 10 °C later (300 m deeper) than the generation of C6+ compounds (138–161 °C). Secondary gas formation from oil cracking begins at 182 °C, maximizes at 197 °C, and is completed well before 225 °C (beginning of late gas generation from the secondary cracking of thermally matured, macromolecular organic matter) at 206 °C. Thus, primary and secondary oil cracking processes do not overlap under geological conditions. In line with a paraffinic high-wax oil petroleum type organofacies, cumulative fluids generated from the least mature sample fall within the black oil class over most of the primary kerogen conversion range up to 90% TR as indicated by low saturation pressures (Psat) and gas-oil-ratios generally below 160 Sm3/Sm3. Maturation results in relatively heavy fluids with Psat values in the range 40–70 bar when the free hydrocarbons, i.e., already present prior to pyrolysis, are included, and in lighter fluids with Psat values in the range 70–90 bar, when the free, mostly waxy hydrocarbons, are excluded. Systematics of physical properties and fluid compositions evolution reproduce the general behavior of naturally occurring petroleum sourced from lacustrine OM very well and fit physical properties and compositions of produced shale oils in the Songliao Basin at comparable maturity levels.

Regional mudstone compaction trends in the Vienna Basin: top seal assessment and implications for uplift history

Seal quality assessment is not only essential in petroleum systems studies but also in the context of other geo energy applications such as underground hydrogen storage. Capillary breakthrough pressure controls top seal capacity in the absence of faults or other discontinuities. In basins that lack measured capillary pressure data (e.g., from drill cores), regional compaction-porosity trends can be used as a first prediction tool to estimate the capillary properties of mudstones. Mathematical compaction models exist but need to be calibrated for each basin. This study aims to establish a compaction trend based on theoretical models, then compare it with theoretical maximum hydrocarbon column heights inferred from true measured capillary pressure curves. Middle to upper Miocene mudstone core samples from the Vienna Basin, covering a broad depth interval from 700 to 3400 m, were investigated by X-ray diffractometry, with an Eltra C/S analyzer, and by Rock–Eval pyrolysis for bulk mineralogy, total organic carbon, and free hydrocarbon contents. Broad ion beam—scanning electron microscopy, mercury intrusion capillary porosimetry, and helium pycnometry were applied to obtain pore structural properties to compare the mathematical compaction models with actual porosity data from the Vienna Basin. Clear decreasing porosity depth trends imply that mechanical compaction was rather uniform in the central Vienna Basin. Comparing the Vienna Basin trend to global mudstone compaction trends, regional uplift causing erosion of up to ~ 500 m upper Miocene strata is inferred. A trend of increasing Rock–Eval parameters S1 and production index [PI = S1/(S1 + S2)] with decreasing capillary sealing capacity of the investigated mudstones possibly indicates vertical hydrocarbon migration through the low-permeable mudstone horizons. This observation must be considered in future top-seal studies for secondary storage applications in the Vienna Basin.

Product migration and regional reaction characteristics in the autothermic pyrolysis in-situ conversion process of low-permeability Huadian oil shale core

Product migration and regional reaction characteristics of low-permeability oil shale cores in the autothermic pyrolysis in-situ conversion have not been investigated. In this study, an in-situ autothermic pyrolysis simulation experiment was conducted using a pressed cylindrical Huadian oil shale core, and systematic geochemical analyses were performed at different regions of the core after the experiments. The results showed that a clear thin grey-white main channel was formed inside the low-permeability core from the gas injection end to the outlet end because of the uneven advancement of the autothermic reaction after the experiment. Moreover, the free hydrocarbon products mainly transported along the main channel towards the outlet end and formed a significant accumulation at the end of the core. In addition, according to the results of pyrolysis hydrocarbon and total organic carbon determination, the core was divided into four typical reaction zones: autothermic, cracking, preheating, and virgin, which were distributed sequentially outwards along both sides of the main channel. Finally, based on the above results and analysis, two construction strategies were suggested for the autothermic pyrolysis in-situ conversion process.

Shale oil resource evaluation with an improved understanding of free hydrocarbons: Insights from three-step hydrocarbon thermal desorption

The pyrolysis parameter S1, which indicates the amount of free hydrocarbons present in shale, is often underestimated due to hydrocarbon loss during sample handling and measurement processes. To remedy this issue, we strongly recommend an immediate three-step hydrocarbon thermal desorption (HTD) approach to be conducted on oil shale at the drilling site. This approach measures Sg, S0, and S1*, which refer to gaseous, light, and free hydrocarbons, respectively. The new shale oil content value, calculated from the total of these three parameters, is far more precise and reliable than traditional pyrolysis S1. Moreover, we thoroughly investigated the components and microscopic occurrence features of hydrocarbons thermally desorbed at three temperature stages using gas chromatography (GC) and X-ray microcomputed tomography (CT). For example, we selected Chang 73 mud shale. Our experimental results irrefutably indicate that the ultimate shale oil content of poor resource rocks is significantly impacted by evaporative loss, with this effect being greater when the total organic carbon (TOC) is lower. Additionally, C1-5 and C1-7 hydrocarbons constitute almost all of Sg and S0, respectively. Sg and S0 are predominantly composed of C1-3 gaseous hydrocarbons, with a maximum proportion of 42.93%. In contrast, S1* contains a substantial amount of C16-31 hydrocarbons. A three-dimensional reconstruction model of an X-ray micro-CT scan shows that while the amount of shale organic matter greatly decreases from the frozen state to 300 °C, the pore volume significantly increases, particularly between 90 and 300 °C. The increased pore volume is mainly due to macropores and fractures. It is imperative to note that the shale oil triple-division boundaries must be adjusted based on more accurate oil content, although this would not affect the resource zones to which the samples already belong (ineffective, low-efficient, and enriched resources). In conclusion, we strongly advise conducting an immediate well-site analysis or utilizing preservation procedures, such as deep freezing or plastic film wrapping followed by core waxing, to minimize volatile loss.

Enrichment of free oil in alkaline lacustrine Fengcheng Formation in Mahu Sag

Estimation of free hydrocarbon quantities in tight formations where pore sizes are at the nano and micron size is very important to understand formation producibility. In the Mahu sag, the Fengcheng Formation is being considered as an important source rock. Although the importance, characteristics of the Fengcheng Formation in terms of controlling factors on the enrichment of free vs. adsorbed hydrocarbons in pore spaces is still not clear. In this study, 13 samples were collected from the Fengcheng Formation and a combination of analytical techniques: X-ray diffraction analysis (XRD), nitrogen gas adsorption, total organic content (TOC), and Rock Eval pyrolysis were employed to analyze the microstructures and geochemical properties of the samples. These analyses were performed on two groups: 1) intact samples and 2) when the soluble hydrocarbon were extracted from the samples. The pore surface area and pore volume were measured slightly higher in the latter group, which were around 2.12 and 1.23 times of the intact samples, respectively. Moreover, deconvolution of pore size distribution (PSD) curves demonstrated that soluble oil mainly exists in the pore phases: 1, 2, 3, and 4 with the mean pore diameter of 15, 35, 51, and 67 nm, respectively. Overall, the oil in the samples of the Fengcheng Formation can become enriched with mobile (vs. adsorbed) fluids if the quantities of the free generated oil and pore size, each exceeds 0.7 wt% and 10.94 nm, respectively. This study can help researchers deepen their understandings of oil mobility and the evaluation of formation producibility in reservoirs deposited in an alkaline lake sedimentary environment.

How grain size influences hydrocarbon generation and expulsion of shale based on Rock-Eval pyrolysis and kinetics?

The differences between the Rock-Eval pyrolysis results of powder and grain samples have attracted wide attentions. Grain samples show lower hydrocarbon yield and different composition of the products. However, the effect of grain size on hydrocarbon generation and expulsion has not yet been quantitatively evaluated. In this study, we prepared each grain into a regular column with precise geometric parameters such as diameter, height, surface area, and volume, which is defined as an independent unit of hydrocarbon generation and expulsion. For comparison, a powder sample corresponding to each grain sample is collected simultaneously during the preparation process. The grain samples are used to simulate the mass of hydrocarbons expelled, while the powder samples are used to simulate the total mass of hydrocarbon generated. Our results show significant differences between the grain samples and the powder samples. All powder samples have a higher expulsion of free hydrocarbons (S1) than grain samples, and almost all grain samples have a higher expulsion of pyrolysis hydrocarbons (S2) than powder samples when the diameter of the grains is smaller than 3 mm. Temperature controls hydrocarbon generation, but grain size retards hydrocarbon expulsion. The influences of the “carry-over” phenomenon, oil adsorption and nanopore confinement are enhanced by grain size, which retards and inhibits hydrocarbon expulsion. Some free hydrocarbons (S1) cannot be expelled from the grain samples at 300 °C. Parts of the retained free hydrocarbons (S1) further cracked into small molecules, which can be expelled and detected as pyrolysis hydrocarbons (S2) at 300–650 °C. Four new parameters were proposed to quantify these influences, namely the S1retained, the S2extra expulsion, the HI difference parameter, and the TOC difference parameter. Diameter is more closely related to hydrocarbon expulsion rather than height. For grain samples, HI increases and TOC decreases with increasing diameter. Activation energies for hydrocarbon generation ranges from 43 to 67 kcal/mol for powder samples, while activation energies for grain samples are almost concentrated in 54–55 kcal/mol, indicating a high expulsion threshold for grain samples. As the grain diameter increases from 1.74 to 5.24 mm, the transformation ratio decreases and the generation rate increases, indicating that the grain size delays the expulsion of hydrocarbon. This laboratory simulation provides some new results to better understand the hydrocarbon generation and expulsion of shale rock under natural conditions.

Shale oil enrichment evaluation and production law in Gulong Sag, Songliao Basin, NE China

Based on the results of drilling, tests and simulation experiments, the shales of the Cretaceous Qingshankou Formation in the Gulong Sag of the Songliao Basin are discussed with respect to hydrocarbon generation evolution, shale oil occurrence, and pore/fracture evolution mechanism. In conjunction with a substantial amount of oil testing and production data, the Gulong shale oil enrichment layers are evaluated and the production behaviors and decline law are analyzed. The results are drawn in four aspects. First, the Gulong shales are in the stage of extensive hydrocarbon expulsion when Ro is 1.0%–1.2%, with the peak hydrocarbon expulsion efficiency of 49.5% approximately. In the low–medium maturity stage, shale oil migrates from kerogen to rocks and organic pores/fractures. In the medium–high maturity stage, shale oil transforms from adsorbed state to free state. Second, the clay mineral intergranular pores/fractures, dissolution pores, and organic pores make up the majority of the pore structure. During the transformation, clay minerals undergo significant intergranular pore/fracture development between the minerals such as illite and illite/smectite mixed layer. A network of pores/fractures is formed by organic matter cracking. Third, free hydrocarbon content, effective porosity, total porosity, and brittle mineral content are the core indicators for the evaluation of shale oil enrichment layers. Class-I layers are defined as free hydrocarbon content equal or greater than 6.0 mg/g, effective porosity equal or greater than 3.5%, total porosity equal or greater than 8.0%, and brittle mineral content equal or greater than 50%. It is believed that the favourable oil layers are Q2–Q3 and Q8–Q9. Fourth, the horizontal wells in the core area of the light oil zone exhibit a high cumulative production in the first year, and present a hyperbolic production decline pattern, with the decline index of 0.85–0.95, the first-year decline rate of 14.5%–26.5%, and the single-well estimated ultimate recovery (EUR) greater than 2.0×104 t. In practical exploration and production, more efforts will be devoted to the clarification of hydrocarbon generation and expulsion mechanisms, accurate testing of porosity and hydrocarbon content/phase of shale under formation conditions, precise delineation of the boundary of enrichment area, relationship between mechanical properties and stimulated reservoir volume, and enhanced oil recovery, in order to improve the EUR and achieve a large-scale, efficient development of shale oil.

Development of a Zonal Model for Forecasting the Oil and Gas Potential of the YUS1 Formation by Geochemical Parameters

The distribution of geochemical properties of rocks of the Bazhenov Formation (BF) by area and section has been refined, regularities have been searched, and conclusions have been obtained that have predictive power. Due to the high cost of continuous core sampling and pyrolysis of samples from BF intervals, the fragmentation and heterogeneity of the accumulated information, as well as the high value of knowledge about the oil-generating properties of BF rocks and their changes over the area, there is a need to increase the information content of the database of geochemical core studies and adapt its application in conditions of limited data. To solve this problem, a database of results of geochemical studies was collected and analyzed, consisting of 5272 samples from 123 wells of 32 fields. As a result of the analysis, conclusions were obtained about the oil-generating properties of BF within the study area and the degree of maturity of the organic matter of the rock. Two regression models were developed to predict the geochemical parameters of free hydrocarbon content, residual generation potential and total organic carbon from well logging data. An algorithm was implemented in the Python programming language to automate the calculation process. Using this algorithm and the resulting regression equation, the calculation of geochemical parameters was carried out in 390 wells in the study area that were not presented by core data, which significantly increased the detail and information content of predictive maps of the distribution of parameters over the area. Using the data obtained, a geological and mathematical model was developed for predicting oil content by geochemical parameters. The developed model reflects the probability of oil content depending on the oil source properties of the rocks of the Bazhenov formation in the study area. The developed forecast model included the parameters of the organic carbon content in the rock, the current reservoir temperature and the thickness of the rocks of the Bazhenov formation.

Estimation of pore pressure considering hydrocarbon generation pressurization using Bayesian inversion

Undercompaction and hydrocarbon generation are the main factors affecting pore pressure. The current seismic pore-pressure prediction (PPP) method is to obtain the overpressure trend by estimating the normal compaction trend (NCT) to predict the physical parameters during normal compaction and comparing the measured parameters. However, selecting a single parameter to indicate overpressure may cause insufficient consideration of factors, such as hydrocarbon generation. Because hydrocarbon generation requires specific temperature and other conditions, pore pressure is divided into two parts: undercompaction in the early stage and hydrocarbon generation after reaching the hydrocarbon generation threshold. A rock-physical model is established for estimating the NCT before hydrocarbon generation to modify the bulk modulus of the model and calculate the pressure generated by undercompaction; the pressure generated by hydrocarbon generation is added to obtain the final pore pressure. In the shale gas work area in the Sichuan Basin, the prediction results are more in line with the actual situation, and the petrophysical analysis indicates that the ratio of free hydrocarbon content and kerogen to water is the influencing factor indicating pore pressure. The practicality of the PPP formula considering hydrocarbon generation in oil and gas sweet spots is illustrated through an example in the research area.

Carbon stability and morphotype composition of biochars from feedstocks in the Mekong Delta, Vietnam

This study investigates carbon stability of biochars produced from wood, herbaceous, and fruit agricultural waste products from southern Vietnam. The biochars were produced by pyrolysis to 500 °C, 700 °C, and 900 °C at a heating rate of 10 °C/min. Organic geochemistry and petrology have well-established measurable parameters that define degree of preservation of organic carbon in the Earth's crust. These parameters are utilized, comparatively, to infer the organic carbon stability in biochars relative to that preserved in the geological carbonaceous rocks. The stability of carbon was assessed by measuring incident-light random reflectance (%Ro) to determine the degree of thermally induced aromatization/ordering of the biochar carbon molecules. Additionally, the organic carbon content of the biochars was quantitatively separated into reactive and non-reactive carbon fractions based on thermodynamic stability of CH and CO bonds. The results show increasing carbon stability with increasing pyrolysis temperature and indicate high stability has been achieved at 700 °C and 900 °C where the biochars have the highest total organic carbon (TOC) contents and lowest Hydrogen Index values. Occurrence of a small quantity of readily degradable, labile free hydrocarbons (soluble organic matter; SOM) is due to condensation of the thermally generated hydrocarbons on the surfaces of the biochars. This fraction is minimized in the biochars produced at 700 °C and 900 °C due to volatilization of the free hydrocarbons at higher pyrolysis temperatures. The relatively substantial content of labile hydrocarbons associated with particulate organic matter (POM) in the 500 °C produced biochars is attributed to the incomplete pyrolyzation of the feedstock at this temperature. This fraction declines to near zero at 700 °C and 900 °C as complete carbonization is achieved at these higher temperatures. The overall carbon budget within the biochar shows that irrespective of the biochar type, over 97% of the TOC consists of highly refractory, residual carbon that geochemically is considered to possess long-term stability (“inert”). This is further underpinned by a pronounced increase in biochar mean random reflectance from <2.33% at 500 °C to >4.35% when pyrolyzed at 700 °C, indicating a highly polyaromatized condensed carbon structure. Rice husk is an exception as it yields a mean reflectance of 4.55% at 500 °C suggesting that pyrolysis temperature is not the only factor controlling %Ro and hence carbon stability. Furthermore, the biochar compositions show a relationship between feedstock and pyrolysis temperature. The biochar morphotype composition changes significantly with increasing temperature, but the analyzed biochars are all dominated by fusinoid/solid (primarily fusinoid) morphotypes with the highest initial quantity recorded at 500 °C. This quantity decreases with increasing pyrolysis temperature while porous morphotypes (tenuinetwork, crassinetwork, mixed porous, mixed dense) increase. Variations in morphotype composition observed between the biochars is attributed to the structural nature of the feedstocks.

Microstructures of continental organic-rich shale and its adjacent siltstone and carbonate rocks—An example from the Lucaogou Formation, Jimusar Sag, Junggar Basin, NW China

To investigate pore structure of a continental shale and its adjacent carbonate rock and siltstone, 93 shales, 30 carbonate rocks and 10 siltstone samples from the Lucaogou Formation, Junggar Basin were examined by using low-pressure gas (N2 and CO2) adsorption, mercury intrusion and FE-SEM. Total organic carbon (TOC) evaluation, Rock-Eval pyrolysis, and X-ray diffraction (XRD) were used to characterize the organic geochemical parameters and mineralogical parameters of studied samples. The results showed that the free hydrocarbon S1 decreased in the order of siltstone, shale and carbonate rock, which is in accordance with the macropore surface area results. The carbonate rock has the highest TOC content and pyrolytic hydrocarbon S2, followed by shale and siltstone. The inter-crystalline pores of clays and intergranular pores exist widely in shale and siltstone, and a large number of dissolution pores were developed within shale, carbonate rock and siltstone. The smectite, illite and illite/smectite together control the micropores and mesopores of shale, more macropores and mesopores are present in the low TOC shale, carbonate rock and siltstone, however, the promotion effect of TOC on micropores of carbonate rock is stronger than clay. The more macropores of shale and siltstone, causes higher amounts free hydrocarbon S1. In addition, the free hydrocarbon S1 is higher at low fractal dimension D1 (D1＜2.3) and high fractal dimension D2 (D2＞2.6) of mesopore in shale. The free hydrocarbon S1 of the massive siltstone and thin layered shale are significantly higher than that of other types, which may be related to that high macropore volume and low mesopore fractal dimension D1 of the thin layered shale and the high macropore surface area of massive siltstone.