Qingshankou Formation Research Articles

Pore types, genesis, and evolution model of lacustrine oil-prone shale: a case study of the Cretaceous Qingshankou Formation, Songliao Basin, NE China

A comprehensive characterisation of the pore structure in shale oil reservoirs is essential for forecasting oil production and exploration risks. This study forecasted these risks in the oil-rich Songliao Basin using combination of high-resolution field emission scanning electron microscopy and quantitative X-ray diffraction to analyze the pore genesis and evolution mode within the first member of the Cretaceous Qingshankou Formation (K2qn1). The results showed the dominance of inorganic pores over organic pores, wherein diagenetic processes, such as compaction, pressure solution, and cementation, were responsible for the destruction of pore structure in the formation. Notably, the pores formed by dissolution and shrinkage cracks resulting from clay mineral transformation improved the oil storage space. Furthermore, according to the geochemical data and clay composition, the K2qn1 shale is in the middle diagenetic stage A, which can be further subdivided into A1 and A2 stages from top to bottom. The porosity slowly decreased in both sub-stages A1 and A2, wherein the decrease was stable in the latter. The diagenetic observations in this study are significant for the exploration of unconventional shale oil in petroliferous basins worldwide.

Authigenic silica in continental lacustrine shale and its hydrocarbon significance

Taking lake basin shales of the Triassic Yanchang Formation in the Ordos Basin, NW China and the Cretaceous Qingshankou Formation in the Songliao Basin, NE China as research objects, the characteristics and origins of different types of silica in the shales have been studied by means of core observation, thin section identification, cathodoluminescence, X-ray diffraction analysis, scanning electron microscope (SEM), electron probe and rock pyrolysis. The results shows that the origins of silica include felsic mineral dissolution, tuffite devitrification, clay mineral transformation and siliceous mineral metasomatism. The silica formed by feldspar dissolution commonly appears as spots and veins, with low degree of crystallization, and is largely aqueous opal mineral, with an average SiO2 content of 67.2%. Silica formed by devitrification of tuffite mainly occurs in two forms, amorphous silica and authigenic quartz with better crystal shape. The authigenic silica formed during the transformation of clay minerals is embedded in the clay minerals in the form of micron-scale plates and small flakes, or mixed with clay minerals in a dispersed state. The authigenic quartz formed by siliceous mineral metasomatism is in better angular crystal shape, and has an average SiO2 content of 87%. The authigenic siliceous mineral content is positively correlated with the content of terrigenous felsic minerals. The pressure solution of felsic minerals is the main source of authigenic siliceous minerals, followed by the transformation of clay minerals, and the organic matter has some boost on the formation of authigenic silica. The authigenic siliceous materials of different origins have different geological characteristics and occurrence states from terrigenous quartz, which would affect the storage performance, seepage capacity and fracturing effect of continental shale. Although the organic-rich shale has high silica content, different from terrigenous quartz, authigenic silica in this kind of shale mostly floats and disperse in clay minerals, which would have negative effect on the formation of complex fractures in fracturing, fracture support ability after fracturing, and formation of effective seepage channels. Calculating the brittleness index of shale intervals only based on the composition of brittle minerals cannot accurately characterize mechanical characteristics of continental shale oil reservoirs, and would affect comprehensive evaluation and selection of continental shale oil “sweet spots”.

Pore Structure Characteristics and Affecting Factors of Shale in the First Member of the Qingshankou Formation in the Gulong Sag, Songliao Basin.

A major historical breakthrough has been made in the exploration of the GK (the first member of the Qingshankou Formation (K2qn1), Gulong Sag) shale oil of the Songliao Basin. However, few reports have been reported on the pore structure characteristics of this large-scale lacustrine medium–high maturity shale. In addition, the difference between the pore structure characteristics of the GK shale and medium–low maturity marine/continental shale is unknown, and the affecting factors of pore development are still unclear. Therefore, in order to clarify the pore structure characteristics of the GK shale and its affecting factors, this study characterized them experimentally and revealed the law of pore evolution using the mineral composition and geochemical analysis, microscopic observations, and pore quantification techniques. Results indicate that (1) the pore system of GK shale reservoirs is divided into micropores (pore diameter < 10 nm), mesopores (10 nm < pore diameter < 50 nm), and macropores (pore diameter > 50 nm); (2) the pore structure of the GK shale is mainly affected by the clay content, siliceous mineral content, and thermal maturity; and (3) when the content of clay minerals and siliceous minerals in the GK shale reservoir is high, and ∼0.8% < Ro < ∼1.4%, the storage capacity and oil content of the GK shale show high values, and it can be considered as a strong candidate for further exploration and development. This research can push the shale oil revolution to a new height and is significant to promote the development of the petroleum industry.

Influences of Clay Mineral and Organic Matter on Nanoscale Pore Structures of the Cretaceous Lacustrine Shales in the Songliao Basin, Northeast China

The Cretaceous lacustrine shales of the Qingshankou Formation (K2qn) from the Songliao Basin are recognized as a potential shale oil reservoir in China. Pore structure of shale within the oil window could be significantly influenced by several factors, including mineral and organic matter (OM) compositions. For a better understanding of the factors controlling the pore structure of these shales, 15 core shales from the K2qn were subjected to low-pressure N2 adsorption measurement for both the initial and solvent extracted samples, and the relationships between shale compositions and pore structure parameters were discussed. The results show that the average specific surface area (SSA) and pore volume (PV) increase from 10.14 m2/g to 29.74 m2/g and from 0.0276 cm3/g to 0.0554 cm3/g respectively after extraction, which suggests that the nanopores in these shales could be significantly occupied by the soluble OM, especially for the pores smaller than 10 nm in size. For the extracted samples, the good positive correlations between the SSA and the illite/smectite (I/S) content indicate that a significant amount of small pores are associated with this mineral, while the overall positive correlations between the PVs with the I/S and OM contents suggest that I/S mineral and organic matter (kerogen) have contributed most to pores lager than 10 nm. It is assessed that OM pores contribute approximately 16% to total PV of these shales. Our results will improve the understanding of pore characterization of the clay- and OM-rich lacustrine shales and provide some implications for shale oil accumulation in the Songliao Basin.

Geochemical Features of Lacustrine Shales in the Upper Cretaceous Qingshankou Formation of Changling Sag, Songliao Basin, Northeast China

The organic-rich shale of the Upper Cretaceous Qingshankou Formation is an important hydrocarbon source rock in Northeast China. In this study, taking the lacustrine shale in the Qingshankou Formation as an example, geochemical analysis, including total organic carbon (TOC), Rock-Eval pyrolysis, maceral compositions, X-ray diffraction (XRD), and biomarker analyses, were carried out on twenty-four shale samples to evaluate the geochemistry and environmental features of this shales. The Qingshankou lacustrine shales contains mainly Type I/II1 organic matter and is oil prone, with a good to excellent source rock. Vitrinite reflectance and Rock-Eval pyrolysis parameters show that the Qingshankou lacustrine shales is mainly in the mature stage and within the oil window. Biomarker composition of the shales provide evidence that the Qingshankou lacustrine shales was formed in a reductive sedimentary environment with relatively high salinity water. The organic matter came from a mixture of plankton, bacterial and land plants.

Characterization of Microstructures in Lacustrine Organic-Rich Shale Using Micro-CT Images: Qingshankou Formation in Songliao Basin

In order to explore the development characteristics and influencing factors of microscale pores in lacustrine organic-rich muddy shale, this study selected five shale samples with different mineral compositions from the Qingshankou Formation in the Songliao Basin. The oil content and mineralogy of the shale samples were obtained by pyrolysis and X-ray diffraction analysis, respectively, while the porosity of the samples was computed by micro-CT imaging. Next, based on the CT images, the permeability of each sample was calculated by the Avizo software. Results showed that the continuous porosity of Qingshankou shale in the Songliao Basin was found between 0.84 and 7.79% (average 4.76%), the total porosity between 1.87 and 12.03% (average 8.28%), and the absolute permeability was calculated between 0.061 and 2.284 × 10−3 μm2. The total porosity of the samples has a good positive correlation with the continuous porosity and permeability. This means higher values of total porosity suggested better continuous porosity and permeability. Both total porosity and continuous porosity are positively correlated with the content of clay minerals. Moreover, the oil content of the samples (the S1 peak from programmed pyrolysis) exhibits a good positive correlation with the total porosity, continuous porosity, permeability, and clay mineral content. Therefore, pores that are developed by clay minerals are the main storage space for oil and flow conduits as well. Clay minerals were found to be the main controlling factor in the porosity, permeability, and the amount of oil content in the pores in the study area.

Laminar Structure and Reservoir Quality of Shales with High Clay Mineral Content in the Qingshankou Formation, Songliao Basin

This paper investigates high-maturity organic matter-rich shales with high clay mineral contents in the Qingshankou Formation, in the Gulong Depression of the Songliao Basin, at a sub-millimeter scale, using a new laminar division method based on XRF data. The influence of laminar structure on reservoir quality is examined using a combination of geochemistry, mineralogy, and pore structures. Explanatory models are established. Three types of laminar units are distinguished in the study area based on differences in pore structure. These are clay mineral laminae (UA), clay mineral-Ostracod laminae (UB), and clay mineral-felsic laminae (UC). UA has illite intergranular pores, micro-fractures, and organic pores, with diameters of 0.5~2 μm. UB primarily contains Ostracod shell margin fractures, pyrite intergranular pores, and chlorite intragranular pores. UC contains albite and illite intergranular pores. Nitrogen adsorption tests show that UA has the highest clay content and the best specific pore volume and specific surface area, indicating that clay minerals are the main contributors to the pores in this type of unit. 2D–3D models of different laminae reveal that carbonate cement is widely developed in UB and UC, but dissolution pores are less developed, with the result that the porosity of UA is two to three times greater than that of UB or UC. It appears that intergranular pores and fractures, formed during the transformation of clay minerals during the advanced thermal evolution stage, are the main contributors to storage space and flow channels. Thermal evolution, clay mineral transformation, and carbonate cementation are the key factors causing differences between laminar units. In addition, clay mineral laminae (UA) are the most important laminar units for shale oil enrichment in the study area. This finding is of great significance for accurately predicting the distribution of shale “sweet spots” and guiding shale oil and gas exploration.

Determination of in situ hydrocarbon contents in shale oil plays. Part 2: Two-dimensional nuclear magnetic resonance (2D NMR) as a potential approach to characterize preserved cores

Determination of the in situ hydrocarbon content and occurrence characteristics of shale oil reservoirs is crucial for reserve prediction and efficient development. Although many scholars have studied the fluid saturation of conventional coring shale using solvent and thermal extraction methods, with time consuming and only volumes or mass of oil and water were given, which could not reveal the occurrence characteristics of oil and water in samples. This study proposes a two-dimensional (2D) nuclear magnetic resonance (NMR) T1–T2 mapping method to systematically assess the in situ water and oil content, distribution, and their evaporative loss laws of preserved shales. Sixty preserved shales with different maturities were selected from the first member of the Qingshankou Formation in the northern Songliao Basin, China. Each preserved sample was divided into two parts and analyzed using a high-frequency (22 MHz) NMR and Dean–Stark extraction respectively. Furthermore, a time-elapsed NMR T1–T2 mapping was performed on a preserved shale core sample after varying the exposure times in an open environment. Results show that T1–T2 mapping can be used to determine the porosity, water and oil contents, and saturations of preserved shales. Oil content measured using T1–T2 mapping was consistent with that obtained by Dean–Stark extraction, with a correlation coefficient (R2) as high as 90% when crude oils of varying maturities were used for NMR calibration.The T1/T2 of oil inpreserved shale showed a negative trend with maturity, and the T2 of oil was often higher than that of water, indicating oil is enriched in the relative macropores. After exposing the preserved shale to open air for 150–200 h, 1) the total loss ratio of oil and water was approximately 80%; 2)the fluid evaporation loss rate follows the orders: oil > water and fluids in larger pores > smaller pores; 3)the free oil content decreased by approximately 92%, whereas the absorbed oil content varied slightly. As a nondestructive, rapid, and minimal sample preparation method, 2D NMR can efficiently assess both fluids content and distribution of a core sample in only 5 min, thus displaying its great advantages and applications for preserved shales with fast fluid evaporation to determine the in situ fluid content.

Impact of thermal maturity on the diagenesis and porosity of lacustrine oil-prone shales: Insights from natural shale samples with thermal maturation in the oil generation window

Shale diagenesis controls the generation, migration and accumulation of hydrocarbons through time and has become a frontier area of study in the fields of sedimentology and petroleum geology. There have been only a few studies on the generation of organic pores in lacustrine shale oil reservoirs during the oil generation thermal evolution stage. In this study, lacustrine organic-rich shale samples at various stages of maturity, from the first member of the Songliao Basin Qingshankou Formation were investigated, and a thermal transformation law of macerals was established, based on organic petrology. The diagenetic alteration styles and sequences were investigated using a high-resolution field emission scanning electron microscope, and cathode luminescence. Furthermore, automated pore extraction technology enabled the examination of the characteristics and genetic process of organic and inorganic pores under the influence of thermal maturation. The results indicate that a small quantity of pre-oil bitumen is generated during the early oil mature stage (Ro: 0.7% - 0.9%), and that the generation of a large quantity of post-oil bitumen that occurs following the peak oil generation stage (i.e., late oil mature stage, Ro: 1.1% - 1.4%), is controlled by the unimodal distribution of the activation energy of Type I kerogen. Compaction intensity certainly influences pore volume reduction. Siliceous cementation primarily occurs during peak oil generation maturity and the subsequent thermal evolution stage. The pores formed in the oil generation window primarily arise from mineral dissolution and organic matter polycondensation. Following peak oil generation, the pores undergo iron dolomitization, smectite illitization, and bitumen cracking. The degree of development of inorganic pores, the most common pore type in shale oil reservoirs, appears to have a significant impact on the total porosity of a reservoir shale. During thermal evolution, the inorganic pore volumes show a decreasing trend. There is a secondary pore development stage, reached when Ro exceeds 1.2%, closely related to the transformation of clay minerals. According to the hydrocarbon generation kinetics and compaction model, organic pore volumes increase gradually at 0.7%Ro, reach their peak at 1.1%Ro, and then steadily decrease due to compaction. The organic pores are relatively well developed when Ro is >0.85% (at the start of the oil window). The shale oil reservoir's most favorable thermal evolution stage is late oil maturity stage that follows the oil generation peak.

Effects of types and content of clay minerals on reservoir effectiveness for lacustrine organic matter rich shale

As a promising supplement of China’s petroleum production, the lacustrine shale, compared with the marine shale, is characterized by higher clay mineral content, which has significant impacts on the hydrocarbon reservoir quality. Controlled by the paleo-lacustrine background and thermal maturity, the clay mineral contents vary tremendously in different shale systems. This study targets on three shale series formed in different basin types, namely the Lucaogou Formation shale (Junggar Basin), the Chang 7 Member shale (Ordos Basin), and the Qingshankou Formation shale (Songliao Basin), where the Junggar Basin was a saline lacustrine basin and the latter two were freshwater-brackish lacustrine basins. We find that the composition and content of clay minerals are considerably varied among the three shales that the clay mineral content of the Lucaogou formation shale is smaller than that of the Chang 7 Member and Qingshankou Formation, and the content of illite in the Chang 7 shale is lower than that in the Qingshankou shale. The occurrence of clay minerals has crucial effects on pore structures, that is the pore-filling clays has indiscernible contribution to the storage space, like in the Lucaogou shale, but those developing along the shale laminae can improve the storage capacities to form inter-granular pores and micro-fractures such as in Chang 7 Member and Qingshankou Formation. The development of clay mineral-related pores and fractures is controlled by thermal maturity (Ro) and affected by the content of terrigenous minerals. This pore structure alteration derived by the clay mineral occurrence types further affects the hydrocarbon contents. In the Lucaogou shale, the oil content is inversely proportional to clay mineral contents, while in Qingshankou Formation, the oil content is even higher than that of the adjacent felsic silt laminae due to the favorable development of micro-fractures and inter-granular pores in clay mineral laminae. The high clay mineral content in lacustrine shales in China make it necessary to investigate the clay mineral evolution to evaluate the hydrocarbon generation potential, pore structures, hydrocarbon contents, and hydrocarbon accumulation mechanisms in shale systems.

Multi-scale classification and evaluation of shale reservoirs and ‘sweet spot’ prediction of the second and third members of the Qingshankou Formation in the Songliao Basin based on machine learning

Owing to the unique structure of shale reservoirs intercalated with thin siltstone in the second and third members of the Qingshankou Formation (K1qn2+3) in the north of the Central Depression of the Songliao Basin, it is difficult to objectively predict and evaluate multi-scale (i.e., from the micro to macro scale) physical properties of the reservoir and the ‘sweet spot’ area (the area with the best reservoir quality). Using machine learning, we present herein a new machine learning framework (GCA-CE-MGPK) specific to reservoirs for studying the shale reservoirs in K1qn2+3. According to the results of a high-pressure mercury-injection experiment, organic geochemical analysis and scanning electron microscopy. Through grey correlation analysis, clustering ensemble and the Kriging model combined with macro geological parameters, an efficient, accurate and objective multi-scale evaluation of the shale reservoirs and the prediction of the ‘sweet spot’ area were realised. This method can be used to overcome difficulty in parameter selection, time-consuming classification of a large amount of data and difficulty in macro-scale reservoir prediction in the absence of seismic data with an average accuracy of 82.4%. The reservoir prediction results showed that the Class-I reservoir, the ‘sweet spots’ area, is mainly distributed in the north of the study area with an area of 3.15 × 108 m2; the Class-II reservoir is mainly distributed in the north of the study area with an area of 9.88 × 108 m2; the Class-III shale reservoir is the most widely distributed reservoir type with an area of 4.90 × 109 m2. Overall, compared with K1qn1, K1qn2+3 offers more realistic oil and gas exploration potential and advantages.

Quantitative analysis of paleoenvironment of Qingshankou Formation in northern Songliao Basin, Northeastern China

The Qingshankou Formation in the Songliao Basin of northeastern China is an important layer for unconventional oil exploration. To solve the problem of the main controlling factors of shale oil enrichment, to quantitatively analyze the paleosalinity, paleoclimate, paleoredox environment, provenance, and lake productivity, and to clarify the relationship between sedimentary environment and total organic carbon, we have analyzed quantitative reconstruction of the sedimentary environment by using comprehensive analysis of multiple indicators with major and trace elements, fossils, and biomarkers. The results are as follows: the paleosalinity index w(Sr)/ w(Ba) ratio is 0.4–4, the w(B)/ w(Ga) value is 0.7–8.5, and the w(Pr)/ w(Ph) value is 0.8–2.8, which mainly stand for fresh brackish to saline water. The paleoclimate CIW′ (Chemical index of weathering, CIW = [A12O3/(AI203 + CaO+Na20)] × 100 [molecular proportions]) value is 90–100, indicating a warm and humid climate. The redox index w(V)/ w((V + Ni)) value is 0.54–0.89, which mainly belongs to the dysoxic environment. The provenance input of terrigenous debris index w(Ti)/ w(Al) value is 0.026–0.034, mainly standing for low terrigenous debris input. The production index CAL (enrichment degree of Cu) value is 1–3, belonging to high production. We conclude that the humid climate, the fresh brackish to saline and dysoxic water, and the high lake production provide favorable geologic conditions for biological reproduction and then provide a foundation for the formation, enrichment, and preservation of organic matter. The quantitative reconstruction of the paleoenvironment of the Qingshankou Formation has theoretical significance for Gulong shale oil exploration and development.

Sedimentary characteristics and implications for hydrocarbon exploration in a retrograding shallow-water delta: An example from the fourth member of the Cretaceous Quantou Formation in the Sanzhao depression, Songliao Basin, NE China

Based on the analysis of core, logging, and testing data, the fourth member of the Cretaceous Quantou Formation (K2q4) in the Sanzhao depression, Songliao Basin, is investigated in order to understand the sedimentary characteristics and hydrocarbon exploration significance of a retrograding shallow-water delta. The results show that during the sedimentary period of K2q4, the Sanzhao depression with a gentle basement experienced stable tectonic subsidence and suffered a long-term lake level rise caused by paleoclimate changes (from semiarid to semihumid), the K2q4 in the study area were dominated by a fining-upward deltaic succession and had relatively stable thickness. From the bottom to the top, the color of mudstone gradually changes from purplish-red to gray and grayish-green, the contents of caliche nodules decrease gradually, while the presence of pyrite in sediments becomes frequent. Channel sandstones mainly composed of siltstone and fine sandstone with developed high-energy sedimentary structures constitute the main sand bodies of deltaic deposits, but the scale of channel sandstones decrease upward. Despite the long-term lake level rise and fining-upward sedimentary succession, purplish-red mudstone, caliche nodules and thin channel sandstones are still broadly distributed in the study area, and thin channel sandstones can be found at the top of K2q4 covered by the black oil shale of Qingshankou Formation. These assertations suggest that the study area was dominated by retrograding shallow-water delta deposits during the sedimentary period of K2q4. In comparison with modern Poyang Lake, we infer that during the sedimentary period of K2q4, the study area experienced frequent lake level fluctuations triggered by paleoclimate changes despite the long-term lake level rise, and the lake level fluctuations control the deposition of retrograding shallow-water delta. In addition, most of the thin channel sandstones distributed at the top of K2q4 and covered by black oil shale are generally immersed in oil, indicating that the thin channel sandstones formed at the top of a retrograding shallow-water delta sedimentary succession are favorable targets for lithological reservoir exploration.

Evolution of Fractal Pore Structure in Sedimentary Rocks

AbstractGeological processes alter pore spaces over time, and their analysis can shed light on the dynamic fractal structure and fluid flow of rocks over time. This study presents experimental evidence to illustrate that the pore fractal structure evolves with sedimentation, carbonate cementation, clay growth, and dissolution. It examines, describes and characterizes a suite of core samples from the Gaotaizi oil layer of the second and third members of the Qingshankou Formation, Songliao Basin, China. The effects of mechanical compaction and other diagenesis effects on fractal pore structure on sedimentary rocks are discussed. A schematic diagram is proposed that describes the impacts of these diagenetic processes on fractal pore structure at the microscopic scale in sedimentary rocks. This work links the state of diagenetic alteration and fractal pore structure, which can guide practical applications such as predicting the permeability of sedimentary rocks.

Thermal maturity: The controlling factor of wettability, pore structure, and oil content in the lacustrine Qingshankou shale, Songliao Basin

Shale oil resources are abundant in the Qingshankou Formation of the Songliao Basin, but there are significant production differences between wells. Although there are many factors affecting shale oil production capacity, they are all fundamentally reflected in the differences of pore structure and oil-bearing; however, research on the pore structure and oil-bearing characteristics of naturally mature shale is still rarely reported. Lacustrine shales with low to high maturity developed in the Qingshankou Formation, Songliao Basin; these shales can be used as good natural mature samples to reveal the wettability, pore structure, oil content, and evolution of shale under the control of thermal maturity. In this study, geochemistry, oil content, and mineral composition information were analyzed using total organic carbon, thermal maturity, Rock-Eval pyrolysis, and X-ray diffraction; low-temperature nitrogen adsorption–desorption (N2GA), nuclear magnetic resonance (NMR), high-pressure mercury injection, and field emission scanning electron microscopy (FE-SEM) were used to analyze the shale pore structure; and spontaneous imbibition (SI) combined with NMR and contact angle measurement (CAM) experiments were performed to reveal the shale wettability. The results indicate that with the evolution of maturity from low to high, the cracking degree of organic matter (OM) and the amount of hydrocarbon generation increases, and the scale (number, size) of OM pore development continues to increase. The porosity, pore volume, and Brunauer–Emmet–Teller specific surface area of shale increased continuously due to the increased thermal evolution of OM, and a great many of micropores formed in the shale. Therefore, the average pore size decreased with increased maturity. In addition, shale oil content also improves with the continuous hydrocarbon generation of OM in the process of thermal evolution; The wettability of the shale interior and surfaces gradually changes from water wetting to oil wetting when vitrinite reflectivity (Ro) > ∼1.20% and the degree of oil wetting continues to increase as maturity increases. The crude oil generated by kerogen continues to flow from micropores to macropores, and the pore network continues to develop with increasing oil wetting degree, which is beneficial to crude oil migration and accumulation in the shale reservoir.

Extraction of Organic Compounds From Lacustrine Oil-Prone Shales and the Effect on Nanopore

Lacustrine oil-prone shale at the oil-generation stage develops a large number of nanopores; however, the influence of fluid–shale interactions on the nanopores of lacustrine shale is poorly understood. A suite of mature lacustrine shales from the Songliao Basin Qingshankou Formation was performed on sequential organic solvent (petroleum ether and mixture of dichloromethane and methanol) extractions, and nitrogen and carbon dioxide adsorptions, Rock-Eval pyrolysis and field emission scanning electron microscopes (FE-SEM) observation. The sequential extractions show a decrease in total organic matter (TOC) and in the exacted organic matter content of shale, but an increase in the specific area (SBET) and pore volume of the extracted residues. Before and after extractions, the relationships between the extracted amount of OM and SBET, pore volume and their cumulative increments reveal OM as a main factor affecting the development of nanopores in these shales. The reasons are 1) SBET and mesopores are mainly blocked by EOMs in the initial samples, 2) the cumulative increases of SBET and mesopores are dominantly controlled by the extracted amount of hydrocarbons during petroleum ether extraction, and 3) both hydrocarbons and NSOs (resins and asphaltenes) have an influence on the cumulative increases of SBET and mesopores, and kerogen exposed more open porous-organic mesopores after the EOMs in the extracted shales. Here, further work concludes that oils adsorbed on pore surfaces are dominantly distributed on nanopores less than 10 nm, and free oils occur when the threshold of the average pore width in studied shales is over 11.7 nm.

Self-sealing of caprocks during CO2 geological sequestration

The self-sealing of caprocks plays a vital role in CO2 geological sequestration. However, the mechanisms by which distinctive mineral combinations and types of caprock bring about self-sealing are unclear. Studies of the self-sealing of caprocks with different mineral combinations and rock types promise to effectively identify the self-sealing capabilities of cap rocks and evaluate the long-term safety of CO2 geological sequestration. This study focuses mainly on the mechanisms of self-sealing in three caprocks, specifically the shale of the Qingshankou Formation in the Songliao Basin, the calcareous mudstone of the Da'anzhai Formation in the Sichuan Basin, and the shale of the Yanchang Formation in the Ordos Basin. This study applies the key technology of CO2–fluid–rock numerical simulation and petrological and analytical methods to systematically investigate the self-sealing capability of these caprocks, which have different mineral compositions, and identify the key minerals that trigger self-sealing. The results show that the key minerals that can trigger self-sealing after CO2 injection are carbonates such as calcite, siderite, and dolomite and clays such as kaolinite. The CO2–fluid–rock interactions in feldspar- and illite-rich shale are relatively mild, which is conducive to the safe geological sequestration of CO2. In contrast, the CO2–fluid–rock interactions in carbonate-rich shale are violent and fluctuate greatly, which is not conducive to the short-term safe sequestration of CO2, but they are favorable for the safe sequestration of CO2 in the medium to long term. After CO2 injection, the main minerals precipitated in a carbonate-rich shale are K-feldspar and small amounts of ankerite and dawsonite. The main minerals precipitated in illite-rich shale are quartz and small amounts of ankerite and dawsonite. The results of this study show that it is possible to effectively evaluate the sealing capability of caprocks, thus providing a basis for the safe sequestration of CO2.

Integrating advanced soft computing techniques with experimental studies for pore structure analysis of Qingshankou shale in Southern Songliao Basin, NE China

Evaluating pore structure of unconventional shale reservoirs enables us to determine their productivity, allowing for better operational decisions. Despite extensive studies in this field, considering the complexity of shale plays, pore structure analysis of such formations still requires novelties and further research. In this study, 10 samples from the Qingshankou Formation (from 5 wells) were analyzed with X-ray diffraction (XRD), programmed pyrolysis, N2 adsorption, and mercury intrusion capillary pressure (MICP). In the next step, several modern intelligent smart models including multilayer perceptron (MLP), radial basis function (RBF), generalized regression neural network (GRNN), cascaded forward neural network (CFNN), and least squares support vector machine (LSSVM), that were optimized by levenberg-marquardt (LM), Bayesian regularization (BR), genetic algorithm (GA), ant colony optimization (ACO), particle swarm optimization (PSO), and differential evolution (DE) algorithms were employed, to estimate the volumes of N2 adsorbed and desorbed based on the mineralogy and geochemical properties of the samples. Results show that samples are mainly composed of clay (up to 42.3 wt%) and quartz (up to 34.6 wt%), low in total organic carbon (TOC) (up to 2.89%) and in the oil generation window. Complexity of smaller pores was found higher compared to medium and larger ones. In addition, deconvolution of N2 adsorption pore size distribution (PSD) curve revealed that samples are composed of up to three families in the range of macropore size and different families in mesopore size. We found that LSSVM with applicability to the entire input dataset, outperformed all other models in predicting the amount of nitrogen adsorption and desorption with an average absolute percent relative error (AAPRE) value of 1.94%. Ultimately, clay minerals and potash feldspar had the greatest effect on increasing and decreasing the amount of nitrogen adsorbed and desorbed, respectively. The Leverage technique's findings demonstrate that more than 97% of total data points in the LSSVM model are in the valid domain. This study proves that smart methods if used properly, would enable us to study a large group of samples independent from exhaustive, time consuming and expensive experimental methods.

Lithofacies and Source Rock Quality of Organic-Rich Shales in the Cretaceous Qingshankou Formation, Songliao Basin, NE China

The organic-rich shale of the Qingshankou Formation (K2qn) is the most important target in the Songliao Basin. The relationship between lithofacies and source rock quality, however, is still controversial. Core observation, thin section identification, X-ray diffraction, organic geochemistry, and other analytical methods were adopted to investigate the petrology and its effects on hydrocarbon potential of the Qingshankou shale. Based on the differences in minerals, bioclastic, and fabric of laminae, four main lithofacies were defined as: (i) felsic shale (FS), (ii) clay shale (CS), (iii) bio-bearing shale (BS), and (iv) mixed shale (MS). The clay minerals content in the CS (average: 46.72 wt%) and MS (average: 41.11 wt%) was higher than that in FS (average: 39.97 wt%) and BS (average: 35.48 wt%). This classification allows the following comparative quantification of total organic carbon (TOC) content to be differentiated: CS &gt; BS &gt; MS &gt; FS. Geochemical analysis indicated that the oil generation potential of the CS was the best, and the hydrocarbons generated from CS might migrate and accumulate in other lithofacies. All this knowledge could shed light on the lithofacies classification in shale systems with high clay mineral content, and may provide references for sweet spotting of the Qingshankou Formation in the Songliao Basin.

Distribution characteristics and oil mobility thresholds in lacustrine shale reservoir: Insights from N2 adsorption experiments on samples prior to and following hydrocarbon extraction

The pore structure and oil content of shales have an important influence on the oil mobility and enrichment. In this study, the lacustrine shale samples from the Qingshankou Formation (Q1) of Songliao Basin were selected. TOC, pyrolysis, XRD and nitrogen adsorption were performed on the original and extracted shale samples. Then the influence of mineral composition and organic matter (OM) on the development of nano-scale pore, the oil phase states and mobility were analyzed. The Q1 shale samples can be sub-divided into three types according to the isotherm characteristics. Type A samples are characterized by high kerogen content, with oil mainly existing in the free phase state. Type B samples are characterized by medium kerogen content, oil mainly exists in the absorbed phase state. Type C samples are characterized by low kerogen content, with trace oil found in the absorbed phase state. Nano-scale organic pores are well developed in the Q1 Formation. Oil is primarily found in the pore spaces with diameters less than 10 nm, this being the pore size threshold for mobile shale oil. When TOCo > 2.0 wt% and EOM >1.0 wt%, Q1 Formation shale oil mobility is high, resulting in prospective drilling targets.