Cretaceous Qingshankou Formation Research Articles

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.

Gulong shale oil enrichment mechanism and orderly distribution of conventional– unconventional oils in the Cretaceous Qingshankou Formation, Songliao Basin, NE China

Through the study of organic matter enrichment, hydrocarbon generation and accumulation process of black shale of the Cretaceous Qingshankou Formation in the Songliao Basin, the enrichment mechanism of Gulong shale oil and the distribution of conventional–unconventional oil are revealed. The Songliao Basin is a huge interior lake basin formed in the Early Cretaceous under the control of the subduction and retreat of the western Pacific plate and the massive horizontal displacement of the Tanlu Fault Zone in Northeast China. During the deposition of the Qingshankou Formation, strong terrestrial hydrological cycle led to the lake level rise of the ancient Songliao Basin and the input of a large amount of nutrients, resulting in planktonic bacteria and algae flourish. Intermittent seawater intrusion events promoted the formation of salinization stratification and anoxic environment in the lake, which were beneficial to the enrichment of organic matters. Biomarkers analysis confirms that the biogenic organic matter of planktonic bacteria and algae modified by microorganisms plays an important role in the formation of high-quality source rocks with high oil generation capability. There are four favorable conditions for the enrichment of light shale oil in the Qingshankou Formation of the Gulong Sag, Songliao Basin: the moderate organic matter abundance and high oil potential provide sufficient material basis for oil enrichment; high degree of thermal evolution makes shale oil have high GOR and good mobility; low hydrocarbon expulsion efficiency leads to a high content of retained hydrocarbons in the source rock; and the confinement effect of intra-layer cement in the high maturity stage induces the efficient accumulation of light shale oil. The restoration of hydrocarbon accumulation process suggests that liquid hydrocarbons generated in the early (low–medium maturity) stage of the Qingshankou Formation source rocks accumulated in placanticline and slope after long-distance secondary migration, forming high-quality conventional and tight oil reservoirs. Light oil generated in the late (medium–high maturity) stage accumulated in situ, forming about 15 billion tons of Gulong shale oil resources, which finally enabled the orderly distribution of conventional–unconventional oils that are contiguous horizontally and superposed vertically within the basin, showing a complete pattern of “whole petroleum system” with conventional oil, tight oil and shale oil in sequence.

Quantitative evaluation model of shale oil adsorption: A case study of the first member of Cretaceous Qingshankou Formation in northern Songliao Basin, NE China

A quantitative evaluation model that integrates kerogen adsorption and clay pore adsorption of shale oil was proposed, and the evaluation charts of adsorption-swelling capacity of kerogen (Mk) and adsorbed oil capacity of clay minerals (Mc) were established, taking the 1st member of Cretaceous Qingshankou Formation in the northern Songliao Basin as an example. The model and charts were derived from swelling oil experiments performed on naturally evolved kerogens and adsorbed oil experiments on clays (separated from shale core samples). They were constructed on the basis of clarifying the control law of kerogen maturity evolution on its adsorption-swelling capacity, and considering the effect of both the clay pore surface area that occupied by adsorbed oil and formation temperature. The results are obtained in four aspects: (1) For the Qing 1 Member shale, with the increase of maturity, Mk decreases. Given Ro of 0.83%–1.65%, Mk is about 50–250 mg/g. (2) The clay in shale adsorbs asphaltene. Mc is 0.63 mg/m2, and about 15% of the clay pore surface is occupied by adsorbed oil. (3) In the low to medium maturity stages, the shale oil adsorption is controlled by organic matter. When Ro>1.3%, the shale oil adsorption capacity is contributed by clay pores. (4) The oil adsorption capacity evaluated on the surface at room temperature is 8%–22% (avg. 15%) higher than that is held in the formations. The proposed evaluation model reveals the occurrence mechanisms of shale oils with different maturities, and provides a new insight for estimating the reserves of shale oil under formation temperature conditions.

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.

Whole petroleum system and hydrocarbon accumulation model in shallow and medium strata in northern Songliao Basin, NE China

Based on the oil and gas exploration practice in the Songliao Basin, combined with the latest exploration and development data such as seismic, well logging and geochemistry, the basic geological conditions, oil and gas types and distribution characteristics, reservoir-forming dynamics, source-reservoir relationship and hydrocarbon accumulation model of the whole petroleum system in shallow and medium strata in the northern part of Songliao Basin are systematically studied. The shallow–medium strata in northern Songliao Basin have the conditions for the formation of whole petroleum system, with sufficient oil and gas sources, diverse reservoir types and well-developed transport system, forming a whole petroleum system centered on the source rocks of the Cretaceous Qingshankou Formation. Different types of oil and gas resources in the whole petroleum system are correlated with each other in terms of depositional system, lithologic association and physical property changes, and they, to a certain extent, have created the spatial framework with orderly symbiosis of shallow–medium conventional oil reservoirs, tight oil reservoirs and shale oil reservoirs in northern Songliao Basin. Vertically, the resources are endowed as conventional oil above source, shale oil/tight oil within source, and tight oil below source. Horizontally, conventional oil, tight oil, interlayer-type shale oil, and pure shale-type shale oil are developed in an orderly way, from the margin of the basin to the center of the depression. Three hydrocarbon accumulation models are recognized for the whole petroleum system in northern Songliao Basin, namely, buoyancy-driven charging of conventional oil above source, retention of shale oil within source, and pressure differential-driven charging of tight oil below source.

Introducing Novel Correction Methods to Calculate Sedimentary Basin Overpressure and Its Application in Predicting Pressure Value and Origin

Overpressure is an important phenomenon observed in sedimentary basins. To enhance the precision of identifying the origin of overpressure and predicting it accurately, this paper presents four practical methods for analyzing formation overpressure, taking into account various factors, such as burial history, rock properties, mechanical models and data quality. By illustrating the application examples in typical basins, this paper demonstrates the practicality and potential of each model. Based on the analysis of organic matter content and denudation, our understanding of the origin of overpressure in the first member of the Cretaceous Qingshankou Formation in Songliao Basin has been revised. A novel model based on the static equilibrium equation was established, which not only demonstrates theoretical rationality but also exhibits practical advantages in the Junggar Basin and Southeast Hainan Basin. The incorporation of lateral loading in the correction model and the utilization of colored inversion in seismic velocity processing model have significantly enhanced pressure prediction accuracy in Junggar Basin and Southeast Hainan Basin, respectively. In conclusion, these correction models demonstrate a high level of reliability and possess significant potential for widespread adoption.

The role of water in the laboratory thermal advancement of immature type I kerogen from the Cretaceous Qingshankou Formation in China

To understand variations in geochemistry, organic petrology, and chemical composition of crude oil and byproducts, an immature sample from the Cretaceous Qingshankou Formation in the Songliao Basin, China, was analyzed by anhydrous and hydrous pyrolysis (AHP/HP) at a wide range of temperatures ranging from 300 °C to 450 °C. The geochemical parameters: TOC, S2, HI, and Tmax obtained from Rock–Eval pyrolysis showed both a decrease and an increase as thermal maturity progressed under HP and AHP conditions. Gas chromatography (GC) analysis showed the presence of n-alkanes in the C14 to C36 range in both expelled and residual byproducts, a Delta-shaped configuration although many samples had a gradually reducing (tapering) trend toward the high range. Gas chromatography-mass spectrometry (GC–MS) analysis revealed both an increase and a decrease in biomarker and very small changes in aromatic compound variations with increasing temperature during pyrolysis. To be more specific, C29Ts biomarker increased with temperature for the expelled byproduct, while the opposite trend was observed for the residual one. Next, The Ts/Tm ratio initially increased and then decreased with temperature while the C29H/C30H ratio fluctuated for the expelled byproduct but increased for the residual. Moreover, the GI and C30 rearranged hopane to C30 hopane ratio remained unchanged whereas the C23 tricyclic terpane/C24 tetracyclic terpane ratio and the C23/C24 tricyclic terpane ratio showed varying trends with maturity alike the C19/C23 and C20/C23 tricyclic terpane. Ultimately, based on organic petrography observations, increasing the temperature resulted in higher bitumen reflectance (%Bro, r) and optical and structural alterations in the macerals. The findings of this study provide valuable insights for future exploration endeavors in the studied region. Moreover, they contribute to our understanding of the significant role of water in the generation and expulsion of petroleum and associated byproducts, thereby facilitating the development of updated models in this field.

Controlling factors for oil production in continental shales: A case study of Cretaceous Qingshankou Formation in Songliao Basin

Continental shale oil is widely distributed in the Cretaceous Qingshankou Formation of the Songliao Basin in Northeast China. In the Qijia-Gulong sag and the Changling sag in the Songliao Basin, breakthroughs of shale oil exploration and development have been made in the first and second members of the Qingshankou Formation, and several wells represented by Well GYYP1 have achieved high and stable shale oil production. However, some horizontal wells in shale oil development pilot test (Well groups A and D) were characterized by low shale oil production, high flowback rate and rapid production decline. Therefore, controlling factors of the shale oil production were investigated. The results show that shale oil enrichment area and optimal sweet spots are fundamental for high shale oil production, improving horizontal length and drilling ratio of sweet spots is a technical guarantee for enhancing shale oil production of single well, and artificial fracture network (incl. scale, complexity, and coupling with pre-existing geological bodies) created by fracturing is a direct factor for controlling the shale oil production. For subsequent exploration and development of the shale oil, the heterogeneity of sweet spot distribution should be carefully considered, the shale oil enrichment areas and optimal sweet spots also need be optimized, and the wellbore trajectory control and fine geological modeling techniques should be figured out. Moreover, the fracturing techniques suitable for the shale with high clay mineral content and weak brittleness should be developed, and the personalized and differentiated staged fracturing also needs to be performed, to effectively enhance single-well shale oil production and estimated ultimate recovery.

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.

Rock Fabric of Lacustrine Shale and Its Influence on Residual Oil Distribution in the Upper Cretaceous Qingshankou Formation, Songliao Basin

Rock Fabric of Lacustrine Shale and Its Influence on Residual Oil Distribution in the Upper Cretaceous Qingshankou Formation, Songliao Basin

Prediction of lamina structure and reservoir quality in shale using well logs: The Cretaceous Qingshankou Formation, Gulong Sag, Songliao Basin, China

Lamina structure is determined by composition, thickness, continuity, and mineral assemblage. Reservoir quality in oil shale reservoirs is determined by lamina structure, which controls hydrocarbon accumulation and migration. The prediction and evaluation of multi-scale lamina structures using geophysical well logs is challenging. Recent studies demonstrate that the lamina structure classification may be based on core observation and core analysis. However, there are no corresponding high-resolution geophysical logging methods to identify and categorize lamina structure continuously in a single well. Here, an experimental approach, involving an integrated analysis of cores, thin sections, well logs such as slabs and button conductivity curves of image logs (up to 5 mm vertical resolution), is used to characterize lamina structure. T1-T2 (T1, longitudinal relaxation time, and T2, transverse relaxation time) maps of nuclear magnetic resonance (NMR) logs are applied to clarify the relationships between the lamina structure, reservoir quality, and oil-bearing properties. Results demonstrate how lamina structure in shale can be divided into three types: laminated rocks, layered rocks, and massive rocks, according to observation of core at the lamina scale. The thickness of individual lamina is less than 0.01 m in the laminated rocks, and the layered rocks have bundles of genetically related laminae thickness ranging between 0.01 m and 0.1 m. In massive rocks there is no visible layering. The well log response patterns of the three types of lamina structure are established so that the distribution of lamina structure can be predicted in a single well via well logs. Results show that the oil-bearing shale intervals are dominated by laminated rocks and layered rocks, accounting for 90% of the studied Qingshankou Formation. In addition, the layered rocks play an important role in improving reservoir quality and the laminated rocks present moderate reservoir quality. The massive rocks show poor reservoir quality. Moreover, an increased proportion of felsic mineral content favors increased oil potential in oil shale reservoirs. The method is generally applicable and is of value in developing predictive indicators of subsurface reservoir sweet spots in shale oil and gas exploration and development.

Insights into Salt Ion Diffusion Behavior in Imbibed Fluids and the Source of Salt Ions in Clay-Rich Shale from Upper Cretaceous Qingshankou Formation, Songliao Basin

Insights into Salt Ion Diffusion Behavior in Imbibed Fluids and the Source of Salt Ions in Clay-Rich Shale from Upper Cretaceous Qingshankou Formation, Songliao Basin

Geochemistry and petrology of petroleum source rocks in the Upper Cretaceous Qingshankou Formation, Songliao Basin, NE China

The Upper Cretaceous Qingshankou Formation in the Songliao Basin, NE China is known to contain excellent petroleum source rocks. In addition, it serves as a valuable record to study depositional conditions within the water column and climatic change. In this study, a large set of organic petrography, major and trace element geochemistry, as well as bulk and molecular organic geochemistry data obtained on 38 core samples of the first Member of the Qingshankou Formation (K2qn1) in the south central depression is reported. All rocks are thermally oil-mature, reaching the early to peak oil generation stage, indicated by the vitrinite reflectance (VRr) of approximately 0.8%. Two different types of lacustrine source rocks (units I and II) and two OM-rich layers within unit I are identified in the studied well. Basically, there is a lower unit 1, characterized by lower total organic carbon (TOC) content and an upper unit 2 characterized by higher TOC content. Furthermore, within unit 1, thin marine transgressive layers of approximately 1–2 m were identified. Generally, unit 1 is characterized by the lowest TOC and sulfur contents with average values of 1.31 wt% and 0.56 wt%, respectively. By contrast, unit 2 samples have significantly higher TOC (avg. 2.39 wt%) and sulfur contents (avg. 1.24 wt%). Samples, which represent the postulated marine transgressive events show the highest TOC (avg. 2.82 wt%) and sulfur contents (avg. 2.01 wt%). Unit 1 was mainly deposited in oxic-dysoxic and freshwater-brackish water column conditions based on multiple organic and inorganic geochemical proxies. By contrast, unit 2 and marine transgressive layers were deposited in less oxygenated and more saline environments. Source rocks from the K2qn1 generally show only minor terrestrial organic matter input. However, unit 1, containing type II-III kerogen, shows indications for a slightly more pronounced contribution from terrigenous higher plants than unit 2 and the marine transgressive layers, where the kerogen is almost exclusively derived from planktonic/algal and microbial organic matter. The low TOC content in unit 1 is attributed to multiple adverse factors for organic matter accumulation, including a relatively shallow, oxic-dysoxic, and weakly stratified water column and high dilution by terrigenous mineral matter. By contrast, more favorable conditions persisted during the deposition of marine transgressive layers and unit 2, e.g., a more reducing and stratified water column and lower dilution by terrigenous mineral matter.

Controlling effect of pore-throat structures on tight oil accumulation effectiveness in the upper Cretaceous Qingshankou formation, Songliao Basin

The Gaotaizi reservoir in the Qingshankou Formation, northern Songliao Basin is one of the most potential tight oil targets in China and it is underlain directly by the OM-rich shales of the Qingshankou Formation. Previous studies indicated a strong oil-bearing heterogeneity in the Gaotaizi reservoir, while the relationship between pore-throat system and oil-bearing property is poorly understood. Thin section, Soxhlet extraction, MICP, fluid inclusion PVTX simulation and basin modelling were combined to investigate the pore-throat structure, and its effect on oil-bearing abundance and the tight oil accumulation effectiveness. Three pore-throat structures in the Gaotaizi reservoir were identified. The pore-throat size distribution (PSD), pore-throat configuration, and the corresponding physical properties became worser from Type I to Type III, as well as the pore types. A close relationship between pore-throat structures and sedimentary facies was established. Type I and II were dominated in mouth bar sand, while Type II, and Type III were mainly distributed in distal sandbars and sheet sand, respectively. The fluid properties and oil-bearing grades in the Gaotaizi tight sandstones were significantly controlled by the pore-throat structures. There were few fluids produced from the tight sandstones with Type III pore-throat structures, whose pore-throat size was almost half of that in tight sandstones with oil production. The dynamic model and ratio of pore containing oil (RPO) parameter were proposed. The residual pressure difference between the source rock and reservoir was 4.1 MPa, and the corresponding lower limit of pore-throat radius for tight oil accumulation was around 180 nm considering the limited buoyancy. Under the same driving force, the RPO of the Type I, II, III pore-throat structure reservoir was 74.4%, 58.0%, 23.3%, respectively, caused by pore-throat structure differences. It shows that an optimal tight oil “sweet spot” formed in the Type I reservoir, and favourable tight oil zones typically developed in the Type II reservoir, whereas only poor tight oil or dry zones developed in the Type III reservoir. This research improves the understanding of continental tight oil enrichment mechanism and provides a reference for optimizing favourable area of tight oil exploration.

Lithofacies and Shale Oil Potential of Fine-Grained Sedimentary Rocks in Lacustrine Basin (Upper Cretaceous Qingshankou Formation, Songliao Basin, Northeast China)

Shale oil has become a global hotspot of unconventional exploration and development. In this study, the latest drill core and experiment analyses of the Qingshankou Formation in the northern Songliao Basin were used to evaluate its lithofacies classification, sedimentary environment, pore types, pore-throat structure characterization, and shale oil potential. Lithofacies classification was determined according to the total organic carbon (TOC) content, sedimentary structure, and rock mineral content. Laminae genesis and micro-sedimentary structures indicate the deposition of fine-grained sedimentary rocks (FGSRs) in a semi-deep to deep lacustrine environment; however, evidence also suggests partial reworking by storm events and bottom current flows. FGSRs mostly comprise type I kerogen, with small amounts of type II1. The average vitrinite reflectance of the FGSRs was 1.37%, indicating middle to high stages of thermal maturation within the oil generation window. The N2 adsorption experiment indicated that silty mudstone (SM), silty fine mixed sedimentary rock (SFMR), and argillaceous fine mixed sedimentary rock (AFMR) had ink-bottle-shaped and slit-shaped pores, and the lithofacies were dominated by mesopores, accounting for 77.4%, 71.9%, and 80.8% of the total pore volume, respectively. Mercury injection capillary pressure analysis indicated that SM and SFMR had an average pore-throat radius of 0.01–0.04 μm, whereas AFMR and CM were dominated by nanopores, mainly distributed in the range of 0.004–0.0063 μm. Based on the comprehensive studies of TOC content, pore development, and brittleness, we concluded that organic-rich laminated SM and SFMR should be the focus of shale oil exploration of the Qingshankou Formation in the northern Songliao Basin, followed by organic-rich or organic-moderate laminated and layered AFMR, as well as calcareous fine mixed sedimentary rocks.

Study on the Delineation of Small Layers and Depositional Micro-Phases in the Qing San Section of the Gaotaizi Formation in Qian'an Oilfield Block 130

The fine isochronous comparison and fine portrayal of sedimentary micro-phases for the stratigraphy of Qian130 block in Qian'an oilfield is a critical problem that needs to be solved in the field nowadays. The target section of the study is the XII Sand Formation in Section III of the Upper Cretaceous Qingshankou Formation, and the oil-bearing formation is the Gaotaizi Oil Formation. Based on field outcrops, cores, logs and other data, a comparative stratigraphic framework of small stratigraphic levels was established and single well phases, continuous well profiles and planar sedimentary phases were studied for the deltaic foreland depositional system of the three sections of the Qingshankou Formation in the Qian'an Oilfield, guided by stratigraphic stratigraphy theory[1-2]. The analysis concludes that the regional structure is located in the northern part of the Changling Depression in the central depressional area of the southern part of the Songliao Basin, where faults are developed. The three sedimentary microphases of the Qingshankou Formation include six microphases: submerged divergent channel, estuarine dam, submerged divergent channel flank, submerged divergent interbay, distant sand dam, and matted sand. Combining the sedimentary micro-phase map of the small layer time unit with the oil formation sandstone thickness map, sand-to-ground ratio map and effective thickness map of the oil formation, the oil and water distribution in the study area is correctly understood to guide the next development of the Qian'an oil field[3-4].

Calculation of oil saturation in clay-rich shale reservoirs: A case study of Qing 1 Member of Cretaceous Qingshankou Formation in Gulong Sag, Songliao Basin, NE China

The targeted reservoir, which is referred as the first member of Cretaceous Qingshankou Formation in Gulong Sag, Songliao Basin, NE China, is characterized by the enrichment of clay and lamellation fractures. Aiming at the technical challenge of determining oil saturation of such reservoir, nano-pores were accurately described and located through focused ion beam scanning electron microscopy and quantitative evaluation of minerals by scanning electron microscopy based on Simandoux model, to construct a 4D digital core frame. Electrical parameters of the shale reservoir were determined by finite element simulation, and the oil saturation calculation method suitable for shale was proposed. Comparison between the results from this method with that from real core test and 2D nuclear magnetic log shows that the absolute errors meet the requirements of the current reserve specification in China for clay-rich shale reservoir. Comparison analysis of multiple wells shows that the oil saturation values calculated by this method of several points vertically in single wells and multiple wells on the plane are in agreement with the test results of core samples and the regional deposition pattern, proving the accuracy and applicability of the method model.

Influencing factors and significance of organic and inorganic nitrogen isotopic compositions in lacustrine sedimentary rocks

Comprehensive nitrogen biogeochemical cycle has been reconstructed for representative lacustrine organic-rich sedimentary rock in China, namely the Triassic Yanchang Formation (YF, 199–230 Ma) in Ordos and the Cretaceous Qingshankou Formation (QF, 86–92 Ma) in Songliao basins, by evaluating the organic and inorganic nitrogen isotopic compositions rather than only organic or bulk nitrogen isotopic compositions. The results indicate that the nitrogen isotope values of bulk rock (δ15Nbulk) in the non-metamorphic stage are significantly different from that of kerogen, which challenge the conceptual framework of sedimentary nitrogen isotope interpretation. The δ15Nbulk from the YF and QF were lower than their respective the nitrogen isotope values of kerogen (δ15Nker), with offsets up to ∼5.1‰, which have the inverse relationship for the metamorphosed rock. Thermal evolution did not significantly modify the δ15N of bulk rock and kerogen. The δ15N of sediments from the YF (δ15Nbulk, 1.6‰–5.6‰) were lower than that of rock from the QF (δ15Nbulk, 10.2‰–15.3‰). The nitrogen isotope values of silicate incorporated nitrogen (δ15Nsil) were slightly lower than those of the δ15Nker in the YF and obviously lower for the QF. The fact that different nitrogen cycles occur in the YF and QF due to the different depositional redox conditions leads to different isotopic results. The YF water environment dominated by oxic conditions is not conducive to the occurrence of denitrification and anammox, and no abundant N2 loss leads to the relatively light δ15Nbulk. In the stratified water for the QF, redox transition zone promotes denitrification and anammox, resulting in the heavy δ15Nbulk of rock and promotes the DNRA, resulting in heavy δ15Nker and low δ15Nsil.

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.