Oil Formation Research Articles

Novel hydrogen-bonded organic frameworks-based coating for fat oil and grease deposition control in the sewer system

Hydrogen-bonded organic frameworks (HOFs) represent an emerging class of porous materials characterized by crystalline frame structures, self-assembled from organic molecules through hydrogen bonding. This study demonstrates that HOFs fragment into small particles while preserving their original structure when dispersed in a polymeric epoxy solution. The intermolecular hydrogen bond structural and electronic properties of the LH4-HOF complex as well as the mechanism of HOF incorporated epoxy were extensively studied using density functional theory. LH4-HOF has a high Langmuir surface area of 2758.3 m2/g and nonlocal density functional theory pore size distributions of 3 A°. This unique solution processability enables the fabrication of coatings with high stability in aqueous systems. Results from a 30-day leaching test under controlled conditions (pH 7, temperature 20 ± 2 °C) indicate that LH4-HOF incorporated epoxy-coated concrete samples exhibited an over 85 % reduction in calcium release compared to uncoated samples, with epoxy-coated samples alone showing a 60 % reduction in calcium leaching. Additionally, the LH4-HOF-incorporated epoxy coating reduced the formation of fats, oils and grease deposits by more than 73 % on the concrete samples. Thus, this novel coating approach offers a sustainable solution with significant potential applications in sewer management.

Selective catalytic conversion of model olefin and diolefin compounds of waste plastic pyrolysis oil: Insights for light olefin production and coke minimization

The primary challenges in ex-situ catalytic pyrolysis of plastic waste to produce light olefins lie in the selective conversion of larger olefins and diolefins downstream of the pyrolyzer. Hence, the catalytic cracking mechanism of plastic pyrolysis oil was explored using an α-olefin (1-decene) and a diolefin (1,9-decadiene) model compounds over an HZSM-5 zeolite-based catalyst in a fixed-bed reactor. Key objectives were to elucidate the reaction pathways for light olefin production, aromatization, and coke formation in catalytic cracking of larger olefins and diolefins. The investigation explored the impact of HZSM-5 steam treatment severity, contact time (∼58–226 ms), and reaction temperature (250–450 °C) on product yields. The severity of steam treatment was found to increase the 1-decene isomerization rate while decreasing the cracking rate and conversion of 1-decene to C3-4 light olefins. In the catalytic cracking of 1-decene, major product types included olefins (linear and nonlinear) and a few naphthenes, while in the case of 1,9-decadiene catalytic cracking, non-linear olefins were absent, with abundant naphthenes followed by lighter diolefins and C3-5 linear olefins. Temperature and contact time variations revealed that the catalytic cracking of 1-decene initiated with double bond rearrangement isomerization, progressing to skeletal isomerization, and intensified cracking reactions producing light C3-4 olefins. Conversely, in the catalytic cracking of 1,9-decadiene, cyclization was the primary reaction pathway, followed by β-scission, resulting in lighter conjugated dienes and light linear olefins. Thermal gravimetric analysis (TGA) of spent catalysts confirmed a higher coke amount generated during 1,9-decadiene cracking compared to 1-decene cracking, indicating that diene compounds serve as precursors for significant coke formation in plastic pyrolysis oil. These insights provide valuable understanding for catalytic upgrading of pyrolysis oil from polyolefin pyrolysis.

Comparative Study on Artificial Fracture Modeling Schemes in Tight Reservoirs—For Enhancing the Production Efficiency of Tight Oil and Gas

In order to improve the reliability of the deployment of production schemes after artificial fracturing in tight reservoirs, it is urgent to carry out research on the description of fractures after artificial fracturing. In this study, taking the Chang 61 oil formation group in the Wangyao South area of Ordos Basin as an example, three different fracture modeling schemes are used to establish the geological model of fractured reservoirs, and the fitting ratios of the respective reservoir models are calculated by using the method of reservoir numerical simulation of the initial fitting, and the optimal fractured reservoir modeling scheme is screened in the end. The research area adopts three types of fracture prediction results based on FMI fracture interpretation data, seismic fracture prediction data, and rock mechanics artificial fracturing simulation data. On this basis, geological models of fractured reservoirs are established, respectively. The initial fitting of reservoir values of each geological model are compared, and the highest initial fitting rate of reservoir values is 88.44%, which is based on rock mechanics artificial fracturing simulation data. However, the initial fitting rate of the reservoir model was the lowest at 75.76%, which was established based on the fracture random modeling results of FMl fracture interpretation data. Under the constraints of seismic geostress prediction results and microseismic monitoring data, the simulation results of rock mechanics artificial fracturing fracture are used as the basis, on which the geological model of artificially fractured reservoirs is thus established, and this scheme can more realistically characterize the characteristics of fractured reservoirs after artificial fracturing in the study area.

Molecular and carbon isotopic geochemistry of oils with different fluorescence color from the Upper Jurassic Qigu formation and oil accumulation process in Yongjin area, Junggar Basin in China

The Yongjin area, located in the middle of the Junggar Basin, is an important oil-producing region. Its major oil-producing formation is the Upper Jurassic Qigu Formation, which has experienced multiple oil-charging events that have resulted in oils with various fluorescent colors. However, the source of oils from the Qigu Formation is currently debated. As exploration and development progressed, the productivity of the Qigu Formation was observed to vary owing to oil viscosity differences. Conventional extraction methods can only be used to obtain a mixture of fluorescing oils of different colors, making it difficult to analyze the properties of oils that charge during different periods. Using microscopy to observe fluorescence the characteristics of oil in various samples were analyzed. Then, accelerated sequential extraction was used to separate the oils with different fluorescent colors (Groups I–IV). Through GC-MS (gas chromatography), GC-IRMS (gas chromatography-mass spectrometry), FT-IR (fourier transform infrared spectroscopy), and fluid inclusion observations and measurements, in conjunction with the geological context, the sources of oils from different charge periods and genesis of heavy oil were determined and the process of oil accumulation was reconstructed. Three stages of oil charging were identified: (1) During the Middle to Late Jurassic, low-mature and mature oil from the Lower Permian Fengcheng Formation and a low quantity of low-mature oil from the Middle Permian Lower Wuerhe Formation charged the Qigu Formation. These oils underwent notable biodegradation and oxidation, with some captured by inclusions (Group III) for preservation. (2) During the Late Cretaceous to Early Paleogene, mature oil from the Wuerhe Formation charged the Qigu Formation. This oil mixed with early oil that was not captured by the inclusions, resulting in the formation of black-brown fluorescing oil (Group IV) and yellow fluorescing inclusion oil (Group II). (3) From the Late Paleogene to the present, highly mature condensates from the Lower Wuerhe Formation charged the Qigu Formation. The oil mixed with early oil to generate yellow-brown (Group II) and blue-white (Group I) fluorescing oils. Low-mature and mature oil from the Fengcheng Formation charged the Jurassic reservoirs and underwent secondary alteration, whereas high-mature oil and gas did not. These oils likely predominantly accumulated in reservoirs between the Fengcheng and Lower Wuerhe formations. Although the Jurassic source rocks began to generate oil, this oil did not migrate upward to the Qigu Formation, indicating that the conventional and unconventional reservoirs under the Jurassic Qigu Formation have exploration potential.

Study of the effect of ultrasonic technology on the extraction of bitumen from bituminous rocks

Background: Nowadays, there are few studies focused on the extraction of targeted products from bituminous rocks. Published research on the on the use of ultrasound for bitumen extraction refers to unconventional technologies. A distinctive feature of the bituminous rocks under study is their exposure at the surface, where they are situated in open areas. Due to various technogenic factors and prolonged atmospheric, light fractions are lost, while the heavier components undergo oxidation. These processes lead to the formation of heavy oils and hard bitumens with complex composition. Aim: To study the effect of ultrasonic technology on the bitumen extraction of from bituminous rocks and to determine the physical and chemical properties of the product obtained. Materials and methods: Thу ultrasonic method has many benefits, in particular energy and water savings, high productivity within a short period of time, and possibility of organizing a mobile unit installation at the production site. The main process parameters includes the determination of the required frequency and power depending on the object of ultrasound technology research. The results of the work have demonstrated that ultrasonic cavitation of bituminous rocks in an alkaline medium increases the degree of bitumen extraction. Results: The physical and chemical properties of bitumen obtained as a result of studying the effect of ultrasonic technology on bitumen extraction from oil-bituminous rocks were determined. Conclusion: The study identified the optimal process parameters based on the specific research object. When selecting the ultrasonic power it was found that clay compounds of bituminous rocks have a direct effect on the extraction of natural bitumen. It was demonstrated that ultrasound technology is a promising and industrially applicable technology for extracting bitumen from the bituminous rocks of the Munaily Mola field.

The Formation Mechanism of Residual Oil and Methods of Enhanced Oil Recovery in a Fractured Low-Permeability Metamorphic Rock Reservoir in Bohai Bay

The oil reservoirs of the metamorphic rocks in Bohai Bay have geological characteristics such as low matrix porosity and permeability, developed natural microfractures, which result in the injection water rapidly advancing along fractures, a fast increase in the water content, and difficulties in extracting the remaining oil. In order to reveal water channeling and the residual oil formation mechanisms in fractured low-permeability reservoirs and solve the water channeling problem, we first analyzed the reservoir development status, then studied the formation mechanism of residual oil using a microfluidic chip device, and formed a method of hierarchical control to effectively control the water channeling problem of fractured reservoirs and maximize the displacement of residual oil. The results show that (1) Due to the low permeability of the reservoir matrix, a large amount of injected water flows along the fracture channel, which leads to the long-term high water cut of some oil wells and the retention of a large amount of crude oil in the matrix. (2) The results of microfluidic experiments show that the distribution of residual oil after water flooding mainly includes five types: blind end of the pore throat, columnar, cluster, flake and film, and residual oil. Among them, sheet-like and clustered residual oil are dominant, accounting for 75~85% and 10~13%, respectively. (3) Based on the characteristics of fracture development in buried-hill reservoirs, a hierarchical control technology of “gel particle + liquid crosslinked gel system” is established. The field application effect predicted that the input–output ratio was 1:3. This study provides a reference for the comprehensive treatment of water channeling in the same type of offshore fractured low-permeability metamorphic rock reservoirs.

Characteristics and Origin of Natural Gas in Yongfeng Sub-Sag of Bogda Mountain Front Belt

By systematically analyzing the natural gas composition, carbon isotopes, and source rock characteristics in the Yongfeng sub-sag of the Bogda Mountain front belt, natural gas characteristics were determined, and the genetic types and sources of natural gas were investigated. The research results indicate that methane is the main component of natural gas in the Yongfeng sub-sag, with low levels of heavy hydrocarbons and a high drying coefficient. These characteristics make it dry gas, which refers to natural gas with a methane content of over 95%. The ethane carbon isotope δ13C2 of natural gas is −28.5‰ and belongs to oil type gas. The methane carbon isotope δ13C1 of natural gas is −58.6‰~−59.4‰, has a relatively depleted methane carbon isotope value, shows significant differences from the surrounding natural gas methane carbon isotope, and belongs to the category of biogenic gas. The Permian Lucaogou Formation is the main source rock in the study area, with good organic matter abundance. The microscopic components of kerogen are mainly composed of sapropelic formations and the organic matter type is I–II1. The source rock has a high maturity and has reached the mature stage, mainly consisting of oil and wet gas. The ethane carbon isotope of natural gas in the Yongfeng sub-sag shows as oil type gas, which is consistent with the kerogen type of the Lucaogou Formation source rocks, indicating that the natural gas mainly comes from the Lucaogou Formation source rocks. Based on comprehensive data and information on natural gas composition, carbon isotopes, and burial history of the source rocks, it is believed that some of the crude oil generated from the Lucaogou Formation in the early stage underwent biodegradation due to tectonic uplift, resulting in biogenic methane and the formation of crude oil biodegraded gas.

Examining the factors that impact the formation of barite scale in water injection operations: experimental study and quantification of scale formation

Barium sulfate (BaSO4) scale formation in oilfield operations is a significant problem that leads to severe operational challenges, including reduced production efficiency and increased maintenance costs. Understanding the factors that influence BaSO4 scale formation, such as injection rate and temperature, is crucial for developing effective mitigation strategies. In this study, we systematically investigated the effects of injection rate and temperature on BaSO4 scale formation using a series of controlled laboratory experiments. The injection rates varied between 1 and 5 mL/min and temperatures between 25 and 75 °C, simulating realistic field conditions. Our findings indicate that higher injection rates and elevated temperatures significantly increase the amount of BaSO4 scale formed. Specifically, the scale formation increased from 15.2 mg/L at 1 mL/min and 25 °C to 22.3 mg/L at 5 mL/min and the same temperature. Similarly, at a constant injection rate of 3 mL/min, the scale formation increased from 18.1 mg/L at 25 °C to 26.5 mg/L at 75 °C. The study employed Scanning Electron Microscopy (SEM) and X-ray Diffraction (XRD) to analyze the crystal morphology and structure of the formed scales. SEM images revealed a transition from dendritic structures at lower temperatures and slower injection rates to spherical crystals at higher temperatures and faster injection rates. XRD patterns indicated variations in crystallinity and phase purity corresponding to the experimental conditions. Our results align with previous studies that report increased nucleation rates and reduced solubility of BaSO4 at higher temperatures and injection rates. These findings highlight the critical role of controlling operational parameters to mitigate scale formation in oil and gas operations. By optimizing injection rates and temperatures, it is possible to reduce scale deposition, thereby improving production efficiency and reducing maintenance costs. This study provides valuable insights for the development of scale management strategies and underscores the importance of a comprehensive understanding of the physicochemical factors affecting BaSO4 scale formation.

Exploration breakthrough and factors for enrichment and high-yield of hydrocarbons in ultra-deep clastic rocks in Linhe Depression, Hetao Basin, NW China

Based on drilling and logging data, as well as geological experiments, the geological characteristics and factors controlling high-yield and enrichment of hydrocarbons in ultra-deep clastic rocks in the Linhe Depression, Hetao Basin, are studied. The results are obtained in four aspects. First, the inland saline lacustrine high-quality source rocks developed in the Paleogene in the Linhe Depression have the characteristics of early maturity, early expulsion, high hydrocarbon yield, and continuous and efficient hydrocarbon generation, providing an important resource basis for the formation of ultra-high pressure and high-yield reservoirs. Second, the weak compaction, early charging, and weak cementation for pore-preserving, together with the ultra-high pressure for pore-preserving and fracture expansion to improve the permeability, leads to the development of high-quality reservoirs with medium porosity (greater than 15%) and medium permeability (up to 226×10−3 μm2) in the ultra-deep strata (deeper than 6 500 m), which represents a greatly expanded space for oil and gas exploration. Third, the Linhe Formation adjacent to the trough exhibits a low net-to-gross (NTG) and good reservoir-caprock assemblage, and it is overlaid by very thick high-quality mudstone caprock, which are conducive to the continuous and efficient hydrocarbon generation and pressurization and the formation of ultra-high pressure oil and gas reservoirs. Fourth, the most favorable targets for ultra-deep exploration are the zones adjacent to the hydrocarbon generating center of the Paleogene Linhe Formation and with good tectonic setting and structural traps, mainly including the Xinglong faulted structural zone and the Nalinhu faulted buried-hill zone. The significant breakthrough of ultra-deep oil and gas exploration in the Linhe Depression reveals the good potential of ultra-deep clastic rocks in this area, and provides valuable reference for oil and gas exploration of ultra-deep clastic rocks in other areas.

The Synergic Effect of Brine Salinity and Dispersed Clay Particles on Water-in-Heavy Oil Emulsion: Insight into Asphaltene Structure and Emulsion Stability

Summary The research on enhancing oil recovery in sandstone reservoirs through low-salinity waterflooding (LSWF) has been well-documented, while there have been few studies conducted on the impact of emulsion formation in heavy oil due to the incompatibility between the injected brine, clay particles, and heavy oil components. In this study, we explored the synergic role of asphaltene and clay in the process of LSWF by introducing an innovative and thorough experimental approach. Our findings presented new insights into how LSWF in clay-rich sandstone reservoirs can influence the behavior and properties of the water-in-heavy oil emulsions. In this regard, we contacted the heavy oil and brine (with and without clay) for 20 days at 90°C. Then, the emulsion was centrifuged to separate the oil and brine phases. The oil phase was examined by conducting the viscosity, interfacial tension (IFT), Fourier transform infrared spectroscopy (FTIR), and asphaltene onset point (AOP) precipitation experiments. Significant decreases in viscosity and asphaltene precipitation values were observed when crude oil was exposed to clay solutions, as indicated by viscosity and IP-143 results. Furthermore, the zeta potential of clay particles suspended in various brines was determined to assess the electrostatic aspects of rock-oil interactions. The analysis of the emulsion phase indicated that the emulsion stability in the presence of clay increased because of the improvement of asphaltene contribution in the interface. This trend aligns with the zeta potential measurement results. In addition, after examining the pH and conductivity of aged brine in the presence and absence of clay, it was observed that the clay caused the release of hydrogen ions in the brine and then bonded with the dissolved cations, leading to improvement in the emulsion stability. Ultimately, the asphaltene molecular structure was compared via scanning electron microscopy (SEM) and attenuated total reflection analysis before contact with the brine and after separation from the emulsion phase. The results indicated a decrease in the concentration of aliphatic groups in the molecular structure of the remaining asphaltene following the aging of the oil bulk. These new findings can potentially mitigate unwanted emulsion damage in the LSWF in heavy oil recovery.

Development Characteristics of Single Sand Body of Yan’An Formation in Western Ordos Basin

Abstract The precise characterization of the types and spatial distribution of strongly heterogeneous single sand bodies are a necessary prerequisite for the study of oil and gas reservoir formation. This article takes the Yan’an Formation in the western Ordos Basin as an example to systematically study the internal structure and profile distribution of strongly heterogeneous single sand bodies. The research results indicate that using mud interlayers, physical interlayers, and calcium interlayers as layered interfaces can effectively classify the single sand body types of each small layer in the Yan’an Formation. The drilling rate of a single sand body is between 50% and 85%, and the average number of sand layers is between 3 and 8. When two rivers intersect and are horizontally tangent, due to the mutual erosion of water flow, relatively thick sand bodies can be retained, ultimately resulting in a pattern of relatively thick on both sides and thin in the middle. The single sand body at the bottom is the most developed and has good continuity. In the transverse direction of the river, the continuity of a single sand body is relatively poor, and the extension range of a single sand body is 300m to 1200m. Along the river channel, single sand bodies are developed with good continuity, extending about 2km. The connectivity between the sand body and the well varies with the migration of the river in the transverse river profile of the research area. The lateral contact relationship of a single sand body determines the boundary of the river channel, and the profile characteristics of a single sand body also reflect its planar distribution. The intergranular pores of the Yan’an Formation sand body are relatively developed, and a large number of quartz particles offset the compressive stress of the rock. The corrosion of feldspar particles is relatively strong, retaining a large number of primary intergranular pores. There is a good quantitative relationship between the thickness of sand in a single level channel and the width of the channel. The control of the well network on the sand body is relatively small, and there is room for further densification of drilling. The vertical contact relationship of a single sand body in the Yan’an Formation of the research area can be divided into three modes: separation, stacking, and overlapping. Cut pile sand bodies with good connectivity have good production capacity. The different planar contact relationships reflect the degree of connectivity between channel sand bodies and wells, with lateral cutting type>docking type>isolation type. The side cut sand body has uniform longitudinal water absorption, small water absorption difference, and high-water drive degree. The isolation type has the greatest difference in water absorption rate and the lowest degree of water flooding.

Genetic mechanism and petroleum geological significance of calcite veins in organic-rich shales of lacustrine basin: A case study of Cretaceous Qingshankou Formation in Songliao Basin, China

Based on the observation and analysis of cores and thin sections, and combined with cathodoluminescence, laser Raman, fluid inclusions, and in-situ LA-ICP-MS U-Pb dating, the genetic mechanism and petroleum geological significance of calcite veins in shales of the Cretaceous Qingshankou Formation in the Songliao Basin were investigated. Macroscopically, the calcite veins are bedding parallel, and show lenticular, S-shaped, cone-in-cone and pinnate structures. Microscopically, they can be divided into syntaxial blocky or columnar calcite veins and antitaxial fibrous calcite veins. The aqueous fluid inclusions in blocky calcite veins have a homogenization temperature of 132.5–145.1 °C, the in-situ U-Pb dating age of blocky calcite veins is (69.9±5.2) Ma, suggesting that the middle maturity period of source rocks and the conventional oil formation period in the Qingshankou Formation are the sedimentary period of Mingshui Formation in Late Cretaceous. The aqueous fluid inclusions in fibrous calcite veins with the homogenization temperature of 141.2–157.4 °C, yields the U-Pb age of (44.7±6.9) Ma, indicating that the middle-high maturity period of source rocks and the Gulong shale oil formation period in the Qingshankou Formation are the sedimentary period of Paleocene Yi'an Formaiton. The syntaxial blocky or columnar calcite veins were formed sensitively to the diagenetic evolution and hydrocarbon generation, mainly in three stages (fracture opening, vein-forming fluid filling, and vein growth). Tectonic extrusion activities and fluid overpressure are induction factors for the formation of fractures, and vein-forming fluid flows mainly as diffusion in a short distance. These veins generally follow a competitive growth mode. The antitaxial fibrous calcite veins were formed under the driving of the force of crystallization in a non-competitive growth environment. It is considered that the calcite veins in organic-rich shale of the Qingshankou Formation in the study area has important implications for local tectonic activities, fluid overpressure, hydrocarbon generation and expulsion, and diagenesis-hydrocarbon accumulation dating of the Songliao Basin.

Morphometric Approach to Quantitative Assessment of Thickness of Sediments Meandering Paleochannels of the Tyumen Formation of the West Siberian Oil and Gas Basin

Morphometric Approach to Quantitative Assessment of Thickness of Sediments Meandering Paleochannels of the Tyumen Formation of the West Siberian Oil and Gas Basin

Sedimentary Reservoir Characteristics of Fuyu Oil Formation in the Middle of Fuxin Uplift, Southern Songliao Basin

Currently, the Fuyu reservoir in the middle of the Fuxin uplift, located in the southern Songliao Basin, is in a high water cut development stage. The understanding of this reservoir is limited, and the distribution of favorable reservoirs remains unclear, necessitating detailed reservoir characterization. This study employs a combination of well and seismic technologies to accurately depict the sedimentary and reservoir characteristics of the Fuyu oil reservoir. By conducting detailed correlations of oil zones, a regional high-resolution isochronous stratigraphic framework is established. The division of sedimentary microfacies enables fine characterization of single sand bodies, identifying channel boundaries, clarifying lateral connectivity, and detailing the vertical contact relationships of sand bodies across different deposition periods. The results demonstrate that root-mean-square amplitude and total energy metrics effectively correspond to sand bodies in the study area and can be used to analyze sand body distribution. Provenance is primarily from the southwest to the northeast, with shallow deltas predominantly developed. Delta plain subfacies are found in zones 4-12, while delta front subfacies are in zones 1-3. Microfacies types mainly include the main distributary channel, distributary channel sides, crevasse splay, overbank sand, and underwater distributary channels. The main distributary channel reservoirs exhibit the best physical properties, with porosity ranging from 20-25%, while sand bodies at the sides of distributary channels reach 15-20%. Predicted favorable areas are mainly located at the intersections of distributary channels and structural highs, where drilling is likely to yield high oil flow.

Numerical Study on the Enhanced Oil Recovery by CO2 Huff-n-Puff in Shale Volatile Oil Formations

The Sichuan Basin’s Liangshan Formation shale is rich in oil and gas resources, yet the recovery rate of shale oil reservoirs typically falls below 10%. Currently, gas injection huff-n-puff (H-n-P) is considered one of the most promising methods for improving shale oil recovery. This study numerically investigates the application of the CO2 huff-n-puff process in enhancing oil recovery in shale volatile oil reservoirs. Using an actual geological model and fluid properties of shale oil reservoirs in the Sichuan Basin, the CO2 huff-n-puff process was simulated. The model takes into account the molecular diffusion of CO2, adsorption, stress sensitivity effects, and nanopore confinement. After history matching, through sensitivity analysis, the optimal injection rate of 400 tons/day, soaking time of 30 days, and three cycles of huff-n-puff were determined to be the most effective. The simulation results show that, compared with other gases, CO2 has significant potential in improving the recovery rate and overall efficiency of shale oil reservoirs. This study is of great significance and can provide valuable references for the actual work of CO2 huff-n-puff processes in shale volatile oil reservoirs of the Sichuan Basin.

Geodynamic development of structures of the North Absheron uplift zone within the South Caspian megadepression and oil-gas-bearing

The article discusses the geodynamic development of the structures of the North Absheron uplift zone. The Pirallahi-Kelkor trough is a polyfocal sub-basin due to the fact that in its sedimentary section, at least the Jurassic, Lower Cretaceous, Lower Pliocene and Quaternary deposits, are characterized by favorable conditions for the accumulation and burial of organic matter. It follows from this that, in accordance with its paleogeotemperature regime, several main stages of hydrocarbon migration could have taken place here. For identifying the formation and further structural-tectonic development , the Absheron bank, the Arzu, Chilov, Palchig Pilpilasi, Chirag and Garabag uplifts have been studied. To solve this issue, paleoprofiles for the end of the Jurassic, Early Cretaceous, Miocene and Pliocene based on the seismic geological profile across the strike of the Pirallahi-Kelkor trough have been compiled. As a result of these studies we established that the uplifts are of syndepositional origin, formed simultaneously with the sedimentation process. The sedimentation and geotemperature regime of the subbasin play a significant role . İt was found that by the end of the Pliocene, the main oil formation zone (MOFZ) contained sediments from the second half of the Lower Cretaceous to the second half of the Lower Pliocene, and both Lower Cretaceous and Lower Pliocene deposits took part in the main stage of hydrocarbon migration. Finally, the MOFZ currently contains sediments from the tops of the Lower Cretaceous to the bottoms of the Upper Pliocene. As can be seen, the main stage of migration covered both Lower Cretaceous and Lower Pliocene deposits. İn addition, we concluded that the natural reservoirs of local uplifts that formed within the Absheron archipelago, regardless of the time of their formation, could be saturated with hydrocarbons depending on the level of their development, position in the structural-tec- tonic plan and reservoir characteristics of the strata. Due to the fact that the uplifts were formed no later than the Miocene, it was even considered that they began to appear by the end of the earlier Miocene, and that they could have captured hydrocarbons of the Lower and Later Cretaceous period.

Enhancing PVT property predictions for black oil reservoirs through the application of supervised machine learning techniques

The study presents an innovative approach utilizing machine learning (ML) techniques to forecast essential characteristics of black oil reservoirs, namely the oil formation volume factor (Bo) and the solution gas-oil ratio (Rs). A suite of four established ML algorithms-Random Forest, Linear Regression, Ada Boost, and Gradient Boost were extensively conditioned using a dataset that includes 297 individual data points and evaluation is done using test data and a blind test of models. The study showcases the practical efficacy of ML in accurately predicting Bo and Rs, even with a relatively modest dataset. The potential of ML models to save time and costs by reducing the dependence on laborious laboratory measurements is underscored, presenting a transformative shift in reservoir engineering practices. Furthermore, the current research extends its impact by comparing ML predictions with various empirical correlations and actual values, demonstrating that ML models, particularly Gradient Boost, consistently outperform traditional correlations and it can be used to predict values in the undersaturated region too. It is observed from the blind test results that for the prediction of Bo Gradient boost and random forest models (R2 0.97, RMSE 0.01) is a preferable choice and for the prediction of Rs the Gradient boost model (R2 0.97, RMSE 22) can be preferred. The adaptability of ML models to integrate new data over time is a significant feature, ensuring continuous improvement in accuracy. This study adds to the expanding reservoir engineering knowledge base, highlighting the practical use of machine learning for accurately predicting crucial reservoir properties. Its significance goes beyond theoretical progress, providing tangible tools for reservoir engineers and geologists to improve decision-making in the management of oil and gas reservoirs.

Enhancement of Biocrude Quality Using Fecal Sludge and Organic Solid Waste Through Two-Stage Hydrothermal Liquefaction Technique

The escalating global challenge of managing unmanaged fecal sludge (250-300 million tonnes/year) and organic solid waste (600-700 million tonnes/year) necessitates innovative and sustainable waste-to-energy solutions. Hydrothermal liquefaction (HTL) of FS & OSW to produce biocrude has been seen as a double-edged sword to substitute fossil fuel and address the issues relating to unmanaged waste (GHG emission, global warming, climate change). Through this study, an approach was taken to improve the biocrude production and enhance the biocrude quality by introducing a two-stage heating in HTL of FS and OSW separately. Four different runs were comprised in this study where one run was in conventional one stage, at 320℃ for 60 min. In terms of the other three runs, in the first stage, 100, 200, and 300℃ were retained for 30 min respectively and the second stage was conducted at 320℃ for 30 min. Results indicate a substantial improvement in biocrude yield of 15% &18% through two-stage heating during HTL (30 min at 200℃, and then 30 min at 320℃) compared to conventional single-stage HTL processes of FS & OSW respectively with a biomass conversion rate of 70%. From the analysis of biocrude maturity & intensity of oil we observe a high potential for crude oil formation being classified as Kerogen type I. GC-FID shows that increasing heat in the first stage tends to produce a lighter fraction (at 300℃ in the first stage produces biocrude with a lighter fraction>80% from FS & OSW feedstocks) in biocrude. In addition to improving the overall efficiency of converting organic waste to biocrude, the two-stage system offers a more flexible platform that allows the biofuel composition to be customized to match the needs of individual applications. The results show that a two-stage HTL process is a feasible and effective technique for converting difficult waste streams into biofuels, with implications for both environmental sustainability and energy security. Journal of Engineering Science 15(1), 2024, 95-105

EVALUATION OF EFFICIENCY OF OIL DISPLACEMENT BY WATER AND GAS AT VARIOUS MODES

The purpose of the work is to analyze in detail the efficiency of oil displacement by various agents, such as water and gas, at different modes. During the study, various methods and technologies aimed at increasing oil recovery were considered, and the effect of various parameters on the efficiency of the process was studied.Particular attention was paid to the method of water-gas impact (HBV) using pump-ejector systems (PES), which provides a triple impact on oil formations by simultaneous or alternate injection of water and gas.Theoretical and experimental methods were used to conduct the study. The beginning of the work was the study and analysis of scientific sources on the issue of assessing the effectiveness of oil displacement. Further, laboratory tests were carried out to assess the effectiveness of oil displacement by various agents. Experimental studies were carried out on a two-phase and three-phase filtration unit. The main parameter measured was the coefficient of oil displacement by water and separation gas. The effectiveness of the impact of various modes of water and gas exposure was studied: alternating (cyclic) injection of water and gas with different cyclicity, simultaneous injection of water and gas, as well as injection of a fine water and gas mixture.Based on the results of the work, it was concluded that the degree of influence of wetting processes on the final displacement result is a critical factor. The following main points can be distinguished:- final value of oil displacement coefficient depends on selection of displacement agent;- in case of water and gas impact, the sequence of water and gas injection is of great importance;- the efficiency of oil displacement is highly dependent on the absolute permeability of the reservoir, as well as on the injection mode (sequential, simultaneous, cyclic).The results of the experiments can be useful for predicting the development of oil fields and choosing optimal methods for increasing oil recovery.The uniqueness of this article lies in the study of the possibilities of using multithreaded ejectors to increase the efficiency of hydrocarbon production.

Data-driven multiscale geomechanical modeling of unconventional shale gas reservoirs: a case study of Duvernay Formation, Alberta, West Canadian Basin

The Duvernay Formation in Canada is one of the major oil and gas source formations in the Western Canadian Sedimentary Basin, located at its deepest point. While it demonstrates promising development potential, challenges arise in the urgent need for integration of geology and engineering models, as well as in optimizing sweet spots, particularly as infill wells and pads become central operational objectives for the shale gas field. A lack of the geomechanical understanding of shale gas reservoirs presents a significant obstacle in addressing these challenges. To overcome this, we implemented data acquisition and prepared historical models and profiles, resulting in an extended high-resolution geological and reservoir property model with a fine grid system. Subsequently, a 3D full-field multi-scale geomechanical model was constructed for the main district by integrating seismic data (100 m), geological structures (km), routine logs (m), core data (cm), and borehole imaging (0.25 m), following a well-designed workflow. The predicted fracturability index (brittleness) ranges from 0.6 to 0.78, and a lower horizontal stress difference (STDIFF) is anticipated in the target formation, Upper Duvernay_D, making it a favorable candidate for hydraulic fracturing treatment. Post-analysis of the multi-disciplinary models and various data types provides guidelines for establishing a specific big database, which serves as the foundation for production performance analysis and aggregate sweet spot analysis. Fourteen geological and geomechanical candidate parameters are selected for the subsequent sweet spot analysis. This study highlights the effectiveness of multi-scale geomechanical modeling as a tool for the integration of multi-disciplinary data sources, providing a bridge between geological understanding and future field development decisions. The workflows also offer a data-driven framework for selecting parameters for sweet spot analysis and production dynamic analysis.