Abstract (
)
Download PDF (
)
Rich HTML
(
)
Knowledge map
Save
By conducting experimental analyses, including thermal pyrolysis, micro-/nano-CT, argon-ion polishing field emission scanning electron microscopy (FE-SEM), confocal laser scanning microscopy (CLSM), and two-dimensional nuclear magnetic resonance (2D NMR), the Gulong shale oil in the Songliao Basin was investigated with respect to formation model, pore structure and accumulation mechanism. First, in the Gulong shale, there are a large number of picotype algae, microalgae and dinoflagellates, which were formed in brackish water environment and constituted the hydrogen-rich oil source materials of shale. Second, most of the oil-generating materials of the Qingshankou Formation shale exist in the form of organic clay complex. During organic matter thermal evolution, clay minerals had double effects of suppression and catalytic hydrogenation, which expanded shale oil window and increased light hydrocarbon yield. Third, the formation of storage space in the Gulong Shale was related to dissolution and hydrocarbon generation. With the diagenesis, micro-/nano-pores increased, pore diameter decreased and more bedding fractures appeared, which jointly gave rise to the unique reservoir with dual media (i.e. nano-scale pores and micro-scale bedding fractures) in the Gulong shale. Fourth, the micro-/nano-scale oil storage unit in the Gulong shale exhibits independent oil/gas occurrence phase, and shows that all-size pores contain oils, which occur in condensate state in micropores or in oil-gas two phase (or liquid) state in macropores/mesopores. The understanding about Gulong shale oil formation and accumulation mechanism has theoretical and practical significance for advancing continental shale oil exploration in China.
Abstract (
)
Download PDF (
)
Rich HTML
(
)
Knowledge map
Save
The strike-slip faults and reservoirs in deep Sinian strata in the Anyue gas field of the Sichuan Basin were analyzed to identify the main controlling factors of dolomite reservoirs along the strike-slip fault zone and clarify how the strike-slip faults control the development and distribution of high-quality “sweet spot” (fractured-vuggy) reservoirs. The carbonate matrix reservoirs of the Sinian Dengying Formation are tight, with low porosity (less than 4%) and low permeability (less than 0.5×10-3 μm2). However, the strike-slip faults and their dissolution processes increased the permeability of carbonate rock by more than 1 order of magnitude and allowed the faulting-related dissolution porosity to be more than doubled. The “sweet spot” fractured-vuggy reservoirs controlled by strike-slip faults occurred widely along the strike-slip fault zone. These reservoirs were formed at the end of the Sinian under the joint control of sedimentary microfacies, faulting and karstification. At the platform margin, the control of karstification is predominant; while high-quality reservoirs controlled by both faulting and karstification are developed with the platform, and they are different in areas, types and zones. The structures of the strike-slip fault zone controlled the differential distribution of the fracture zones and the fault-controlled “sweet spot” reservoirs, and led to wide fracture-vug zones. In conclusion, the strike-slip fault related “sweet spot” reservoirs represent a new type of targets for efficient development of resources in deep ancient carbonates. For these reservoirs, specific development strategies should be made according to the diverse and differential controls of strike-slip faults on the reservoirs.
Abstract (
)
Download PDF (
)
Rich HTML
(
)
Knowledge map
Save
To understand the reservoir property and hydrocarbon accumulation conditions of the Middle and Upper Ordovician intraplatform shoal between ultra-deep main strike-slip faults in Fuman Oilfield of the Tarim Basin, China, the main strike-slip faults in and around Well FD1 in the basin were analyzed in terms of sedimentary facies, sequence stratigraphy, intraplatform shoal reservoir property, and oil and gas origins, based on drilling data. The Yingshan Formation intraplatform shoal between the main strike-slip faults is superimposed with low-order faults to form a new type of hydrocarbon play. Hydrocarbons generated from the Lower Cambrian Yuertusi Formation source rocks were firstly transported through the main strike-slip faults vertically to the second member of Yingshan Formation, and then migrated laterally until they were accumulated. In Well FD1, a small amount of oil came from the Yuertusi Formation source rocks in the mature stage, and a large amount of gas was cracked from oil in the ultra-deep reservoir. Therefore, the secondary gas condensate reservoir in Well FD1 is characterized by high gas to oil ratio, dry gas (dryness coefficient being 0.970) and hybrid origin. This new type of hydrocarbon play consisting of intraplatform shoal and low-order fault suggests a prospect of continuous hydrocarbon-bearing area in Fuman Oilfield, which will expand the ultrap-deep oil and gas exploration in the oilfield.
Abstract (
)
Download PDF (
)
Rich HTML
(
)
Knowledge map
Save
Based on the drilling, logging, experimental and testing data of Well PD1, a shallow normal-pressure shale gas well in the Laochangping anticline in southeastern Sichuan Basin, the shallow shale gas reservoirs of the Ordovician Wufeng Formation to Silurian Longmaxi Formation (Wufeng-Longmaxi) were investigated in terms of geological characteristics, occurrence mechanism, and adsorption-desorption characteristics, to reveal the enrichment laws and high-yield mechanism of shallow normal-pressure shale gas in complex structure areas. First, the shallow shale gas reservoirs are similar to the medium-deep shale gas reservoirs in static indicators such as high-quality shale thickness, geochemistry, physical properties and mineral composition, but the former is geologically characterized by low formation pressure coefficient, low gas content, high proportion of adsorbed gas, low in-situ stress, and big difference between principal stresses. Second, shallow shales in the complex structure areas have the gas occurrence characteristics including low total gas content (1.1-4.8 m3/t), high adsorbed gas content (2.5-2.8 m3/t), low sensitive desorption pressure (1.7-2.5 MPa), and good self-sealing. Third, the adsorbed gas enrichment of shales is mainly controlled by organic matter abundance, formation temperature and formation pressure: the higher the organic matter abundance and formation pressure, the lower the formation temperature and the higher the adsorption capacity, which is more beneficial for the adsorbed gas occurrence. Fourth, the shallow normal-pressure shale gas corresponds to low sensitive desorption pressure. The adsorbed gas can be rapidly desorbed and recovered when the flowing pressure is reduced below the sensitive desorption pressure. Fifth, the exploration breakthrough of Well PD1 demonstrates that the shallow complex structure areas with adsorbed gas in dominance can form large-scale shale reservoirs, and confirms the good exploration potential of shallow normal-pressure shale gas in the margin of the Sichuan Basin.
Abstract (
)
Download PDF (
)
Rich HTML
(
)
Knowledge map
Save
Based on rock mineral and geochemical analysis, microscopic observation, physical property measurement, and thin layer separation test, the characteristics of typical layers of the Paleogene Shahejie Formation carbonate-rich shale in the Jiyang Depression were analyzed, and the organic matter abundance, reservoir properties, and oil-bearing properties of different layers were compared. Typical shale storage-seepage structures were classified, and the mobility of oil in different types of shale storage-seepage structure was compared. The results show that the repeated superposition of mud layer and calcite layer is the main layer structure of carbonate-rich shales. The calcite layer is divided into micritic calcite layer, microsparry calcite layer and fibrous calcite vein. The mud layer is the main contributor to the organic matter abundance and porosity of shale, with the best hydrocarbon generation potential, reservoir capacity, and oil-bearing property. The micritic calcite layer also has relatively good hydrocarbon generation potential, reservoir capacity and oil-bearing property. The microsparry calcite layer and fibrous calcite vein have good permeability and conductivity. Four types of shale storage-seepage structure are developed in the carbonate-rich shale, including microsparry calcite-rich structure, mixed calcite-rich structure, fibrous calcite vein-rich structure, and micritic calcite-rich structure, in a descending order of oil mobility. The exploration targets of carbonate-rich shale in the Jiyang Depression Shahejie Formation are different in terms of storage-seepage structure at different thermal evolution stages.
Abstract (
)
Download PDF (
)
Rich HTML
(
)
Knowledge map
Save
Based on the recent oil and gas discoveries and geological understandings on the ultra-deep strata of sedimentary basins, the formation and occurrence of hydrocarbons in the ultra-deep strata were investigated with respect to the processes of basin formation, hydrocarbon generation, reservoir formation and hydrocarbon accumulation, and key issues in ultra-deep oil and gas exploration were discussed. The ultra-deep strata in China underwent two extensional-convergent cycles in the Meso-Neoproterozoic era and the Early Paleozoic Era respectively, with the tectonic-sedimentary differentiation producing the spatially adjacent source-reservoir assemblages. There are diverse large-scale carbonate reservoirs such as mound-beach, dolomite, karst fracture-vug, fractured karst and faulted zone, as well as over-pressured clastic rock and fractured bedrock reservoirs. Hydrocarbons were accumulated in multiple stages, accompanied by adjusting and finalizing in the late stage. The distribution of hydrocarbons is controlled by high-energy beach zone, regional unconformity, paleo-high and large-scale fault zone. The ultra-deep strata endow oil and gas resources as 33% of the remaining total resources, suggesting an important successive domain for hydrocarbon development in China. The large-scale pool-forming geologic units and giant hydrocarbon enrichment zones in ultra-deep strata are key and promising prospects for delivering successive discoveries. The geological conditions and enrichment zone prediction of ultra-deep oil and gas are key issues of petroleum geology.
Abstract (
)
Download PDF (
)
Rich HTML
(
)
Knowledge map
Save
The literatures on solid bitumen (SB) in shales are reviewed. Then, taking the organic-rich shales in the first member of the Cretaceous Qingshankou Formation (Qing 1 Member) in the Songliao Basin as an example, the definition, classification, occurrence and evolution of SB in shales are investigated, and the indications of SB on maturity and the influence of SB on reservoir space are discussed. The difference in primary maceral types is primarily responsible for the different evolution paths of SB. Pre-oil bitumen is mostly in-situ SB, while post-oil bitumen and pyrobitumen are usually migrated SB. In the immaturity to early oil generation stage, bituminite, vitrinite, and inertinite can be distinguished from SB depending on their optical characteristics under reflected light, and alginite can be differentiated from SB by their fluorescence characteristics. Under scanning electron microscope (SEM), in-situ SB and migrated SB can be identified. The SB reflectance increases linearly with increasing vitrinite reflectance, as a result of a decrease of aliphatic structure and the enhancement of aromatization of SB. Within the oil window, three types of secondary pores may develop in SB, including modified mineral pores, devolatilization cracks and bubble holes. In the high maturity stage, spongy pores may develop in pyrobitumen. SEM combined with in-situ analysis techniques (e.g. Raman spectroscopy) can further reveal the structural information of different types of SB, thus providing crucial data for research at micro-scales such as organic matter migration paths and dynamics.
Abstract (
)
Download PDF (
)
Rich HTML
(
)
Knowledge map
Save
Based on the measurements of petrological, petrophysical and elastic properties of the samples of different sedimentary facies in the fourth member of Sinian Dengying Formation (Deng 4 Member) in the Sichuan Basin, the diagenetic processes of reservoirs of different sedimentary facies and their controls on the petrophysical properties were discussed. The results show that cracks and mineral composition jointly control the petrophysical properties, and both are significantly influenced by sedimentary environment and diagenesis. The microbial dolomite of mound-shoal facies mainly experienced multi-stage dolomitization, penecontemporaneous dissolution, tectonic rupture and hydrothermal/organic acid dissolution processes, giving rise to cracks and dissolved pores. The grannular dolomite of inter-mound-shoal bottomland or dolomitic lagoon facies mainly underwent mechanical compaction, burial dolomitization and tectonic-hydrothermal action, creating cracks and intercrystalline pores. The diagenesis related to crack development increases the pressure- and saturation-dependent effects of samples, leading to significant decrease in the compressional wave impedance and Poisson's ratio. Dolomitization changes the properties of mineral particles, resulting in a Poisson's ratio close to dolomite. The muddy, siliceous and calcareous sediments in the low-energy environment lead to the decrease of impedance and the differential change of Poisson's ratio (significantly increased or decreased). The samples with both cracks and dissolved pores show high P-wave velocity dispersion characteristics, and the P-wave velocity dispersion of samples with only fractures or pores is the lowest.
Abstract (
)
Download PDF (
)
Rich HTML
(
)
Knowledge map
Save
The relationship between fracture calcite veins and shale gas enrichment in the deep Ordovician Wufeng Formation-Silurian Longmaxi Formation (Wufeng-Longmaxi) shales in southern Sichuan Basin was investigated through core and thin section observations, cathodoluminescence analysis, isotope geochemistry analysis, fluid inclusion testing, and basin simulation. Tectonic fracture calcite veins mainly in the undulating part of the structure and non-tectonic fracture calcite veins are mainly formed in the gentle part of the structure. The latter, mainly induced by hydrocarbon generation, occurred at the stage of peak oil and gas generation, while the former turned up with the formation of Luzhou paleouplift during the Indosinian. Under the influence of hydrocarbon generation pressurization process, fractures were opened and closed frequently, and oil and gas episodic activities are recorded by veins. The formation pressure coefficient at the maximum paleodepth exceeds 2.0. The formation uplift stage after the Late Yanshanian is the key period for shale gas migration. Shale gas migrates along the bedding to the high part of the structure. The greater the structural fluctuation is, the more intense the shale gas migration activity is, and the loss is more. The gentler the formation is, the weaker the shale gas migration activity is, and the loss is less. The shale gas enrichment in the core of gentle anticlines and gentle synclines is relatively higher.
Abstract (
)
Download PDF (
)
Rich HTML
(
)
Knowledge map
Save
The complexity of diagenesis and hydrocarbon accumulation in the deep reservoirs in southern Junggar Basin restricts the process of hydrocarbon exploration in the lower reservoir assemblage. The lithofacies and diagenesis of reservoirs in the Cretaceous Qingshuihe Formation in the Gaoquan structure of the Sikeshu Sag, southern Junggar Basin were analyzed. On this basis, the thermal evolution history of the basin was calibrated using calcite in-situ U-Pb dating and fluid inclusion analysis to depict the hydrocarbon accumulation process of the lower reservoir assemblage in the Gaoquan structure. The Qingshuihe Formation reservoirs experienced two phases of calcite cementation and three phases of hydrocarbon charging. The calcites are dated to be 122.1±6.4 Ma, 14.4±1.0 Ma, and 14.2±0.3 Ma. The hydrocarbon charging events occurred at around 14.2-30.0 Ma (low-mature oil), 14.2 Ma (mature oil), and 2 Ma (high-mature gas). The latter two phases of hydrocarbon charging contributed dominantly to the formation of reservoirs. Due to the tectonic activity of S-N compressive thrust in the late Himalayan since 2 Ma, the traps in the Gaoquan structure were reworked, especially the effective traps which developed in the main reservoir-forming period decreased significantly in scale, resulting in weak hydrocarbon shows in the middle-lower part of the structure. This indicates that the effective traps in key reservoir-forming period controlled hydrocarbon enrichment and distribution in the lower reservoir assemblage. Calcite U-Pb dating combined with fluid inclusion analysis can help effectively describe the complex diagenesis and hydrocarbon accumulation process of structural zones in the central-west part of the basin.
Abstract (
)
Download PDF (
)
Rich HTML
(
)
Knowledge map
Save
Considering the action mechanisms of overpressure on physical changes in skeletal grains of deep reservoir rocks and the differences in physical changes of skeletal grains under overpressure and hydrostatic pressure, the sandstone of the Jurassic Toutunhe Formation in the southern margin of Junggar Basin was taken as an example for physical modeling experiment to analyze the action mechanisms of overpressure on the physical properties of deep reservoirs. (1) In the simulated ultra-deep layer with a burial depth of 6000-8000 m, the mechanical compaction under overpressure reduces the remaining primary pores by about a half that under hydrostatic pressure. Overpressure can effectively suppress the mechanical compaction to allow the preservation of intergranular primary pores. (2) The linear contact length ratio under overpressure is always smaller than the linear contact length ratio under hydrostatic pressure at the same depth. In deep reservoirs, the difference between the mechanical compaction degree under overpressure and hydrostatic pressure shows a decreasing trend, the effect of abnormally high pressure to resist the increase of effective stress is weakened, and the degree of mechanical compaction is gradually close to that under hydrostatic pressure. (3) The microfractures in skeletal grains of deep reservoirs under overpressure are thin and long, while the microfractures in skeletal grains of deep reservoirs under hydrostatic pressure are short and wide. This difference is attributed to the probable presence of tension fractures in the rocks containing abnormally high pressure fluid. (4) The microfractures in skeletal grains under overpressure were mainly formed later than that under hydrostatic pressure, and the development degree and length of microfractures both extend deeper. (5) The development stages of microfractures under overpressure are mainly controlled by the development stages of abnormally high pressure and the magnitude of effective stress acting on the skeletal grains. Moreover, the development stages of microfractures in skeletal grains are more than those under hydrostatic pressure in deep reservoir. The multi-stage abnormally high pressure plays an important role in improving the physical properties of deep reservoirs.
Abstract (
)
Download PDF (
)
Rich HTML
(
)
Knowledge map
Save
The gas-water distribution and production heterogeneity of tight gas reservoirs have been summarized from experimental and geological observations, but the charging and accumulation mechanisms have not been examined quantitatively by mathematical model. The tight gas charging and accumulation mechanisms were revealed from a combination of physical simulation of nuclear magnetic resonance coupling displacement, numerical simulation considering material and mechanical equilibria, as well as actual geological observation. The results show that gas migrates into tight rocks to preferentially form a gas saturation stabilization zone near the source-reservoir interface. When the gas source is insufficient, gas saturation reduction zone and uncharged zone are formed in sequence from the source-reservoir interface. The better the source rock conditions with more gas expulsion volume and higher overpressure, the thicker the gas saturation stabilization and reduction zones, and the higher the overall gas saturation. When the source rock conditions are limited, the better the tight reservoir conditions with higher porosity and permeability as well as larger pore throat, the thinner the gas saturation stabilization and reduction zones, but the gas saturation is high. The sweet spot of tight gas is developed in the high-quality reservoir near the source rock, which often corresponds to the gas saturation stabilization zone. The numerical simulation results by mathematical model agree well with the physical simulation results by nuclear magnetic resonance coupling displacement, and explain the gas-water distribution and production pattern of deep reservoirs in the Xujiaweizi fault depression of the Songliao Basin and tight gas reservoirs in the Linxing-Huangfu area of the Ordos Basin.
Abstract (
)
Download PDF (
)
Rich HTML
(
)
Knowledge map
Save
The reservoirs in the seventh member of the Triassic Yanchang Formation (Chang 7 Member) in the Qingcheng Oilfield of the Ordos Basin are characterized by thin sandbody, tight rocks, high heterogeneity, low formation pressure coefficient, and complex geomorphology. Through the efforts in the stages of exploration, appraisal, pilot testing and development, a series of key technologies have been formed, including “sweet spot” optimization, differentiated three-dimensional well deployment, fast drilling and completion of large-scale horizontal well cluster, intensively-staged volume fracturing in long horizontal well, and optimization of rational production system. Furthermore, a production organization mode represented by factory-like operations on loess platform has been implemented. Application of these technologies has enabled to significantly improve the single-well production of the Qingcheng Oilfield, reduce the investment cost, and realize a large-scale and beneficial development at a full cost below $55 per barrel. In 2022, the annual production of Chang 7 shale oil in the Ordos Basin reached 221×104 t, accounting for 70% of the annual shale oil production of China. The practice of development technologies in the Qingcheng Oilfield provides valuable references for efficient development of continental shale oil.
Abstract (
)
Download PDF (
)
Rich HTML
(
)
Knowledge map
Save
Based on imbibition replacement of shut-in well in tight oil reservoirs, this paper expounds the principle of saturation rebalancing during the shut-in process after fracturing, establishes an optimization method for shut-in time after horizontal well volume fracturing with the goal of shortening oil breakthrough time and achieving rapid oil breakthrough, and analyzes the influences of permeability, porosity, fracture half-length and fracturing fluid volume on the shut-in time. The oil and water imbibition displacement in the matrix and fractures occurs during the shut-in process of wells after fracturing. If the shut-in time is too short, the oil-water displacement is not sufficient, and the oil breakthrough time is long after the well is put into production. If the shut-in time is too long, the oil and water displacement is sufficient, but the energy dissipation in the formation near the bottom of the well is severe, and the flowing period is short and the production is low after the well is put into production. A rational shut-in time can help shorten the oil breakthrough time, extend the flowing period and increase the production of the well. The rational shut-in time is influenced by factors such as permeability, porosity, fracture half-length and fracturing fluid volume. The shortest and longest shut-in times are negatively correlated with porosity, permeability, and fracture half-length, and positively correlated with fracturing fluid volume. The pilot test in tight oil horizontal wells in the Songliao Basin, NE China, has confirmed that the proposed optimization method can effectively improve the development effect of horizontal well volume fracturing.
Abstract (
)
Download PDF (
)
Rich HTML
(
)
Knowledge map
Save
We present an efficient and risk-informed closed-loop field development (CLFD) workflow for recurrently revising the field development plan (FDP) using the acquired information. To make the process practical, we integrated multiple concepts of machine learning, an intelligent selection process to discard the worst FDP options and a growing set of representative reservoir models. These concepts were combined and used with a cluster-based learning and evolution optimizer to efficiently explore the search space of decision variables. Unlike previous studies, we also added the execution time of the closed-loop field development (CLFD) workflow and worked with more realistic timelines to confirm the utility of a CLFD workflow. To appreciate the importance of data assimilation and new well-logs in a CLFD workflow, we carried out researches at rigorous conditions without a reduction in uncertainty attributes. The proposed CLFD workflow was implemented on a benchmark analogous to a giant field with extensively time-consuming simulation models. The results underscore that an ensemble with as few as 100 scenarios was sufficient to gauge the geological uncertainty, despite working with a giant field with highly heterogeneous characteristics. It is demonstrated that the CLFD workflow can improve the efficiency by over 85% compared to the previously validated workflow. Finally, we present some acute insights and problems related to data assimilation for the practical application of a CLFD workflow.
Abstract (
)
Download PDF (
)
Rich HTML
(
)
Knowledge map
Save
Combining low salinity water (LSW) with surfactants has an enormous potential for enhancing oil recovery processes. However, there is no consensus about the mechanisms involved, in addition to the fact that several studies have been conducted in model systems, while experiments with rocks and reservoir fluids are scarce. This study presents a core-flooding experiment of LSW injection, with and without surfactant, using the core and heavy oil samples obtained from a sandstone reservoir in southeastern Mexico. The effluents and the crude oil obtained at each stage were analyzed. The study was complemented by tomographic analysis. The results revealed that LSW injection and hybrid process with surfactants obtained an increase of 11.4 percentage points in recovery factor. Various phenomena were caused by LSW flooding, such as changes in wettability and pH, ion exchange, mineral dissolution, detachment of fines and modification of the hydrocarbon profile. In the surfactant flooding, the reduction of interfacial tension and alteration of wettability were the main mechanisms involved. The findings of this work also showed that the conditions believed to be necessary for enhanced oil recovery with LSW, such as the presence of kaolinite or high acid number oil, are not relevant.
Abstract (
)
Download PDF (
)
Rich HTML
(
)
Knowledge map
Save
According to the transversely isotropic theory and weak plane criterion, and considering the mechanical damages due to stress unloading and hydration during drilling, a shale wellbore stability model with the influence of stress unloading and hydration was established using triaxial test and shear test. Then, factors influencing the wellbore stability in shale were analyzed. The results indicate that stress unloading occurs during drilling in shale. The larger the confining pressure and axial stress, the more remarkable weakening of shale strength caused by stress unloading. The stress unloading range is positively correlated with the weakening degree of shale strength. Shale with a higher development degree of bedding is more prone to damage along bedding. In this case, during stress unloading, the synergistic effect of weak structural plane and stress unloading happens, leading to a higher weakening degree of shale strength and poorer mechanical stability, which brings a higher risk of wellbore instability. Fluid tends to invade shale through bedding, promoting the shale hydration. Hydration also can weaken shale mechanical stability, causing the decline of wellbore stability. Influence of stress unloading on collapse pressure of shale mainly occurs at the early stage of drilling, while the influence of hydration on wellbore stability mainly happens at the late stage of drilling. Bedding, stress unloading and hydration jointly affect the wellbore stability in shale. The presented shale wellbore stability model with the influence of stress unloading and hydration considers the influences of the three factors. Field application demonstrates that the prediction results of the model agree with the actual drilling results, verifying the reliability of the model.
Abstract (
)
Download PDF (
)
Rich HTML
(
)
Knowledge map
Save
The existing approaches for identifying events in horizontal well fracturing are difficult, time-consuming, inaccurate, and incapable of real-time warning. Through improvement of data analysis and deep learning algorithm, together with the analysis on data and information of horizontal well fracturing in shale gas reservoirs, this paper presents a method for intelligent identification and real-time warning of diverse complex events in horizontal well fracturing. An identification model for "point" events in fracturing is established based on the Att-BiLSTM neural network, along with the broad learning system (BLS) and the BP neural network, and it realizes the intelligent identification of the start/end of fracturing, formation breakdown, instantaneous shut-in, and other events, with an accuracy of over 97%. An identification model for "phase" events in fracturing is established based on enhanced Unet++ network, and it realizes the intelligent identification of pump ball, pad-acid treatment, temporary plugging fracturing, sand plugging, and other events, with an error of less than 0.002. Moreover, a real-time prediction model for fracturing pressure is built based on the Att-BiLSTM neural network, and it realizes the real-time warning of diverse events in fracturing. The proposed method can provide an intelligent, efficient and accurate identification of events in fracturing to support the decision-making.
Abstract (
)
Download PDF (
)
Rich HTML
(
)
Knowledge map
Save
By analyzing the corrosion of phosphate completion fluid on the P110 steel at 170 ℃, the high-temperature corrosion mechanism of phosphate completion fluid was revealed, and a corrosion inhibition method by membrane transformation was proposed and an efficient membrane-forming agent was selected. Scanning electron microscope (SEM) images, X-ray energy spectrum and X-ray diffraction results were used to characterize the microscopic morphology, elemental composition and phase composition of the precipitation membrane on the surface of the test piece. The effect and mechanism of corrosion inhibition by membrane transformation were clarified. The phosphate completion fluid eroded the test piece by high-temperature water vapor and its hydrolyzed products to form a membrane of iron phosphate corrosion product. By changing the corrosion reaction path, the Zn2+ membrane-forming agent could generate KZnPO4 precipitation membrane with high temperature resistance, uniform thickness and tight crystal packing on the surface of the test piece, which could inhibit the corrosion of the test piece, with efficiency up to 69.63%. The Cu2+ membrane-forming agent electrochemically reacted with Fe to precipitate trace elemental Cu on the surface of the test piece, thus forming a protective membrane, which could inhibit metal corrosion, with efficiency up to 96.64%, but the wear resistance was poor. After combining 0.05% Cu2+ and 0.25% Zn2+, a composite protective membrane of KZnPO4 crystal and elemental Cu was formed on the surface of the test piece. The corrosion inhibition efficiency reached 93.03%, which ensured the high corrosion inhibition efficiency and generated a precipitation membrane resistant to temperature and wear.
Abstract (
)
Download PDF (
)
Rich HTML
(
)
Knowledge map
Save
Molecular dynamics method was used to establish composite wall/inorganic nanopores of three pore sizes, three shale oil systems, five CO2-cosolvent systems, and pure CO2 system. The process of CO2-cosolvent displacement of crude oil in shale nanopores and carbon storage was simulated and the influencing factors of displacement and storage were analyzed. It is shown that the attraction of the quartz wall to shale oil increases with the degree of hydroxylation. The higher the degree of quartz hydroxylation, the more difficult it is to extract the polar components of shale oil. Nanopore size also has a great impact on shale oil displacement efficiency. The larger the pore size, the higher the shale oil displacement efficiency. The closer the cosolvent molecules are to the polarity of the shale oil, the higher the mutual solubility of CO2 and shale oil. The more the non-polar components of shale oil, the lower the mutual solubility of CO2 and shale oil with highly polar cosolvent. Ethyl acetate is more effective in stripping relatively high polar shale oil, while dimethyl ether is more effective in stripping relatively low polar shale oil. Kerogen is highly adsorptive, especially to CO2. The CO2 inside the kerogen is not easy to diffuse and leak, thus allowing for a stable carbon storage. The highest CO2 storage rate is observed when dimethyl ether is used as a cosolvent, and the best storage stability is observed when ethyl acetate is used as a cosolvent.
