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Marine shale gas resources have great potential in the south of the Sichuan Basin in China. At present, the high-quality shale gas resources at depth of 2000-3500 m are under effective development, and strategic breakthroughs have been made in deeper shale gas resources at depth of 3500-4500 m. To promote the effective production of shale gas in this area, this study examines key factors controlling high shale gas production and presents the next exploration direction in the southern Sichuan Basin based on summarizing the geological understandings from the Lower Silurian Longmaxi Formation shale gas exploration combined with the latest results of geological evaluation. The results show that: (1) The relative sea depth in marine shelf sedimentary environment controls the development and distribution of reservoirs. In the relatively deep water area in deep-water shelf, grade-I reservoirs with a larger continuous thickness develop. The relative depth of sea in marine shelf sedimentary environment can be determined by redox conditions. The research shows that the uranium to thorium mass ratio greater than 1.25 indicates relatively deep water in anoxic reduction environment, and the uranium to thorium mass ratio of 0.75-1.25 indicates semi-deep water in weak reduction and weak oxidation environment, and the uranium to thorium mass ratio less than 0.75 indicates relatively shallow water in strong oxidation environment. (2) The propped fractures in shale reservoirs subject to fracturing treatment are generally 10-12 m high, if grade-I reservoirs are more than 10 m in continuous thickness, then all the propped section would be high-quality reserves; in this case, the longer the continuous thickness of penetrated grade-I reservoirs, the higher the production will be. (3) The shale gas reservoirs at 3500-4500 m depth in southern Sichuan are characterized by high formation pressure, high pressure coefficient, well preserved pores, good pore structure and high proportion of free gas, making them the most favorable new field for shale gas exploration; and the pressure coefficient greater than 1.2 is a necessary condition for shale gas wells to obtain high production. (4) High production wells in the deep shale gas reservoirs are those in areas where Long11- Long13 sub-beds are more than 10 m thick, with 1500 m long horizontal section, grade-I reservoirs penetration rate of over 90%, and fractured by dense cutting + high intensity sand injection + large displacement + large liquid volume. (5) The relatively deep-water area in the deep-water shelf and the area at depth of 3500-4500 m well overlap in the southern Sichuan, and the overlapping area is the most favorable shale gas exploration and development zones in the southern Sichuan in the future. With advancement in theory and technology, annual shale gas production in the southern Sichuan is expected to reach 450×108m3.
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Compared with marine facies shale strata, lacustrine shale strata are more complicated in geological conditions, and thus more difficult to explore and develop. To realize economic exploration and development of lacustrine shale oil, the geological regularities of accumulation and high yield of retained movable petroleum in shale should be understood first. In this work, taking the shale strata of Kong 2 Member and Sha 3 Member in the Paleogene of Huanghua depression in the Bohai Bay Basin as examples, based on the previous joint analysis results of over ten thousand core samples and the latest oil testing, production test and geochemical data of more than 30 horizontal wells, accumulation conditions and models of retained movable petroleum in lacustrine shale were studied comprehensively. The study shows that at moderate organic matter abundance (with TOC from 2% to 4%), shale strata have the best match between oil content and brittleness, and thus are rich in oil and good in fracability. Moderate ancient lake basin size and moderate sediment supply intensity are the internal factors leading to best coupling of organic matter abundance and brittle mineral content in the shale formation. Moderate thermal evolution maturity of Ro of 0.7%-1.0% (at burial depth of 3200 to 4300 m) is the interval where oil generation from thermal evolution and oil adsorption by kerogen in shale layers match best, and retained movable petroleum is high in proportion. Moderate diagenetic evolution stage (3200 to 4300 m in the middle diagenetic stage A) is conducive to the formation of a large number of dissolved pores and organic matter pores, which provide storage space for shale oil enrichment. Moderate development degree of natural fractures (without damaging the shale oil roof and floor sealing conditions) is conducive to the storage, seepage and preservation of shale oil. The research results have overthrown the general understanding that high organic matter abundance, high maturity, and high development degree of natural fractures are conducive to shale oil enrichment, and have guided the comprehensive evaluation of shale oil and gas sweet spots and well deployment in the second member of the Kongdian Formation in the Cangdong sag and the Shahejie Formation in the Qikou sag. Industrial development of the shale oil in Kong 2 Member of the Cangdong sag has made major breakthrough, and important signs of shale oil have been found in Sha 3 Member of the Qikou sag, demonstrating huge exploration potential of lacustrine shale oil.
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A set of shale-dominated source rocks series were deposited during the heyday of lake basin development in the Member 7 of Triassic Yanchang Formation, Ordos Basin, and the thickness is about 110 m. Aimed at whether this layer can form large-scale oil enrichment of industrial value, comprehensive geological research and exploration practice have been carried out for years and obtained the following important geologic findings. Firstly, widely distributed black shale and dark mudstone with an average organic matter abundance of 13.81% and 3.74%, respectively, lay solid material foundation for the formation of shale oil. Secondly, sandy rocks sandwiched in thick organic-rich shale formations constitute an oil-rich “sweet spot”, the average thickness of thin sandstone is 3.5 m. Thirdly, fine-grained sandstone and siltstone reservoirs have mainly small pores of 2-8 μm and throats of 20-150 nm in radius, but with a large number of micro-pores and nano-throats, through fracturing, the reservoirs can provide good conductivity for the fluid in it. Fourthly, continued high-intensity hydrocarbon generation led to a pressure difference between the source rock and thin-layer reservoir of up to 8-16 MPa during geological history, driven by the high pressure, the oil charged into the reservoirs in large area, with oil saturation reaching more than 70%. Under the guidance of the above theory, in 2019, the Qingcheng Oilfield with geologic oil reserves of billion ton order was proved in the classⅠmulti-stage superimposed sandstone shale reservoir of Chang 7 Member by the Changqing Oilfield Branch through implementation of overall exploration and horizontal well volume fracturing. Two risk exploration horizontal wells were deployed for the classⅡ thick layer mud shale interbedded with thin layers of silt- and fine-sandstones reservoir in the Chang 73 submember, and they were tested high yield oil flows of more than 100 tons per day, marking major breakthroughs in petroleum exploration in classⅠshale reservoirs. The new discoveries have expanded the domain of unconventional petroleum exploration.
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The paleotectonic pattern, lithofacies paleogeographic features, sedimentary evolution and its controlling effects on hydrocarbon accumulation assemblages during the depositional period of the Sinian Dengying Formation in middle-upper Yangtze region were investigated based on outcrops, drilling, log and seismic data. The study shows that, (1) Affected by the breakup of the Rodinia supercontinent, the middle and upper Yangtze areas were in extensional tectonic environment during the depositional period of Dengying Formation. The carbonate platform was structurally differentiated. Intra-platform depressions controlled by syndepositional faults developed, forming a tectonic-paleogeographic pattern of “three platforms with two depressions”. (2) During the depositional period of the first and second members of the Dengying Formation, rimmed platforms and intra-platform fault depressions developed in upper Yangtze area and isolated platform developed in middle Yangtze area, and there was the Xuanhan-Kaijiang ancient land block in eastern Sichuan. The depositional period of the third member of the Dengying Formation is the transformation period of tectonic-paleogeographic pattern, when a set of shallow water shelf sediment rich in mud was deposited due to transgression on the background of the eroded terrain formed in EpisodeⅠof Tongwan Movement. The sediment of the fourth member of the Dengying Formation inherited the paleogeographic pattern of the first and second members of the Dengying Formation in general, but the Deyang-Anyue intra-platform fault depression further expanded, and the middle Yangtze platform evolved into two separated platforms. (3) Tectonic-sedimentary differentiation and evolution of carbonate platform in the Sinian gave rise to two types of accumulation assemblages with wide distribution and great exploration potential, which are platform margin and intra-platform.
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The diagenesis and diagenetic facies of shale reservoirs in Lucaogou Formation of Jimusar Sag were studied by means of microscopic observation and identification of ordinary thin sections and cast thin sections, X-ray diffraction, scanning electron microscope and electron probe tests. The results show that alkaline and acidic diagenetic processes occurred alternately during the deposition of Permian Lucaogou Formation in Jimusar Sag. The evolution of porosity in the shale reservoirs was influenced by compaction and alternate alkaline and acidic diagenetic processes jointly, and has gone through three stages, namely, stage of porosity reduction and increase caused by alkaline compaction, stage of porosity increase caused by acid dissolution, and stage of porosity increase and reduction caused by alkaline dissolution. Correspondingly, three secondary pore zones developed in Lucaogou Formation. The shale reservoirs are divided into three diagenetic facies: tuff residual intergranular pore-dissolution pore facies, tuff organic micrite dolomite mixed pore facies, and micrite alga-dolomite intercrystalline pore facies. With wide distribution, good pore structure and high oil content, the first two facies are diagenetic facies of favorable reservoirs in Lucaogou Formation. The research results provide a basis for better understanding and exploration and development of the Lucaogou Formation shale reservoirs.
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High-yielding oil wells were recently found in the first member of Paleogene Shahejie Formation, the Binhai area of Qikou Sag, providing an example of medium- and deep-buried high-quality reservoirs in the central part of a faulted lacustrine basin. By using data of cores, cast thin sections, scanning electron microscope and physical property tests, the sedimentary facies, physical properties and main control factors of the high-quality reservoirs were analyzed. The reservoirs are identified as deposits of slump-type sub-lacustrine fans, which are marked by muddy fragments, slump deformation structure and Bouma sequences in sandstones. They present mostly medium porosity and low permeability, and slightly medium porosity and high permeability. They have primary intergranular pores, intergranular and intragranular dissolution pores in feldspar and detritus grains, and structural microcracks as storage space. The main factors controlling the high quality reservoirs are as follows: (1) Favorable sedimentary microfacies of main and proximal distributary gravity flow channels. The microfacies with coarse sediment were dominated by transportation and deposition of sandy debris flow, and the effect of deposition on reservoir properties decreases with the increase of depth. (2) Medium texture maturity. It is shown by medium-sorted sandstones that were formed by beach bar sediment collapsing and redepositing, and was good for the formation of the primary intergranular pores. (3) High content of intermediate-acid volcanic rock detritus. The reservoir sandstone has high content of detritus of various components, especially intermediate-acid volcanic rock detritus, which is good for the formation of dissolution pores. (4) Organic acid corrosion. It was attributed to hydrocarbon maturity during mesodiagenetic A substage. (5) Early-forming and long lasting overpressure. A large-scale overpressure compartment was caused by under-compaction and hydrocarbon generation pressurization related to thick deep-lacustrine mudstone, and is responsible for the preservation of abundant primary pores. (6) Regional transtensional tectonic action. It resulted in the structural microcracks.
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Through lithofacies analysis and architecture anatomy of the Carboniferous Ross Sandstone turbidites outcropped at western Ireland, the depositional model of deepwater turbidite lobes is established. Seven types of lithofacies are recognized including goniatites-rich shale, laminated shale, laminated siltstone, massive sandstone, fine-medium sandstone with mud-clast, basal gravel, and chaotic mudstone, which can be subdivided into units of three origins, turbidite lobe, turbidite channel, and slide-slump; and four hierarchical levels, lobe complex, lobe, lobe element and single sandstone layer. The lobes show apparent compensational stacking pattern, lobe elements display typical thickening-upward cycles on vertical profile, and the higher the hierarchical level, the better the preservation of the hierarchical boundary is. In general, turbidite lobe deposits appear as tabular, parallel/sub-parallel sandstone and mudstone interbeds, and change from thick, massive sandstone in the proximal end to thinner sandstone and mudstone interbeds from axis to fringe, with the sand-shale ratio and degree of sandstone amalgamation decreasing.
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Ancient marine carbonates experienced complex modifications, making it difficult to identify reservoir genesis and effective porosity before hydrocarbon migration. To solve these issues, we used element mapping and carbonate mineral laser U-Pb radiometric dating techniques to study the diagenetic environments based on geochemistry and diagenesis-porosity evolution based on geochronology of the dolomite reservoir of the Sinian Qigebrak Formation, northwest Tarim Basin. Two major understandings were obtained as follows: (1) Supported by petrographic observations, the element mapping, stable isotopes, strontium isotope, and cathodoluminescence tests were performed on different phases of dolomite cements precipitated in vugs and dissolved fissures. The results show that the dolomite reservoirs of the Qigebrak Formation went through freshwater, marine, extremely shallow burial, burial and hydrothermal diagenetic environments after synsedimentary dolomitization; the reservoir spaces were mainly formed in the synsedimentary period (primary pores) and freshwater environment (supergene dissolution pores) before burial; whereas the marine, burial and hydrothermal environments caused the gradual filling of reservoir space by dolomite cements. (2) Based on the above understandings, each phase of dolomite cement precipitated in the reservoir space was dated by the U-Pb radiometric dating technique, and the diagenesis-porosity evolution curves constrained by geochronology were established. The loss of reservoir porosity mainly occurred in the early Caledonian, and during the peak period of hydrocarbon generation of Yuertusi Formation source rock, the reservoirs still maintained at a porosity of 6%-10%. The above understandings provide a certain basis for the evaluation of accumulation effectiveness of the Sinian Qigebrak Formation, northwestern Tarim Basin, and provide a case for the application of mapping and dating techniques in the study of ancient carbonate reservoirs.
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The concept and characteristics of fluvial fan are elucidated through literature review and case analysis. Firstly, the concept and terminology of fluvial fan are introduced. Secondly, the progress and controversy on the formation mechanism, analysis methods and sedimentary models of fluvial fan are elaborated, and fluvial fan is compared with alluvial fan, river and lacustrine delta. Finally, ten identification signs of the fluvial fan are proposed. It is found through the study that development and scale of fluvial fan are affected by external factors such as climate, tectonic, provenance and wind field. The facies and lithofacies association inside the fan are controlled by the activity of the internal channel. It is pointed that fluvial fans are widely distributed in the world not only today but also in the geological history. The occurrence of fluvial fan will change the traditional continental deposition system dominated by alluvial fan-river-lacustrine. Meanwhile, the research of fluvial fan will be of great significance in the fields of sedimentology and oil and gas exploration.
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Carboniferous carbonate reservoirs at the eastern edge of the Pre-Caspian Basin have undergone complex sedimentation, diagenesis and tectonism processes, and developed various reservoir space types of pores, cavities and fractures with complicated combination patterns which create intricate pore-throats structure. The complex pore-throat structure leads to the complex porosity-permeability relationship, bringing great challenges for classification and evaluation of reservoirs and efficient development. Based on the comprehensive analysis on cores, thin sections, SEM, mercury intrusion, routine core analysis and various tests, this paper systematically investigated the features and main controlling factors of pore-throats structure and its impact on the porosity-permeability relationship of the four reservoir types which were pore-cavity-fracture, pore-cavity, pore-fracture and pore, and three progresses are made. (1) A set of classification and descriptive approach for pore-throat structure of Carboniferous carbonate reservoirs applied to the eastern edge of the Pre-Caspian Basin was established. Four types of pore-throat structures were developed which were wide multimodal mode, wide bimodal mode, centralized unimodal mode and asymmetry bimodal mode, respectively. The discriminant index of pore-throat structure was proposed, realizing the quantitative characterization of pore-throat structure types. (2) The microscopic heterogeneity of pore reservoir was the strongest and four types of pore-throat structures were all developed. The pore-fracture and pore-cavity-fracture reservoirs took the second place, and the microscopic heterogeneity of pore-cavity reservoir was the weakest. It was revealed that the main controlling factor of pore-throat structure was the combination patterns of reservoir space types formed by sedimentation, diagenesis and tectonism. (3) It was revealed that the development of various pore-throat structure types was the important factor affecting poroperm relationship of reservoirs. The calculation accuracy of permeability of reservoirs can be improved remarkably by subdividing the pore-throat structure types. This study deepens the understanding of pore-throat structure of complicated carbonate reservoirs, and is conducive to classification and evaluation, establishment of precise porosity-permeability relationship and highly efficient development of carbonate reservoirs.
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Low maturity coal samples were taken from the Ordos Basin to conduct gold tube thermal simulation experiment in a closed system, and the characteristics of the products were analyzed to find out the fractionation mechanism of carbon isotopes and the causes of abnormal carbon isotopic compositions of natural gas. At the heating rates of 2 °C/h (slow) and 20 °C/h (rapid), the low maturity coal samples of the Ordos Basin had the maximum yields of alkane gas of 302.74 mL/g and 230.16 mL/g, the δ13C1 ranges of -34.8‰ to -23.6‰ and -35.5‰ to -24.0‰; δ13C2 ranges of -28.0‰ to -9.0‰ and -28.9‰ to -8.3‰; and δ13C3 ranges of -25.8‰ to -14.7‰ and -26.4‰ to -13.2‰, respectively. Alkane gas in the thermal simulation products of rapid temperature rise process showed obvious partial reversal of carbon isotope series at 550°C, and at other temperatures showed positive carbon isotope series. In the two heating processes, the δ13C1 turned lighter first and then heavier, and the non-monotonic variation of the δ13C1 values is because the early CH4 is from different parent materials resulted from heterogeneity of organic matter or the carbon isotope fractionation formed by activation energy difference of early enriched12CH4 and late enriched13CH4. The reversal of carbon isotope values of heavy hydrocarbon gas can occur not only in high to over mature shale gas (oil-type gas), but also in coal-derived gas. Through thermal simulation experiment of toluene, it is confirmed that the carbon isotope value of heavy hydrocarbon gas can be reversed and inversed at high to over mature stage. The isotope fractionation effect caused by demethylation and methyl linkage of aromatic hydrocarbons may be an important reason for carbon isotope inversion and reversal of alkane gas at the high to over mature stage.
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Based on well test interpretation, production performance analysis, overburden permeability and porosity test, gas-water core flooding test and high-pressure mercury injection, a quantitative correlation has been built of in-situ effective permeability with routine permeability and water saturation, and the ranges of Main Flow Channel Index (MFCI) are determined for different permeability levels in porous sand gas reservoirs. A new method to evaluate the in-situ effective permeability of porous sand reservoir and a correlation chart of reserves producing degree and main flow channel index are established. The results reveal that the main flow channel index of porous sand gas reservoirs has close correlation with routine matrix permeability and water saturation. The lower the routine matrix permeability and the higher the water saturation, the lower the MFCI is. If the routine matrix permeability is greater than 5.0×10-3, the MFCI is generally greater than 0.5. When the routine matrix permeability is from 1.0×10-3 to 5.0×10-3, the MFCI is mainly between 0.2 and 0.5. When the routine matrix permeability is less than 1.0×10-3, the MFCI is less than 0.2. The evaluation method of in-situ effective permeability can be used to evaluate newly discovered or not tested porous sand gas reservoirs quickly and identify whether there is tight sand gas. The correlation chart of reserves producing degree and main flow channel index can provide basis for recoverable reserves evaluation and well infilling, and provide technical support for formulation of reasonable technical policy of gas reservoir.
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Based on the characteristics of injection-production units in fractured-vuggy carbonate reservoirs, nine groups of experiments were designed and performed to analyze the interference characteristics and their influencing factors during water flooding. Based on percolation theory, an inversion model for simulating waterflooding interferences was proposed to study the influence laws of different factors on interference characteristics. The results show that well spacing, permeability ratio, cave size, and cave location all affect the interference characteristics of water flooding. When the cave is located in high permeability fractures, or in the small well spacing direction, or close to the producer in an injection-production unit, the effects of water flooding are much better. When the large cave is located in the high-permeability or small well spacing direction, the well in the direction with lower permeability or smaller well spacing will see water breakthrough earlier. When the cave is in the higher permeability direction and the reserves between the water injector and producer differ greatly, the conductivity differences in different injection-production directions are favorable for water flooding. When the injection-production well pattern is constructed or recombined, it’s better to make the reserves of caves in different injection-production directions proportional to permeability, and inversely proportional to the well spacing. The well close to the cave should be a producer, and the well far from the cave should be an injector. Different ratios of cave reserves to fracture reserves correspond to different optimal well spacings and optimal permeability ratios. Moreover, both optimal well spacing and optimal permeability ratio increase as the ratio of cave reserves to fracture reserves increases.
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Based on long-term dynamic tracing of dissolved inorganic carbon (DIC) and stable carbon isotope (δ13CDIC) in produced water from 20 coalbed methane (CBM) wells in western Guizhou, the spatial-temporal dynamic variations of δ13CDIC of the GP well group produced in multi-layer commingled manner were analyzed, and the relationship between the value of δ13CDIC and CBM productivity was examined. The produced water samples of typical wells in the GP well group were amplified and sequenced using 16S rDNA, and a geological response model of δ13CDIC in produced water from CBM wells with multi-coal seams was put forward. The research shows that: δ13CDIC in produced water from medium-rank coal seams commonly show positive anomalies, the produced water contains more than 15 species of methanogens, and Methanobacterium is the dominant genus. The dominant methanogens sequence numbers in the produced water are positively correlated with δ13CDIC, and the positive anomaly of δ13CDIC is caused by reduction of methanogens, and especially hydrogenotrophic methanogens. Vertical segmentation of sedimentary facies and lithology in stratum with multi-coal seams will result in permeability and water cut segmentation, which will lead to the segmentation of δ13CDIC and archaea community in produced water, so in the strata with better permeability and high water cut, the δ13CDIC of the produced water is abnormally enriched, and the dominant archaea is mainly Methanobacterium. In the strata with weak permeability and low water cut, the δ13CDIC of the produced water is small, and the microbial action is weak. The shallow layer close to the coal seam outcrop is likely to be affected by meteoric precipitation, so the δ13CDIC of the produced water is smaller. The geological response model of δ13CDIC in produced water from multi-coal seams CBM wells in the medium-rank coal reveals the geological mechanism and microbial action mechanism of the δ13CDIC difference in the produced water from the multi-coal seams CBM wells. It also provides effective geochemical evidence for the superimposed fluid system controlled by sedimentary facies, and can also be used for the contribution analysis of the produced gas and water by the multi-layer CBM wells.
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A deep learning method for predicting oil field production at ultra-high water cut stage from the existing oil field production data was presented, and the experimental verification and application effect analysis were carried out. Since the traditional Fully Connected Neural Network (FCNN) is incapable of preserving the correlation of time series data, the Long Short-Term Memory (LSTM) network, which is a kind of Recurrent Neural Network (RNN), was utilized to establish a model for oil field production prediction. By this model, oil field production can be predicted from the relationship between oil production index and its influencing factors and the trend and correlation of oil production over time. Production data of a medium and high permeability sandstone oilfield in China developed by water flooding was used to predict its production at ultra-high water cut stage, and the results were compared with the results from the traditional FCNN and water drive characteristic curves. The LSTM based on deep learning has higher precision, and gives more accurate production prediction for complex time series in oil field production. The LSTM model was used to predict the monthly oil production of another two oil fields. The prediction results are good, which verifies the versatility of the method.
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A large data bank of more than 700 gas-condensate samples collected from literature and experiments was established. On this basis, empirical correlations and equations of state commonly used to calculate dew-point pressure (DPP) were evaluated. A new model for estimating DPP was proposed. All the empirical correlations and the Peng-Robinson state equation were compared, and sensitivity of parameters was analyzed. The current standards used to identify gas condensate were evaluated and found to be not accurate enough. The Peng-Robinson state equation has no unique solution and is affected by multiple factors such as the characterization of C7+ components and the splitting scheme. The Nemeth-Kennedy correlation has the highest accuracy when applied to the data bank established in this study, followed by Elsharkawy correlation and Godwin correlation. While Shokir correlation cannot be used for samples without C7+ components, it is therefore the lowest in accuracy. The newly proposed model has an average absolute error, root mean square error and coefficient of determination of 7.5%, 588, and 0.87, respectively, and is better than the above four correlations statistically. The proposed model proved to be more accurate and valid when compared to experimental results and simulation with the Peng-Robinson state equation.
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This article outlines the development of separated zone oil production in foreign countries, and details its development in China. According to the development process, production needs, technical characteristics and adaptability of oilfields in China, the development of separate zone oil production technology is divided into four stages: flowing well zonal oil production, mechanical recovery and water blocking, hydraulically adjustable zonal oil production, and intelligent zonal production. The principles, construction processes, adaptability, advantages and disadvantages of the technology are introduced in detail. Based on the actual production situation of the oilfields in China at present, three development directions of the technology are proposed. First, the real-time monitoring and adjustment level of separated zone oil production needs to be improved by developing downhole sensor technology and two-way communication technology between ground and downhole and enhancing full life cycle service capability and adaptability to horizontal wells. Second, an integrated platform of zonal oil production and management should be built using a digital artificial lifting system. Third, integration of injection and production should be implemented through large-scale application of zonal oil production and zonal water injection to improve matching and adjustment level between the injection and production parameters, thus making the development adjustment from "lag control" to "real-time optimization" and improving the development effect.
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The main area of the Jiaoshiba anticline of the Fuling shale gas field was taken as the research object, laboratory rock mechanical experiments and direct shear experiments were conducted to clarify the mechanical anisotropy characteristics and parameters of rock samples with rich beddings. Based on the experimental results, a 3D fracture propagation model of the target reservoir taking mechanical anisotropy, weak bedding plane and vertical stress difference into account was established by the discrete element method to analyze distribution patterns of hydraulic fractures under different bedding densities, mechanical properties, and fracturing engineering parameters (including perforation clusters, injection rates and fracturing fluid viscosity). The research results show that considering the influence of the weak bedding plane and longitudinal stress difference, the interlayer stress difference 3-4 MPa in the study area can control the fracture height within the zone of stress barrier, and the fracture height is less than 40 m. If the influence of the weak bedding plane is not considered, the simulation result of fracture height is obviously higher. Although the opening of high-density bedding fractures increases the complexity of hydraulic fractures, it significantly limited the propagation of fracture height. By reducing the number of clusters, increasing the injection rate, and increasing the volume and proportion of high-viscosity fracturing fluid in the pad stage, the restriction on fracture height due to the bedding plane and vertical stress difference can be reduced, and the longitudinal propagation of fractures can be promoted. The fracture propagation model was used to simulate one stage of Well A in Fuling shale gas field, and the simulation results were consistent with the micro-seismic monitoring results.
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AM-AMPS-TAC polymers with different charge distribution are synthesized using acrylamide (AM), 2-acrylamido-2- methylpropanesulfonate (AMPS) and 3-acrylamidopropyl trimethylammonium (TAC) at different feed ratios by polymerization in solution. The salt-responsive behavior, reasons leading to salt-responsiveness, and effects of polymers molecular structure on salt-responsiveness are studied by laboratory experiments to find out the adaptability of the polymers. Rheology test under stepwise shear mode shows that the AM-AMPS-TAC polymers have salt responsiveness, and the closer the feeds of AMPS and ATC, the more significant the salt responsiveness will be. Conformation change of polymers molecular chain under salt stimulus is studied by turbidity test and micro-morphology analysis, and the responsive mechanism is further investigated by intrinsic viscosity test and copolymer composition analysis. Results indicate that the salt-responsive behavior of AM-AMPS-TAC polymers derives from the “curled to expanded” transition of chain conformation under salt stimulus, and this transition is led by the screening effect of salt which weakens polymers intramolecular ionic bond. Application in saturated saltwater drilling fluid shows that the AM90-AMPS5-TAC5 polymer has the best salt-tolerance and temperature-tolerance when used together with fluid loss controller PAC-Lv. The drilling fluid saturated with NaCl can maintain stable viscosity, good dispersion and low fluid loss for long time under 150 °C.
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Based on detailed core description and systematic joint test data, enrichment laws of continental shale oil have been examined deeply. Key technologies such as the identification and quantitative evaluation method for sweet spot, precise design and tracking of horizontal well trajectory, and the low-cost horizontal well volume fracturing technology of the whole process "slick water + quartz sand" for continental shale oil have been formed. The research results show that the enrichment of pure continental shale oil of the Paleogene Kong 2 Member in Cangdong Sag is controlled by predominant fabric facies and cross-over effect of retained hydrocarbons jointly; and there are four modes of shale oil enrichment, i.e. laminar felsic, laminar mixed, thin-layer limy dolomitic, and thick-layer limy dolomitic shales. The identification and evaluation method for shale oil sweet spots can predict sweet spots accurately. The precise trajectory design for sweet spot layer and tracking-trajectory optimization while drilling by considering geological and engineering factors have been proved effective by field application, with drilling rate of sweet spots reaching 100% and drilling rate of type I sweet spots reaching over 75%. The whole process "slick water + quartz sand" low cost volume fracturing has been proved effective in creating multi- stage fracture network in the horizontal section, and improved productivity greatly. It can lower the comprehensive engineering cost by 26.4%.
