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Based on analysis of newly collected 3D seismic and drilled well data, the geological structure and fault system of Baodao sag have been systematically examined to figure out characteristics of the transition fault terrace belt and its control on the formation of natural gas reservoirs. The research results show that the Baodao sag has the northern fault terrace belt, central depression belt and southern slope belt developed, among them, the northern fault terrace belt consists of multiple transition fault terrace belts such as Baodao B, A and C from west to east which control the source rocks, traps, reservoirs, oil and gas migration and hydrocarbon enrichment in the Baodao sag. The activity of the main fault of the transition belt in the sedimentary period of Yacheng Formation in the Early Oligocene controlled the hydrocarbon generation kitchen and hydrocarbon generation potential. From west to east, getting closer to the provenance, the transition belt increased in activity strength, thickness of source rock and scale of delta, and had multiple hydrocarbon generation depressions developed. The main fault had local compression under the background of tension and torsion, giving rise to composite traps under the background of large nose structure, and the Baodao A and Baodao C traps to the east are larger than Baodao B trap. Multiple fault terraces controlled the material source input from the uplift area to form large delta sand bodies, and the synthetic transition belt of the west and middle sections and the gentle slope of the east section of the F12 fault in the Baodao A transition belt controlled the input of two major material sources, giving rise to a number of delta lobes in the west and east branches. The large structural ridge formed under the control of the main fault close to the hydrocarbon generation center allows efficient migration and accumulation of oil and gas. The combination mode and active time of the main faults matched well with the natural gas charging period, resulting in the hydrocarbon gas enrichment. Baodao A transition belt is adjacent to Baodao 27, 25 and 21 lows, where large braided river delta deposits supplied by Shenhu uplift provenance develop, and it is characterized by large structural ridges allowing high efficient hydrocarbon accumulation, parallel combination of main faults and early cessation of faulting activity, so it is a favorable area for hydrocarbon gas accumulation. Thick high-quality gas reservoirs have been revealed through drilling, leading to the discovery of the first large-scale gas field in Baodo 21-1 of Baodao sag. This discovery also confirms that the north transition zone of Songnan-Baodao sag has good reservoir forming conditions, and the transition fault terrace belt has great exploration potential eastward.
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Since gas hydrate exists in three different forms at the same time such as pore filling, particle support and separate stratification, the calculation method of hydrate saturation using traditional shaly sand formation interpretation models is equivalent to considering only the simple case that hydrate exists as pore filling, and does not consider other complex states. Based on the analysis of hydrate resistivity experimental data and the general form of the resistivity-oil (gas) saturation relationship, the best simplified formula of hydrate saturation calculation is derived, then the physical meaning of the three items are clarified: they respectively represent the resistivity index-saturation relationship when hydrate particles are completely distributed in the pores of formation rocks, supported in the form of particles, and exist in layers, corresponding quantitative evaluation method of hydrate saturation is built. The field application shows that the hydrate saturation calculated by this method is closer to that obtained by sampling analysis. At the same time, it also provides a logging analysis basis for the effective development after hydrate exploration.
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The origin of dolomite in Shahejie Formation shale of Jiyang Depression in eastern China were studied by means of petrologic identification, compositional analysis by X-ray diffraction, stable carbon and oxygen isotopic composition, and trace element and rare earth element analyses. The results show that the development of dolomite is limited in the lacustrine organic rich shale of Shahejie Formation in the study area. Three kinds of dolomite minerals can be identified: primary dolomite (D1), penecontemporaneous dolomite (D2), and ankerite (Ak). D1 has the structure of primary spherical dolomite, high magnesium and high calcium, with order degree of 0.3-0.5, and is characterized by the intracrystalline corrosion and coexistence of secondary enlargement along the outer edge. D2 has the characteristics of secondary enlargement, order degree of 0.5-0.7, high magnesium, high calcium and containing a little iron and manganese elements. Ak is characterized by high order degree of 0.7-0.9, rhombic crystal, high magnesium, high calcium and high iron. The micritic calcite belongs to primary origin on the basis of the carbon and oxygen isotopic compositions and the fractionation characteristics of rare earth elements. According to the oxygen isotopic fractionation equation between paragenetic dolomite and calcite, it is calculated that the formation temperature of dolomite in the shale is between 36.76-45.83 ℃, belonging to lacustrine low-temperature dolomite. Based on the maturation and growth mechanism of primary and penecontemporaneous dolomite crystals, a dolomite diagenetic sequence and the dolomitization process are proposed, which is corresponding to the diagenetic environment of Shahejie Formation shale in the study area.
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Gas expansion caused by significant formation uplifting in the Sulige gas field in the Ordos Basin since Late Cretaceous and its effects on hydrocarbon accumulation have been investigated systematically based on comprehensive analysis of geochemical, fluid inclusion and production data. The results indicate that gas volume expansion since the Late Cretaceous was the driving force for adjustment and secondary charging of tight sandstone gas reservoirs in the Sulige gas field of the Ordos Basin. The gas retained in the source rocks expanded in volume, resulting in gas re-expulsion, migration and secondary charging into reservoirs, while the gas volume expansion in the tight reservoirs caused the increase of gas saturation, gas-bearing area and gas column height, which worked together to increase the gas content of the reservoir and bring about large-scale gas accumulation events. The Sulige gas field had experienced a two-stage formation process, burial before the end of Early Cretaceous and uplifting since the Late Cretaceous. In the burial stage, natural gas was driven by hydrocarbon generation overpressure to migrate and accumulate, while in the uplifting stage, the gas volume expansion drove internal adjustment inside gas reservoirs and secondary charging to form new reservoirs. On the whole, the gas reservoir adjustment and secondary charging during uplifting stage is more significant in the eastern gas field than that in the west, which is favorable for forming gas-rich area.
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Based on the data associated with cores, sidewall cores, casting thin sections, reservoir physical properties, conventional logging and imaging logging, the classification schemes of vertical reservoir units are proposed for the two types of Archaeozoic buried hills (exposed and covered ones) in the Bozhong Sag, Bohai Bay Basin. The geological characteristics and storage spaces of these reservoir units are described, and their identification markers in conventional and imaging log curves are established. The Archaeozoic metamorphic buried hills can be vertically classified into two primary reservoir units: weathering crust and inner buried hill. The weathering crust contains four secondary units, i.e., the clay zone, weathered glutenite zone, leached zone, disaggregation zone; and the interiors contain two secondary units, i.e., interior fracture zone and tight zone. In particular, the inner fracture zone was further divided into cataclasite belts and dense-fracture belts. It is proposed that the favorable reservoirs of exposed Archaeozoic metamorphic buried hills are mainly developed in four parts including weathered glutenite zone, leached zone, disintegration zone superposed with the cataclasite belt and the cataclasite belt of inner fracture zone, and are controlled by both weathering and tectonic actions. Favorable reservoirs in covered Archaeozoic metamorphic buried hills are mainly developed in the weathering crust superposed with the cataclasite belts and the cataclasite belts of inner fracture zone, and are mainly controlled by tectonic actions.
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Through the analysis of logging, field outcrops, cores and geochemical data, and based on the study of the relationships between sea level changes, sequence filling, paleo-geomorphy and lithofacies, the sequence lithofacies paleo-geography and evolution process of the Lower Permian Liangshan-Qixia Formation (Qixia Stage for short) in Sichuan Basin and its surrounding areas are restored. The Qixia Stage can be divided into three third-order sequences, in which SQ0, SQ1 and SQ2 are developed in the depression area, and SQ1 and SQ2 are only developed in other areas. The paleo-geomorphy reflected by the thickness of each sequence indicates that before the deposition of the Qixia Stage in the Early Permian, the areas surrounding the Sichuan Basin are characterized by “four uplifts and four depressions”, namely, four paleo-uplifts/paleo-lands of Kangdian, Hannan, Shennongjia and Xuefeng Mountain, and four depressions of Chengdu-Mianyang, Kangdian front, Jiangkou and Yichang; while the interior of the basin is characterized by “secondary uplifts, secondary depressions and alternating convex-concave”. SQ2 is the main shoal forming period of the Qixia Formation, and the high-energy mound shoal facies mainly developed in the highs of sedimentary paleo-geomorphy and the relative slope break zones. The distribution of dolomitic reservoirs (dolomite, limy dolomite and dolomitic limestone) has a good correlation with the sedimentary geomorphic highs and slope break zones. The favorable mound-shoal and dolomitic reservoirs are distributed around depressions at platform-margin and along highs and around sags in the basin. It is pointed out that the platform-margin area in western Sichuan Basin is still the key area for exploration at present; while areas around Chengdu-Mianyang depression and Guangwang secondary depression inside the platform and areas around sags in central Sichuan-southern Sichuan are favorable exploration areas for dolomitic reservoirs of the Qixia Formation in the next step.
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In this work, the Permian Longtan marine-continental transitional shale in the southeast of Sichuan Basin was taken as study object. Through petrology and geochemical analysis, lithofacies types of the marine-continental transitional shale were classified, and key controlling factors of physical properties, and gas content of the different shale lithofacies were analyzed. The research results show that the Longtan Formation marine-continental transitional shale in the study area has four types of lithofacies, namely, organic-lean calcareous shale, organic-lean mixed shale, organic-lean argillaceous shale, and organic-rich argillaceous shale, among which the organic-rich argillaceous shale is the most favorable lithofacies of the study area. The pore types of different lithofacies vary significantly and the clay mineral-related pore is the dominant type of the pore system in the study area. The main controlling factor of the physical properties is clay mineral content, and the most important factor affecting gas content is TOC content. Compared with marine shale, the marine-continental transitional shale has low values, wide distribution range and strong heterogeneity in TOC content, porosity, and pore structure parameters, but still contains some favorable layers with high physical properties and gas contents. The organic-rich clay shale deposited in tidal flat-lagoon system is most likely to form shale gas sweet spots, so it should be paid more attention in shale gas exploration.
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To reveal the development characteristics and distribution of gravity flow sedimentary system under micro-paleogeomorphic units of the Chang 7 Member of Triassic Yanchang Formation in the southwestern Ordos Basin, on the basis of the restoration of the paleogeomorphological form of the Chang 7 sedimentary period by the impression method, each micro paleogeomorphology unit was depicted in-depth, and the characteristics and development models of gravity flow deposits in the study area were studied in combination with outcrop, core, mud logging and log data. The results show that: (1) The paleogeomorphology in the Chang 7 sedimentary period was an asymmetrical depression, wide and gentle in the northeast and steep and narrow in the southwest. Three sub-paleogeomorphologic units were developed in the basin, including ancient gentle slope, paleo-slope and paleo-depression, and they can be further subdivided into eight micro-paleogeomorphologic units: bulge, groove, slope break belt, plain of lake bottom, deep depression of lake bottom, paleo-channel, paleo-ridge of lake bottom, and paleo-uplift of lake bottom. (2) There are 9 types of lithofacies and 4 types of lithofacies assemblages of Chang 7 Member. According to lithofacies composition and lithofacies vertical combination, the gravity flow deposit is further divided into 5 types of microfacies: restricted channel, unrestricted channel, natural levee, inter-channel, lobe. (3) Paleogeomorphology plays an important role in controlling sediment source direction, type and spatial distribution of sedimentary microfacies, genetic types and distribution of sand bodies in Chang 7 Member.
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Based on seismic and drilling data in the study area, the geological structure and kinematic process of the Termit rift basin were studied using seismic profile interpretation and balanced restoration to find out the dynamic mechanism of the basin. (1) The geological structure of the Termit Basin is represented as a narrow rift basin, with development of series of structural styles in extensional, extensional strike-slip and compressional stress setting. On plan, it is narrow in the north and wide in the south, and transitions from graben to half-graben from north to south; it features a graben controlled by the boundary faults in the north and a fault-overlapped half-graben in the south. (2) Before the Cretaceous, a series of hidden faults developed in the West African rift system, which laid the foundation for the development location and distribution direction of the Termit Basin; during the Cretaceous to Paleogene periods, the basin experienced two phases of rifting in Early Cretaceous and Paleogene, which controlled the initial structure and current structural shape of the basin respectively; during the Neogene to Quaternary, the basin was subjected to weak transformation. (3) In the Precambrian, the Pan-African movement gave rise to a narrow and long weak zone within the African plate, which provided the pre-existing structural conditions for the formation of the Termit Basin. In the Early Cretaceous, affected by the South Atlantic rifting, the Pan African weak zone was reactivated, resulting in the first stage of rifting and the basic structural framework of the Termit Basin. In the Paleogene, affected by the subduction and convergence of the Neo-Tethys Ocean, the African-Arabian plate extended in near E-W trending, and the Termit Basin experienced the second stage of rifting. The oblique extension in this period caused intense structural differentiation, and the current structural pattern of alternate uplifts and depressions took shape gradually.
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The targeted reservoir, which is referred as the first member of Cretaceous Qingshankou Formation in Gulong Sag, Songliao basin, is characterized by the enrichment of clay and lamellation fractures. Aiming at the technical challenge of determining oil saturation of such reservoir, nano-pores were accurately described and located through focused ion beam scanning electron microscopy and quantitative evaluation of minerals by scanning electron microscopy based on Simandoux model, to construct a 4D digital core frame. Electrical parameters of the shale reservoir were determined by finite element simulation, and the oil saturation calculation method suitable for shale was proposed. Comparison between the results from this method with that from real core test and 2D nuclear magnetic log shows that the absolute errors meet the requirements of the current reserve specification in China for clay-rich shale reservoir. Comparison analysis of multiple wells shows that the oil saturation values calculated by this method of several points vertically in single wells and multiple wells on the plane are in agreement with the test results of core samples and the regional deposition pattern, proving the accuracy and applicability of the method model.
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An intelligent prediction method for fractures in tight carbonate reservoir has been established by upgrading single-well fracture identification and interwell fracture trend prediction with artificial intelligence, modifying construction of interwell fracture density model, and modeling fracture network and making fracture property equivalence. This method deeply mines fracture information in multi-source isomerous data of different scales to reduce uncertainties of fracture prediction. Based on conventional fracture indicating parameter method, a prediction method of single-well fractures has been worked out by using 3 kinds of artificial intelligence methods to improve fracture identification accuracy from 3 aspects, small sample classification, multi-scale nonlinear feature extraction, and decreasing variance of the prediction model. Fracture prediction by artificial intelligence using seismic attributes provides many details of inter-well fractures. It is combined with fault-related fracture information predicted by numerical simulation of reservoir geomechanics to improve inter-well fracture trend prediction. An interwell fracture density model for fracture network modeling is built by coupling single well fracture identification and interwell fracture trend through co-sequential simulation. By taking the tight carbonate reservoir of Oligocene-Miocene AS Formation of A Oilfield in Zagros Basin of the Middle East as an example, the proposed prediction method was applied and verified. The single-well fracture identification improves over 15% compared with the conventional fracture indication parameter method in accuracy rate, and the inter-well fracture prediction improves over 25% compared with the composite seismic attribute prediction. The established fracture network model is well consistent with the fluid production index.
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To efficiently develop deep shale gas in southern Sichuan Basin, under the guidance of “extreme utilization” theory, a basic idea and solutions for deep shale gas development are put forward and applied in practice. In view of multiple influencing factors of shale gas development, low single-well production and marginal profit of wells in this region, the basic idea is to establish “transparent geological body” of the block in concern, evaluate the factors affecting shale gas development through integrated geological-engineering research and optimize the shale gas development of wells in their whole life cycle to balance the relationship between production objectives and development costs. The solutions are as follows: (1) calculate the gold target index and pinpoint the location of horizontal well drilling target, and shale reservoirs are depicted accurately by geophysical and other means to build underground transparent geological body; (2) optimize the drilling and completion process, improve the adaptability of key tools by cooling, reducing density and optimizing the performance of drilling fluid, the “man-made gas reservoir” is built by comprehensively considering the characteristics of in-situ stress and fractures after the development well is drilled; (3) through efficient management, establishment of learning curve and optimization of drainage and production regime, the development quality and efficiency of the well are improved across its whole life cycle, to fulfil “extreme utilization” development of shale gas. The practice shows that the estimated ultimate recovery of single wells in southern Sichuan Basin increase by 10%-20% than last year.
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On the basis of analyzing the fluid phase behavior during the transformation from gas reservoir to gas storage, a mathematical model and an experimental simulation method are established to describe the oil-gas phase behavior during the whole injection- production process of gas storage. The underground gas storage in the Liaohe Shuang 6 gas reservoir with oil ring is taken as a typical example to verify the reliability and accuracy of the mathematical model and reveal characteristics and mechanisms of fluid phase behavior. In the gas injection stage of the gas storage, the phase behavior is characterized by mainly evaporation and extraction and secondarily dissolution and diffusion of gas in the cap to oil in the oil ring of the reservoir; the gas in gas cap increases in light component content, decreases in contents of intermediate and heavy components, and increases in density and viscosity. The oil of the ring decreases in content of heavy components, increases in contents of light and intermediate components, decreases in density and viscosity, and increases in volume factor and solution gas oil ratio. In the stable operation stage of periodic injection-production of gas storage, the phase behavior shows that the evaporation and extraction capacity of injection gas in the cap to oil rim is weakened step by step, the phase behavior gradually changes into dissolution and diffusion. The gas in gas cap decreases in content of intermediate components, increases in content of light components slowly, and becomes lighter; but changes hardly in density and viscosity. The oil in the oil ring increases in content of heavy components, decreases in content of intermediate components, rises in density and viscosity, and drops in volume factor and solution gas oil ratio.
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Lower-phase microemulsions with core-shell structure were prepared by microemulsion dilution method. The high temperature resistant systems were screened and the performance evaluation experiments were conducted to clarify the spontaneous imbibition mechanisms in ultra-low permeability and tight oil reservoirs, and to direct the field microfracture huff and puff test of oil well. The microemulsion system (O-ME) with cationic-nonionic surfactant as hydrophilic shell, No.3 white oil as oil phase core has the highest imbibition recovery; its spontaneous imbibition mechanisms include: the ultra-low inter-facial tension and wettability reversal significantly reduce oil adhesion work to improve oil displacement efficiency, the nanoscale “core-shell structure” formed can easily enter micro-nano pores and throats to expand the swept volume, in addition, the remarkable effect of dispersing and solubilizing crude oil can improve the mobility of crude oil. Based on the experimental results, a microfracture huff and puff test of O-ME was carried out in Well YBD43-X506 of Shengli Oilfield. After being treated, the well had a significant increase of daily fluid production to 5 tons from 1.4 tons, and an increase of daily oil production to 2.7 tons from 1.0 ton before treatment.
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To clarify microscopic mechanisms of residual oil displacement by hydraulic pulsation wave, microscopic visualization experiments of hydraulic pulsation wave driving residual oil were carried out by using the microscopic visualization device of pulsating water drive. For the four types of residual oil left in the reservoir after water flooding, i.e. membrane, column, cluster, and blind end residual oils, hydraulic pulsation waves broke the micro-equilibrium of the interface by disturbing the oil-water interface, so that the injected water invaded into and contacted with the remaining oil in small pores and blind holes, and the remaining oil was pushed or stripped to the mainstream channel by deformation superposition effect and then carried out by the injected water. In the displacement, the pulsation frequency mainly affected the cluster and blind end remaining oil, and the hydraulic pulsation wave with a frequency of about 1 Hz had the best effect in improving the recovery. The pulsation amplitude value mainly affected the membrane and column residual oil, and the larger the amplitude value, the more remaining oil the hydraulic pulsation wave would displace. The presence of low intensity freewheeling pressure and holding pressure end pressure promoted the concentration of pulsating energy and greatly improve the recovery of cluster residual oil. The rise in temperature made the hydraulic pulsation wave work better in displacing remaining oil, improving the efficiency of oil flooding.
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One-dimensional gas injection storage building and one-cycle injection-production modeling experiment, and two-dimensional flat core storage building and multi-cycle injection-production modeling experiment were carried out using one-dimensional long core and large two-dimensional flat physical models to find out the effects of reservoir physical properties and injection-production balance time on reservoir pore utilization efficiency, effective reservoir capacity formation and capacity-reaching cycle. The results show that reservoir physical properties and formation water saturation are the main factors affecting the construction and operation of gas-reservoir type underground gas storage. During the construction and operation of gas-reservoir type gas storage, the reservoir space can be divided into three types of working zones: high efficiency, low efficiency and ineffective ones. The higher the reservoir permeability, the higher the pore utilization efficiency is, the smaller the ineffective working zone is, or there is no ineffective working zone; the smaller the loss of injected gas is, and the higher the utilization rate of pores is. The better the reservoir physical properties, the larger the reservoir space and the larger the final gas storage capacity is. The higher the water saturation of the reservoir, the more the gas loss during gas storage capacity building and operation is. Optimizing injection-production regime to discharge water and reduce water saturation is an effective way to reduce gas loss in gas storage. In the process of multiple cycles of injection and production, there is a reasonable injection-production balance time, further extending the injection-production balance period after reaching the reasonable time has little contribution to the expansion of gas storage capacity.
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Metallic nanoparticles and carbon nanomaterials have been extensively studied in enhanced oil recovery. Carbon nanotube (CNT)/TiO2 nanocomposite is synthesized and investigated in terms of contact angle, interfacial tension (IFT), emulsion stability, etc. Its performance in oil displacement in porous media is evaluated through glass micromodel experiment. The synthesized CNT/TiO2 is composed of TiO2-based nanocomposites and CNTs as reinforcement phase. TiO2 is the dominant crystalline phase, and TiO2 nanoparticles cover on the CNTs. CNT/TiO2 nanocomposite is able to alter the wetting conditions of the rock from strong oil-wet to hydrophilic conditions and effectively reduce the interfacial tension. CNT/TiO2 nanocomposite plays an effective role in stabilizing the Pickering emulsions, and even forms stable emulsions at high temperature as 90 ℃. For NaCl concentration of up to 2%, a stable emulsion can be formed even after 7 days. It is observed from glass micromodel experiments that the CNT/TiO2 nanofluid provides a higher recovery factor denoting its promising performance in enhanced oil recovery.
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Based on the structure, working principle, and working conditions of conductance water cut sensor, it is revealed that the early failure of the metal electrode of the sensor is due to the comprehensive influence of well fluid erosion, electrochemical corrosion, and oil pollution during its long-term service in the downhole. A technology for electrode surface treatment is proposed using boron-doped diamond (BDD) films to improve the service performance of the modified electrode. The hot wire chemical vapor deposition method was adopted to fabricate BDD film, the boron doping concentration and deposition time were optimized, and fluorination treatment was applied to improve the wear resistance, electrochemical corrosion resistance, and oleophobic property of the BDD film comprehensively. The results showed that BDD film with boron doping concentration of 6×10-3 exhibited high wear resistance and good electrochemical corrosion resistance, and endowed the modified electrode with superior erosion resistance and corrosion resistance. The friction coefficient and wear rate of BDD modified electrode were 92% and 78% lower than those of Invar alloy, also, the low-frequency impedance modulus value of the modified electrode was higher than 1×104 Ω·cm2. The BDD film prepared with a deposition time of 8 h had a favorable micro-nano structure owing to small grain size and uniform distribution. Such morphology was conducive to enhancing the oleophobic performance of the modified electrode, and its contact angle in the simulated well fluid was high to 102°. The engineering applicability of BDD film modified electrode under simulated working conditions indicated that, the modified electrode had excellent comprehensive performances of erosion resistance, electrochemical corrosion resistance and oil adhesion resistance, and can realize the long-term stable operation of the conductance water cut sensor under harsh downhole conditions.
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Through embedding modified nano-silica particles on the surface of polystyrene using the method of Pickering emulsion polymerization, a kind of nano/micro oleophobic agent named OL-1 was developed. The effects of OL-1 on the rock surface properties and its performance in inhibiting the oil phase imbibition into the rock were explored. The performance and mechanisms of OL-1 in improving the wellbore stability of shale gas wells were evaluated and analyzed. OL-1 could absorb on the surface of the shale core to form a membrane with a micro-nano two-stage roughness, making the surface energy of the core decrease to 0.13 mN/m and the contact angle of the white oil on the core surface increase from 16.39° to 153.03°. Compared with the untreated capillary tube, when immersed into 3# white oil, the capillary tube treated by OL-1 had a reversal of capillary pressure from 273.76 Pa to -297.71 Pa, and the oil imbibition height inside the capillary tube decreased from 31 mm above the external liquid level to 33 mm below the external liquid level. The amount of oil invading into the rock core modified by OL-1 decreased by 64.29% compared with the untreated one. The shale core immersed into the oil-based drilling fluid with 1% OL-1 had a porosity reduction rate of only 4.5%. Compared with the core immersed in the drilling fluid without OL-1, the inherent force of the core treated by 1% OL-1 increased by 24.9%, demonstrating that OL-1 could effectively improve the rock mechanical stability by inhibiting oil phase imbibition.
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Based on practices of CO2 flooding tests in China and abroad, the recovery factor of carbon dioxide capture, utilization in displacing oil and storage (CCUS-EOR) in permanent sequestration scenario has been investigated in this work. Under the background of carbon neutrality, carbon dioxide injection into geological bodies should pursue the goal of permanent sequestration for effective carbon emission reduction. Hence, CCUS-EOR is an ultimate development method for oil reservoirs to maximize oil recovery. The limit recovery factor of CCUS-EOR development mode is put forward, the connotation differences between it and ultimate recovery factor and economically reasonable recovery factor are clarified. It is concluded that limit recovery factor is achievable with mature supporting technical base for the whole process of CCUS-EOR. Based on statistics of practical data of CO2 flooding projects in China and abroad such as North H79 block CO2 flooding pilot test at small well spacing in Jilin Oilfield etc., the empirical relationship between the oil recovery factor of miscible CO2 flooding and cumulative CO2 volume injected is obtained by regression. Combined with the concept of “oil production rate multiplier of gas flooding, a reservoir engineering method calculating CO2 flooding recovery factor under any miscible degree is established by derivation. It is found that when the cumulative CO2 volume injected is 1.5 times the hydrocarbon pore volume (HCPV), the relative deviation and the absolute difference between the recovery percentage and the limit recovery factor are less than 5% and less than 2.0 percentage points respectively. The limit recovery factor of CCUS-EOR can only be approached by large pore volume (PV) injection based on the technology of expanding swept volume. It needs to be realized from three aspects: large PV injection scheme design, enhancing miscibility degree and continuously expanding swept volume of injected CO2.
