Reservoir Physical Properties Research Articles

Evaluation Model and Application of Shale Oil Production Efficiency Under Energy-Depleted Development Mode in Jimsar Sag

In order to reveal the shale oil production mechanism and production efficiency under the energy-depleted development mode, experiments on expulsion oil based on imbibition and elastic energy release under high temperature and pressure were carried out, and nuclear magnetic resonance on-line monitoring was used to observe the production characteristics of shale oil. The experimental results show that the imbibition-expulsion oil mainly occurs in the small-size pore-throat system. Under the condition of high temperature and pressure, the oil-expulsion efficiency is generally less than 2% affected by pore pressure, which is significantly different from the conventional imbibition experiment results. Although elastic-energy expulsion oil occurs in different sizes of pore-throat systems, the oil-expulsion efficiency in large size pore-throat systems is more sensitive to temperature. Overall, the total elastic-energy oil-expulsion efficiency is significantly positively correlated with reservoir physical properties, production differential pressure and temperature, and negatively correlated with crude oil viscosity. Comprehensively considering various geological factors affecting oil-expulsion efficiency, the shale oil production efficiency evaluation model under the energy-depleted development mode is constructed, and the movable oil porosity of shale oil development section in the study area is evaluated. The results show that there is a good positive correlation between movable oil porosity and oil production intensity. The movable oil porosity of dry layer is generally lower than 0.5% and that of poor oil layer is between 0.5% and 1.5%. When the movable oil porosity is between 1.5 and 2.5%, it can be determined as the type II oil layer, and for more than 2.5%, it is the type I oil layer. The single-well evaluation results show that the shale oil “sweet spots” of the Lucaogou Formation in Jimsar Sag are mainly distributed in P2l22−1∼ P2l22−3 and P2l12−1∼ P2l12−3, which is in good agreement with the current development status.

Pore structure and reservoir physical properties for effective development of tight sandstone gas: A case study from the Central Sichuan Basin, China

Several large gas fields have been found in the Central Sichuan Basin in recent years, with proven reserves of more than 100 × 10 9 m3. Among these, the tight sandstone gas in the Late Triassic Xujiahe Formation is a key target in the Sichuan Basin. The key to the discovery of high‐yield areas rich in tight sandstone gas is to determine the pore structures and the lower limits of effective physical properties of reservoirs that control natural gas accumulation. In this study, we investigate the Late Triassic second Member of the Xujiahe Formation (hereinafter referred to as the Xu2 Member) in the Central Sichuan Basin as an example. We analyse the distribution characteristics of pores and throats in the reservoirs and identify that the reservoir in the study area is mainly characterized by small pores and narrow throats. The physical properties of reservoirs in the area are mainly controlled by pore‐throat radius and the permeability–porosity ratio. Nuclear magnetic resonance analysis indicates that the irreducible water saturation is mostly more than 50% and is inversely correlated with the physical properties of reservoirs in the study area. Meanwhile, with an increase in the physical properties of reservoirs, the proportion of large pores increases and the irreducible water saturation rapidly decreases. According to the gas–water two‐phase seepage experiment, for reservoirs with good physical properties, the gas relative permeability significantly increases with an increase in gas saturation and the reservoir permeability has more significant effects. Where the reservoir permeability is less than 0.4 mD, the permeability of both gas phase and water phases is only less than 0.1, and the mobility of both gas and water is poor. Only when the reservoir permeability is more than 0.4 mD, can the gas relative permeability reach more than 0.3, and the water mobility is significantly inhibited. In this case, favourable results can be achieved from the natural gas development. As verified by the development of the tight sandstone reservoirs in the Xu2 Member in Central Sichuan Basin, the lower limits of physical properties allowing for effective natural gas development include the reservoir permeability of more than 0.1 mD (preferably more than 0.2 mD) and the reservoir porosity of greater than 6%–7%.

Geological Characteristics and Controlling Factors of Enrichment of Deep Shale Gas in the East Weiyuan–North Rongchang Area, Sichuan Basin, China

The southern Sichuan Basin is the core area of China’s efficient development of deep shale gas (burial depth greater than 3,500 m). Reservoir geological characteristics determine whether shale gas can be preserved, enriched, and produced. Taking the Long 11 sub-member of the Wufeng Formation of the Upper Ordovician and the Longmaxi Formation of the Lower Silurian in the East Weiyuan–North Rongchang area as an example, we used the core, logging, production test, and other data, combining X-ray diffraction analysis, LECO Total Organic Carbon (TOC)-S analysis, optical microscopy, and argon ion polishing field-emission scanning electron microscopy, to study the shale mineral composition, geochemistry, reservoir space, pore structure characteristics, and reservoir physical properties. The following results were obtained: 1) The brittle mineral content, organic matter maturity, and TOC content are high, gradually increase from top to bottom, and reach their maxima at small layer 1 of Long 11. 2) Organic pores, inorganic pores, and fractures are important reservoir spaces, among which organic pores and fractures are important seepage channels for shale gas. 3) The shale pore structure revealed by electron microscopy shows that the pore structure in target layers can be divided into four types: unimodal type (mainly organic pores), bimodal type (both organic and inorganic pores), monoclinic type I (mainly organic pores), and monoclinic type II (mainly inorganic pores). The pore morphology is complex, and circular and oval shapes predominate. 4) Sedimentary facies are the main factor controlling the enrichment of shale gas, and the development of fractures is the key to obtaining high yields of shale gas. 5) The class I favorable target area is mainly distributed in wells W206, W206H1, R234H, and R233H and areas to its south, and some areas in the east of the study area.

Characteristics and Controlling Factors of the Chang 8 Oil Reservoir in the Yanchi Area of the Ordos Basin: A Case Study of Well G20

In the Ordos Basin, the Chang 8 oil reservoir of the Triassic Yanchang Formation is the main target of oil exploration and development and there are many factors affecting the hydrocarbon accumulation. Well G20 is an important exploration well in the Yanchi area in the northwestern part of the basin, and the core of the Chang 8 reservoir was sampled and tested to determine the source rocks, trace element composition, mineral composition, reservoir physical properties, and oil-bearing properties. The results show that the rock retrieved exhibits delta plain subfacies; the range of the Chang 8 water body was large, with a gentle slope, and the climate was relatively dry. These findings suggest that this reservoir was deposited in an environment in which sedimentary sand body could easily form. The Chang 8 sandstone reservoir pores are dominated by intergranular pores and feldspar intragranular dissolution pores, indicating that the Chang 8 reservoir is a low-porosity and low-permeability reservoir. Chang 7 source rocks from this area have a type I-II1 hydrocarbon-generating potential, with an average total organic carbon (TOC) content of 5.99% and vitrinite reflectance (Ro) value of 0.48%. Combined with the regional sedimentary evolution, tectonic movement, and reservoir distribution, it is considered that due to the lack of lithologic traps or low-amplitude structural traps, G20 produced water in well testing. The Chang 8 oil reservoir in the Yanchi area can be divided into structural reservoirs and structural-lithologic reservoirs. The conventional oil and gas reservoir exploration ideas of “thick sand belt” and “reservoir sweet spot” are not applicable here. The lithology traps or low-amplitude structural traps and areas with good preservation conditions are the main directions for the next phase of exploration in the northwestern part of the Ordos Basin.

Reaction mechanism and reservoir simulation study of the high-temperature nitrogen injection in-situ oil shale process: A case study in Songliao Basin, China

China’s oil shale reserves are 739.1 billion tons and 45 per cent of which are in Songliao Basin. Therefore, a pilot project is conducted in Songliao Basin, aimed at technical preparation for commercial in-situ oil shale processes production. Because N2 is readily accessible and has no damage to the formation, the high-temperature nitrogen injection in-situ conversion process (HNICP) is the most basic convection heating technique, which is used in the pilot project. In this study, the Wellington reaction model is adjusted to describes the pyrolysis behavior and characteristics of shale in Songliao Basin, China. Based on the geological data and production date of the pilot project in Songliao Basin, a simulation model matching the production test scheme is established to investigate subsequent production performance and the evolution of reservoir physical properties for 550 days. Finally, the effect of injection temperature, total organic carbon (TOC), and enclosing area on the recovery factor is analyzed. The results show that the oil production rate can be divided into four stages for the HNICP of oil shale. In the third stage, prechar accumulation is very severe in the main fracture. However, the prechar accumulation relieves the heat short problem in the main fracture. The high temperature is beneficial to the production of oil, HC, and prechar. The formation plugging in the low TOC shale formation is more serious. Because of the spontaneous imbibition of oil in the formation away from the main fracture, the small enclosing area is beneficial to the production of oil.

Water film thickness of tight reservoir in Fuyu oil layer of Cretaceous Quantou Formation in Songliao Basin and its influence on the lower limit of seepage

The water film thickness in tight sandstone reservoir is critical to determine the lower limit of both flow pore-throat radius and the physical property of the reservoir. In order to study the effect of water film thickness on fluid flow capacity, firstly, through molecular dynamics simulations, the adsorption behavior of different minerals on water molecules was simulated, and the adsorption characteristics of different minerals on water molecules were clarified. Secondly, a new method for calculating the water film thickness of bound water was established by comprehensively using three experimental methods: high-pressure mercury injection experiment (HPMI), cryogenic nitrogen adsorption experiment, and centrifugal-nuclear magnetic resonance (NMR). The lower limit of the flow pore-throat radius and the physical property of the tight reservoir were determined more accurately by improving the previous calculation methods. The results demonstrated that the adsorption of minerals to water molecules mainly formed a binding force through microscopic forces such as electrostatic force and Van Der Waals Force, in which Van Der Waals Force repels water molecules while electrostatic force absorbs water molecules. Different minerals have different adsorption capacities for water molecules. According to the established formula, the bound water film thickness of different samples is different. Then, the water film thickness of the Fuyu oil layer in the Songliao Basin can be calculated to be approximately 19.651 nm. By improving the formula used by the predecessors to determine the lower limit of physical property, it could be accurately determined that the lower limit of flow pore-throat radius was 26.751 nm, and the lower limit of permeability and porosity was 0.047mD and 9.87%, respectively. This method has both a strong theoretical basis and experimental data support. Thus, it can be generalized to a certain extent.

Formation Time and Material Source of Carbonate Cements in Permian Sandstone in the Ordos Basin, Western of China

Abstract Carbonate cements are an important type of cement in Permian tight gas reservoirs in the Ordos Basin. Moreover, the distribution of carbonate cements in sandstone provides an important basis for studying the fluid mechanism and genesis of cements and a scientific basis for investigating the physical properties of reservoirs and the underground distribution of oil and gas. Based on the observations of thin sections and temperature measurements of fluid inclusions, this study concludes that the carbonate cements in the study area are dominated by calcite and ferrous calcite and divided into three phases, where the latter two phases are dominant. The material source of carbonate cements is obtained via the thermal simulations of gold tubes in source rocks, temperature of fluid inclusions in carbonate cements, composition of fluid inclusions in quartz overgrowth, and analysis of carbon and oxygen isotopes. Results show that phase I calcite may be directly precipitated from the supersaturation of pore water by Ca2+ and CO32−. The CO32− in the phase II calcite and ferrous calcite stems from the CO2 generated in the hydrocarbon generation process of organic matter, while the CO32− in phase III calcite stems from the CO2 generated in the decarboxylation of organic acids. Ca2+ is derived from the dissolution of early carbonate cements in sandstone and conversion of smectite into illite in mudstone. The Permian sandstone in the Yishan Slope at the center of the basin is close to the source rock, and the carbon isotopic value of the carbonate cements, which is dominated by organic carbon, ranges between −7.5‰ and −19.0‰. However, the Permian sandstone in the Tianhuan Depression at the edge of the basin is far away from the source rock, with its carbon isotope value ranging from −5.9‰ to −8.7‰, which is probably due to the insufficient supply of organic carbon and a small amount of early inorganic CO2 remains in the reservoir.

Study on the logging response characteristics and the quantitative identification method of solid bitumen at different thermal evolution stages

Solid bitumen is the intermediate products during the oil and gas generation, and widely exists in petroliferous basins all over the world. Besides damaging the reservoir physical properties, solid bitumen affects the logging parameters and is hard to be identified by the conventional logging method. In this study, two different thermal evolution stages of solid bitumen, separately from the Devonian outcrop profile and the Well ST3 in the northwestern Sichuan Basin, are taken as an example. Through a series of analyses on the porosity, permeability, resistivity, S-wave time difference, P-wave time difference and nuclear magnetic resonance (NMR) before and after bitumen dissolution, the logging response characteristics of solid bitumen at different thermal evolution stages are clarified, and the logging quantitative identification method of solid bitumen is established. The results are as below: (1) The solubility of solid bitumen is linearly correlated with the increment of porosity, permeability, P-wave time difference and S-wave time difference, and exponentially correlated with the decrement of resistivity. (2) Under the equal solid bitumen content and with the increase of thermal evolution, the influence of solid bitumen on porosity and permeability gradually decreases, while the influence on acoustic time difference and resistivity gradually increases. (3) Two kinds of NMR logging interpretation models for bitumen reservoir are established based on the NMR response characteristics of solid bitumen at different thermal evolution stages. The solid bitumen from low thermal evolution stage has a strong response in NMR, while that from high thermal evolution stage is otherwise. The Peak 1 (0.1 ms – 10 ms) of the T2 spectrum can respond to most of the low thermal evolution stage solid bitumen, but just a few of the high thermal evolution stage solid bitumen. (4) The NMR logging quantitative calculation methods on different thermal evolution stage solid bitumen are established respectively to solve the difficult issues of quantitative identification of solid bitumen. All the researches above have important guiding significance for the logging quantitative calculation of solid bitumen and the selection of effective oil/gas test layers.

Polymer-Surfactant Flooding in Low-Permeability Reservoirs: An Experimental Study.

Chemical flooding technology has been widely applied in medium- and high-permeability reservoirs. However, it is rarely applied in low-permeability reservoirs, which is mainly limited by reservoir physical properties, chemical agents, injection capacity, and so forth. In this paper, a novel chemical formula used in low-permeability reservoirs was developed. In response to the low-permeability reservoir geological characteristics, fluid properties, and water flooding development of the target block, some experimental studies and field project studies of polymer–surfactant flooding were carried out. The surfactant structure and polymer molecular weight were determined from laboratory experiments. The polymer–surfactant binary system was synthesized. It had good injectivity in low-permeability reservoirs, and its oil recovery efficiency increased over 10% in the laboratory experiment. The result was higher than that of single chemical flooding. After field implementation, initial results have been achieved with an increase in injection pressure. The chemical formula can effectively alleviate intra-layer and inter-layer contradictions in the reservoir. The project has increased oil output by 77,700 t and the recovery factor by 3.5%. The experience and lessons were of great significance for the development of chemical flooding in high-temperature, high-salinity, and low-permeability reservoirs.

Genetic mechanism and grading assessment of the glutenite reservoirs in the Eocene Shahejie Formation, Chezhen Sag, Bohai Bay Basin

Abundant oil potential has been confirmed in the Eocene Shahejie Formation (Es) in the Chezhen Sag, but the genetic mechanism of its reservoir has not been fully understood. Based on core observation, thin-section identification, scanning electron microscopy (SEM), X-ray diffraction, and formation pressure measurement, the factors controlling the quality of glutenite reservoirs in the Shahejie Formation in the Chezhen Sag were revealed. The petrophysical structure, depositional facies, diagenesis, and formation overpressure jointly control the development and evolution of glutenite reservoirs. Reservoirs with high composition maturity exhibit better physical properties. Depositional facies control the development of high- and poor-quality reservoirs but have little influence on the physical properties of medium-quality reservoirs. Compaction is the main factor for reducing reservoir porosity during burial, and the cementation of carbonate and clay minerals affects the reservoir quality to some extent. Each secondary structural zone shows different dissolution models. The reservoirs in the steep slope zone are in a closed system with weak dissolution, hardly contributing to improving the reservoir porosity. The dissolution of reservoirs in the depression zone has been enhanced; however, the migration of dissolution products is restricted because of the closed reservoirs, causing the redistribution of pore space and limited contribution to improving the physical properties. The reservoir in the gentle slope zone is in an open system with a shallow buried depth, and severe dissolution can effectively improve the reservoir's physical properties. A grading assessment scheme is proposed based on the depositional facies, diagenesis, and formation overpressure, and favorable exploration zones are predicted. The western part of the gentle slope zone in the upper part of the Es4 member and the eastern part of the steep slope zone in the lower part of the Es3 member of the Chezhen Sag are the principal target areas for exploration.

Compatibility characteristics of fracturing fluid and shale oil reservoir: A case study of the first member of Qingshankou Formation, northern Songliao Basin, Northeast China

Hydraulic fracturing is currently one of the most economical and effective means to develop shale oil resources. However, the fracturing effects in shale oil wells vary significantly. The compatibility between the fracturing fluid and the shale oil reservoir is one of the important factors affecting the fracturing stimulation. In this study, a series of physical simulation experiments were carried out to reveal the changes in the physical properties and surface properties of a shale oil reservoir using different fracturing fluids (guar gum fracturing fluid, slick hydraulic fracturing fluid, and formation water fracturing fluid). The dynamic flowback process of different fracturing fluids was visualized and quantitatively characterized using the NMR technology. The results indicate that with the increase in soaking time in the formation water fracturing fluid, the hysteresis coefficient of the shale increased. The increasing ink-bottle pores resulted in worse pore connectivity and physical properties of reservoir. The shale undergoes strong water sensitivity damage and strong stress sensitivity, which is not conducive to the stability and long-term effects of shale oil production. After injecting the guar gum fracturing fluid, the pore connectivity of the shale is enhanced, and the stress sensitivity is the weakest. The particle suspension and dispersion system of the guar gum fracturing fluid is the most stable, which greatly avoids reservoir damage caused by solid particle migration blocking in the pore throat. In addition, it can effectively inhibit shale hydration and expansion, and achieve the highest displacement flowback efficiency, which is more suitable for the fracturing operation of shale oil reservoirs in the study area. The effects of the slippery hydraulic fracturing fluid on shale are between the above two fracturing fluids. The research results are of great significance in guiding the fracturing operation of shale oil wells in the northern Songliao Basin.

Estimating melt fraction in silicic systems using Bayesian inversion of magnetotelluric data

The location, volume and physical states of magma reservoirs are primary controls on the eruptive behavior of volcanic systems. Fundamental to understanding and monitoring these systems is the ability to identify reservoir size and physical properties, in particular melt fraction which plays an important role in the rheology and stability of a magmatic system. Large silicic volcanic eruptions in the geological record suggest that extensive pockets of melt-rich silicic magma must exist in the subsurface but such melt pockets have not been detected by geophysics. This has led to the question of whether the reservoirs that feed large volcanic eruptions are only melt-rich for a short time and thus would only be detected by geophysics shortly prior to an eruption. Magnetotelluric data measure the electrical resistivity of the subsurface and are sensitive to subsurface fluids and partial melts making it a powerful tool for imaging subvolcanic magma reservoirs. This study examines the ability for magnetotelluric data to accurately estimate melt fraction using both stochastic Bayesian inversion and deterministic regularized inversion. Results from synthetic modelling indicate that magnetotelluric data are best able to predict the melt fraction for the thick melt-rich layer using both inversion methods, though both methods under-estimate the true amount of melt. In addition, magnetotelluric data can accurately detect changes in melt fraction from crystal-rich mush (0.1 melt fraction) to melt-rich magma (0.9 melt fraction) for thick layers. Thickness is a key parameter which provides a method to assess the total volume of melt present, but it is difficult to estimate using smooth regularized inversions. Fixed-dimension Bayesian inversions provide estimates of layer thickness and their uncertainties and it is shown that estimates of total volume of melt are more accurate for both thin (0.2 km) and thick (1 km) layers than individual estimates of melt fraction or thickness alone. The melt fraction of the thin melt-rich layer is under-estimated using both the deterministic inversion method and the most probable solution of the Bayesian inversion. The Bayesian distribution of solutions has long tails which includes the true solution and better represents the uncertainty of the modelled parameters. As we consider past large melt-rich caldera eruptions at Taupo (New Zealand), Toba (Indonesia), Yellowstone and Long Valley (USA), our analysis suggests that thin melt-rich, potentially eruptible zones involved in large (e.g. >500 km3) eruptions could be systematically misinterpreted as thicker non-eruptible crystal-rich mush zones. Testing the sensitivity of MT to detect melt accumulation in active magmatic systems has important implications for volcanic hazard assessment and the use of Bayesian inversions allows for a better understanding of the range of possible interpretations.

Research on Gas Drainage Laws of SRV-fractured Horizontal Wells in Different Types of Tight Gas Reservoirs

Horizontal well and large-scale hydraulic fracturing are the main technical means for tight gas development at present. However, tight gas reservoirs are characterized by strong heterogeneity, and different types of gas Wells have different production characteristics and pressure propagation laws. In view of the above problems, based on the physical characteristics and reservoir reconstruction evaluation of tight gas reservoir in GAS Reservoir A in Sichuan Basin, three types of reservoir hydraulic fracture models and numerical simulation models were generated by using numerical simulation method, and the production dynamic prediction and pressure wave propagation law were studied. The simulation results show that: (1) In the beginning of production, the deflated area is mainly hydraulic fracture reconstruction area, and the drainage radius of all kinds of gas Wells expands at similar speed; (2) When the drainage range is expanded in the untransformed area, the dimensionless drainage radius expansion speed of gas well is positively correlated with the reservoir physical property. The dimensionless drainage radius and drainage area of class I and II horizontal Wells are relatively faster, while that of Class III Wells is slightly slower.

Analysis on the current situation of water injection development in a block of sunenoer Oilfield

Surennuoer oilfield is located in the north of Wuerxun Sag, beierhu depression, Haita basin. This paper introduces the geological characteristics of the oilfield from the aspects of oilfield structure and reservoir physical properties; On the basis of carefully combining the dynamic and static data, this paper analyzes the dynamic development characteristics of the oilfield since it was put into development. At the same time, combined with its characteristics, it summarizes the main understanding of the current oilfield development, which provides reference experience for the future water injection development adjustment of low permeability oilfields, and has certain reference significance for the efficient and rapid development of similar oilfields.

Genetic Mechanism of Multi-Stage Carbonate Minerals and its Control on Reservoir Physical Properties in Dolomitic Shales

Genetic Mechanism of Multi-Stage Carbonate Minerals and its Control on Reservoir Physical Properties in Dolomitic Shales

Statistical analysis of static and dynamic predictors for seismicb-value variations in the Groningen gas field

AbstractWe perform statistical analyses on spatiotemporal patterns in the magnitude distribution of induced earthquakes in the Groningen natural gas field. The seismic catalogue contains 336 earthquakes with (local) magnitudes above$1.45$, observed in the period between 1 January 1995 and 1 January 2022. An exploratory moving-window analysis of maximum-likelihoodb-values in both time and space does not reveal any significant variation in time, but does reveal a spatial variation that exceeds the$0.05$significance level.In search for improved understanding of the observed spatial variations in physical terms we test five physical reservoir properties as possibleb-value predictors. The predictors include two static (spatial, time-independent) properties: the reservoir layer thickness, and the topographic gradient (a measure of the degree of faulting intensity in the reservoir); and three dynamic (spatiotemporal, time-dependent) properties: the pressure drop due to gas extraction, the resulting reservoir compaction, and a measure for the resulting induced stress. The latter property is the one that is currently used in the seismic source models that feed into the state-of-the-art hazard and risk assessment.We assess the predictive capabilities of the five properties by statistical evaluation of both moving window analysis, and maximum-likelihood parameter estimation for a number of simple functional forms that express theb-value as a function of the predictor. We find significant linear trends of theb-value for both topographic gradient and induced stress, but even more pronouncedly for reservoir thickness. Also for the moving window analysis and the step function fit, the reservoir thickness provides the most significant results.We conclude that reservoir thickness is a strong predictor for spatialb-value variations in the Groningen field. We propose to develop a forecasting model for Groningen magnitude distributions conditioned on reservoir thickness, to be used alongside, or as a replacement, for the current models conditioned on induced stress.

Empirical mode decomposition-refined composite multiscale dispersion entropy analysis and its application to geophysical well log data

Oil and gas exploration activities often face great challenges due to the nonlinear behavior of the reservoir's physical properties, which is commonly defined as “heterogeneity”. Currently, well log data analysis techniques are a novel approach to unravel such nonlinear behavior, because well log data incorporates considerable geological information that determines reservoir property. However, the current complexity analysis techniques face two challenges: 1) the spatiotemporal multiscale nature of complex geological systems and 2) the superposition of the trends in the geophysical well log data on the analysis results. To fill the research gap, we propose an empirical mode decomposition-refined composite multiscale dispersion entropy analysis (EMD-RCMDEA) to eradicate trends and obtain the complexity results with spatiotemporal characteristics. The proposed method produces more accurate results, and its effectiveness, stability, and efficiency are also verified by the simulation signals and the gamma-ray (GR) well log signals. Compared to previous refined composite multiscale entropy analysis (RCMSEA), the EMD-RCMDEA enhances the stability by 69.3% and efficiency by 53.5%. Additionally, using the GR well log data for reservoirs, this method is also applied to explore the heterogeneity of strata with diverse depositional environments and different composite patterns and acquire the following results. 1) The EMD-RCMDEA values of the GR well log data are positively correlated with the heterogeneity of the strata. 2) The reservoir developed in a delta-front depositional environment has the strongest heterogeneity. 3) The heterogeneity of the composite patterns is much stronger than that of the single heterogeneity patterns. 4) Among the heterogeneities of the composite patterns, the pattern consisting of different facies is stronger than that for single facies. • A novel heterogeneity evaluation method is proposed based on EMD-RCMDEA. • New metrics for evaluating the stability of the multiscale entropy method are proposed. • The EMD-RCMDEA eliminates the drawback of multiscale entropy methods. • Trends superimposed in signals affect complexity analysis results. • The EMD-RCMDEA values of GR well log data positively correlate with reservoir heterogeneity.

High-pressure heavy oil saturation treatment method of outcrop core based on loose sandstone heavy oil reservoirs

The unconsolidated sandstone heavy oil reservoir is dominated by heterogeneous elastic-plastic reservoir with complex structure. The core demand is large in the study of reservoir lithology and physical properties. Although the high-cost freezing and encapsulation processes are used in the process of coring site and indoor processing, they are still easy to damage in the process of extracting cores. Moreover, the physical parameters of ordinary artificial cores are too different from those of producing cores to obtain accurate lithology and physical parameters. So, replacing the production cores with outcrop cores may become an important method to study the physical parameters of reservoirs. In this paper, the micro-velocity displacement method and saturated heavy oil method are used to study the lithology and physical property parameters of outcrop cores. The results show that compared with those of producing cores, the rock mechanics parameters of outcrop cores after high-pressure heavy oil saturation treatment are basically consistent with those of field cores. Therefore, it can be used to replace the core to study the physical parameters of rocks in special cases.

A Comparison of Shale Gas Fracturing Based on Deep and Shallow Shale Reservoirs in the United States and China

China began to build its national shale gas demonstration area in 2012. The central exploration, drilling, and development technologies for medium and shallow marine shale reservoirs with less than 3,500 m of buried depth in Changning-Weiyuan, Zhaotong, and other regions had matured. In this study, we macroscopically investigated the development history of shale gas in the United States and China and compared the physical and mechanical conditions of deep and shallow reservoirs. The comparative results revealed that the main reasons for the order-ofmagnitude difference between China’s annual shale gas output and the United States could be attributed to three aspects: reservoir buried depth, reservoir physical and mechanical properties, and engineering technology level. The current engineering technology level of China could not meet the requirements of increasing production and reducing costs for deep shale gas reservoirs; they had reached the beneficial threshold development stage and lacked the capacity for large-scale commercial production. We identified several physical and mechanical reasons for this threshold development stage. Deep shale reservoirs were affected by the bedding fracture, low brittleness index, low clay mineral content, and significant areal differences, as well as by the transformation from elasticity to plasticity, difficulty in sanding, and high mechanical and strength parameters. Simultaneously, they were accompanied by six high values of formation temperature, horizontal principal stress difference, pore pressure, fracture pressure, extension pressure, and closure pressure. The key to deep shale gas horizontal well fracturing was to improve the complexity of the hydraulic fracture network, form adequate proppant support of fracture surface, and increase the practical stimulated reservoir volume (SRV), which accompanied visual hydraulic discrete network monitoring. On this basis, we proposed several ideas to improve China’s deep shale gas development involving advanced technology systems, developing tools, and supporting technologies in shale gas exploration and development in the United States. These ideas primarily involved stimulation technologies, such as vertically integrated dessert identification and optimization, horizontal well multistage/multicluster fracturing, staged tools development for horizontal wells, fractures network morphology monitoring by microseismic and distributed optical fiber, shale hydration expansion, soak well, and fracturing fluid flow back. China initially developed the critical technology of horizontal well large-scale and high-strength volume fracturing with a core of “staged fracturing with dense cutting + shorter cluster spacing + fracture reorientation by pitching + forced-sand addition + increasing diameter perforating + proppant combination by high strength and small particle size particles”. We concluded that China should continue to conduct critical research on theories and technical methods of horizontal well fracturing, suitable for domestic deep and ultra-deep marine and marine-continental sedimentary shale, to support and promote the efficient development of shale gas in China in the future. It is essential to balance the relationship between the overall utilization degree of the gas reservoir and associated economic benefits and to localize some essential tools and supporting technologies. These findings can contribute to the flourishing developments of China’s deep shale gas.

Study on reservoir physical properties of Nadanhada terrane

The Nadanhada terrane is basically a large tectonic sedimentary hybrid, which is an accretionary complex belt formed by the subduction of the Pacific plate to the Eurasian plate. Through field geological survey, paleomagnetic analysis, paleontological analysis and microscopic observation of core slices, its structural and petrological characteristics were studied. The results show that the accretionary complex is mainly composed of 7 parts, including undeformed sedimentary rocks, shear deformed sedimentary rocks, shear deformed volcanic rocks, turbidites, deformed siliceous rocks, limestone blocks and basic ultrabasic rocks. Shear deformation structures of deformed sedimentary rocks and volcanic rocks are developed. The sediment grain size of the Lower Cretaceous reservoirs in each basin in the northern region is relatively coarse, the sorting is moderately deviated, and the rounding is poor, mainly secondary to angular. The grain size of the lower Cretaceous sediments of each basin in the southern region is relatively fine, with coarse, medium and fine sandstones, but mainly medium fine sandstones, with medium sorting preference and sub angular to sub round roundness.