Low-permeability Sandstone Research Articles

A three dimensional visualized physical simulation for natural gas charging in the micro-nano pore system

A micro-nano pore three-dimensional visualized real-time physical simulation of natural gas charging, in-situ pore-scale computation, pore network modelling, and apparent permeability evaluation theory were used to investigate laws of gas and water flow and their distribution, and controlling factors during the gas charging process in low-permeability (tight) sandstone reservoir. By describing features of gas-water flow and distribution and their variations in the micro-nano pore system, it is found that the gas charging in the low permeability (tight) sandstone can be divided into two stages, expansion stage and stable stage. In the expansion stage, the gas flows continuously first into large-sized pores then small-sized pores, and first into centers of the pores then edges of pores; pore-throats greater than 20 μm in radius make up the major pathway for gas charging. With the increase of charging pressure, movable water in the edges of large-sized pores and in the centers of small pores is displaced out successively. Pore-throats of 20–50 μm in radius and pore-throats less than 20 μm in radius dominate the expansion of gas charging channels at different stages of charging in turn, leading to reductions in pore-throat radius, throat length and coordination number of the pathway, which is the main increase stage of gas permeability and gas saturation. Among which, pore-throats 30–50 μm in radius control the increase pattern of gas saturation. In the stable stage, gas charging pathways have expanded to the maximum, so the pathways keep stable in pore-throat radius, throat length, and coordination number, and irreducible water remains in the pore system, the gas phase is in concentrated clusters, while the water phase is in the form of dispersed thin film, and the gas saturation and gas permeability tend stable. Connected pore-throats less than 20 μm in radius control the expansion limit of the charging pathways, the formation of stable gas-water distribution, and the maximum gas saturation. The heterogeneity of connected pore-throats affects the dynamic variations of gas phase charging and gas-water distribution. It can be concluded that the pore-throat configuration and heterogeneity of the micro-nanometer pore system control the dynamic variations of the low-permeability (tight) sandstone gas charging process and gas-water distribution features.

Depositional and provenance records of the Lower Permian sandstones from Sishichang area, northwestern margin of the Tarim Basin, NW China

Depositional and provenance records of the Lower Permian sandstones from Sishichang area, northwestern margin of the Tarim Basin, NW China

Natural gas development prospect in Changqing gas province of the Ordos Basin

At present, natural gas accounts for a low proportion in China's primary energy consumption structure and is highly dependent on foreign sources. Changqing gas province of the Ordos Basin where PetroChina Changqing Oilfield Company (referred to as Changqing Oilfield) is located is one of China's four major natural gas production bases. It bears the important responsibility for ensuring people's livelihood and promoting the healthy development of society economy. In recent years, Changqing Oilfield actively implements national instructive spirit on vigorously promoting domestic oil and gas exploration and development strength and formulates the secondary acceleration development strategies. Its annual natural gas production in 2020 reaches 448.5 × 108 m3 and oil and gas equivalent exceeds 6000 × 104 t, tamping its important position of “Western Daqing” in this industry. In order to further promote the continuous stable production and realize the goal of quality and efficiency improvement in Changqing gas province, this paper analyzes the situations and challenges of natural gas development in this gas province, prepares the development technological countermeasures and forecast the natural gas development prospect. And the following research results are obtained. First, the natural gas exploration and development in Changqing gas province is divided into four stages and the main technologies for the development of low-permeability carbonate gas reservoir, low-permeability sandstone gas reservoir and tight sandstone gas reservoir are formed. Second, the natural gas development in Changqing gas province faces six challenges, such as low reserve production degree, sharp decline of production rates and complex distribution of remaining undeveloped reserves of developed gas fields. And twenty-six development technological countermeasures are put forward correspondingly, such as well pattern thickening, extension and reserve increase, secondary production layer potential tapping and fine gas well management. Third, the development direction and goal of natural gas development in Changqing gas province is to pay equal attention to the stable production of old gas fields and the production increase of new areas and carry out conventional gas and unconventional gas research simultaneously. In conclusion, the annual natural gas production of Changqing gas province will maintain a sound momentum of steady growth and will exceed 500 × 108 m3 at the end of the 14th Five-Year Plan and maintain at a stable level for a long term, which is conducive to the optimization of domestic energy consumption structure and realization of “carbon peak and carbon neutrality”.

Quantitative investigation of phase characteristic effects on CO2 breakthrough pressures in unsaturated Low-Permeability sandstone

Study on CO2 breakthrough pressures in caprocks under formation temperatures (T) and pressures (P), which can make CO2 in gaseous, liquid and supercritical states, are vital to the seal ability of caprocks for CO2 sequestration. Laboratory testing is necessary to obtain breakthrough pressures as there is no in situ method to accurately estimate the factors that can affect its variability. In this study, we use the step-by-step method to study CO2 breakthrough pressures in unsaturated low-permeability sandstone, and carried out 9 cases of CO2 breakthrough pressure experiments under multiple P-T conditions that can make CO2 in gaseous, liquid and supercritical states, respectively. The variation of CO2 breakthrough pressures (Pbt) were analyzed based on 4 properties of multi-phase flow: CO2-H2O interfacial tension (γ), CO2-H2O-rock wettability, CO2-H2O viscosity ratio (M), and CO2-H2O density difference. The results show that CO2 breakthrough pressure and breakthrough time are positively correlated with experimental temperatures and pressures. The main property affecting CO2 breakthrough pressures is the CO2-H2O viscosity ratio, which is more affected by the P-T conditions (or CO2 phase). Moreover, the breakthrough pressures of CO2 under 9 groups of multiple P-T conditions (which can make CO2 in various phases) is Supercritical CO2 > Liquid CO2 > Gaseous CO2. This study has important guiding significance for the selection of target caprock for CO2 geo-sequestration.

Imaging acidic contaminants in a confined aquifer using electromagnetic geophysical method constrained by hydrochemical data

Acid in-situ uranium leach mining is an effective, popular technology for extracting uranium without large uranium mill tailings. However, acid in-situ leaching causes extremely high concentrations of acidic contaminants in aquifers. To represent the migration and range of acidic contaminant pollutants in confined aquifers, this study applied the controlled source audio-frequency magnetotellurics (CSAMT) method to a uranium mining area located in the Yili Basin, Xinjiang, northwest China. We collected ten CSAMT profiles from 364 sites with an average site interval of 20 m. The electrical resistivity model of the uranium mining area was obtained via two-dimensional inversion using CSAMT data, with 23 frequencies, ranging from 8192 Hz to 4 Hz. Combined with geological, geochemical, and well log data, this resistivity model was successfully used to identify the scale and position of acid contaminant plumes beneath the uranium mining area, which appear as electrically well-defined features that closely coincide with the distribution of sulfate and uranium ions in groundwater. With uranium mining activities ceasing, the scale of acid contaminant plumes has been reduced, owing to the natural attenuation of the aquifer or the contaminants well confined in the mining site. The low-permeability sandstone surrounding the aquifer was imaged as a resistive feature, which confines the contaminant plumes to the uranium mining area and slows the downstream migration of contaminants. According to the modified Archie's law, the porosity of the sandstone bearing uranium beneath the injection well zone increases, owing to acidification, while the porosity of the sandstone beneath the production well zone decreases, owing to pore plugging.

Analysis of Microstructure and Low Permeability with 3D Digital Rock Modeling

The sandstone microstructure and permeability are important parameters for quantitative evaluation of groundwater/oil/gas resources and prediction of flow rates of water/oil/gas. In this study, we applied seven low-permeability sandstone samples obtained from North China to research the microstructure and permeability based on digital core technology. Rock images were collected by X-ray microcomputed tomography (μCT), and then software (Avizo) was applied to analyze the microstructure and calculate the parameters such as porosity, connected porosity, average equivalent diameter, tortuosity, and shape factor. By introducing the shape factor into the Kozeny–Carman equation, we modified the Kozeny–Carman equation and found that the modified equation is a function of porosity, diameter of particles, tortuosity, and particle shape factor.

Integrating Petrography With Core-Log-Well Test Data For Low Permeability Sandstone Reservoir Characterization: Preliminary Recommendation For Production Optimization

Integrating petrographic core information into combined core petrophysics, log, and well test data for understanding facies and environmental deposition in rock characterization has proved itself useful to improving quality and reliability of the required conclusions. This integrated approach has specifically shown its use in the cases of complex reservoirs such ones characterized as low-permeability sandstone reservoirs. It is in this spirit that this paper demonstrates how this virtually cost efficient analysis provides preliminary recommendations for the exploitation of such reservoirs. As case study, two types of producing reservoirs (Bekasap, Bangko, Pematang, and Tanjung Formations) have been taken in 2009. The first type is strongly controlled by depositional environment. It is found in the upper part of Bekasap and Bangko formations (1900 - 2300 ft-ss), deposited in estuarine system, and made of very fine to fine grained sand with low to moderate bioturbation. This mostly feldspathic and lithic greywackes have permeability of up to 200 mD. The second type is strongly dominated by diagenesis process and is mainly found in the Upper Pematang and Tanjung Formations (6200 - 7400 ft-ss). This reservoir type is characterized by its coarse-grained and conglomeratic sandstones resulted from fan- elta and braided channel depositional system. Diagenetic events such as compaction, recrystallization of matrix into microcrystalline clay minerals, precipitation of authigenic minerals in pore system are also well identified from the performed petrographic analysis. This is dominated by sublitharenite and litharenite sandstones exhibit horizontal permeability of up to several dozens mD. The two producing reservoir types have undergone carefully planned exploitation and stimulation operations, and the horizontal drilling and fracturing

An Experiment-Based Study of Formation Damage Using a Microetching Model Displacement Method.

In the field of oil and gas exploration, drilling fluid is regarded as the essential “blood” for drilling, which mainly helps to control the formation pressure and remove cuttings from the well. During the drilling fluid cycle, the drilling fluid penetrates into the pores of the formation rock, thus blocking the rock pores and resulting in a decline in oil and gas recovery efficiency. Therefore, it is very important to understand the microscopic mechanism of formation damage caused by drilling fluid. However, as an important component of formation damage, the microscopic mechanism of fluid damage has not yet been clearly revealed. In this study, a new microetching model (MEM), along with displacement equipment, was designed. The pore network of rock samples was extracted from thin-section images and etched to a thin aluminum sheet by laser. Oil-based drilling fluid was used to displace the stratum water in the MEM. The displacement process was recorded by a camera and analyzed. A core flooding experiment, permeability measurement, and SEM observations were performed. The results show that, for low-porosity and low-permeability sandstone, the main forms of formation damage by drilling fluid include solid damage and liquid damage. Solid damage is mainly caused by the blockage of small pores and narrow throats with solid particles of the size 0.1~30.0 μm in drilling fluid, while liquid damage is mainly caused by the water lock and hydrocarbon lock effects formed by the oil–water two-phase interface, gas–water two-phase interface, or the oil–gas–water three-phase interface.

Investigation on the microscopic damage mechanism of fracturing fluids to low-permeability sandstone oil reservoir by nuclear magnetic resonance

Hydraulic fracturing has become an essential stimulation treatment for improving the development efficiency of low-permeability oil reservoirs. However, fracturing fluid inevitably causes reservoir damage. This study proposed a combined method of microscopic and macroscopic experiments to investigate the nature of formation damage of fracturing fluid by quantifying its influence on porosity, permeability, and pore structure. Nuclear magnetic resonance technology combined with core flooding test and parallel sample comparison method was applied to quantitatively evaluate the damage degree and identify the main damage types of hydroxypropyl guar (HPG) fracturing fluid and slickwater fracturing fluid. The microscopic damage mechanisms of these fracturing fluids were analyzed by thin section petrography, X-ray diffraction, rate-controlled mercury intrusion, scanning electron microscopy, and wettability tests. The results show that the total permeability damage degree of HPG fracturing fluid filtrate is 30.43%, of which water sensitivity, water lock, and macromolecule adsorption account for 6.06%, 23.26%, and 1.11%, respectively. Water lock is the major damage factor. Regarding the damage of slickwater fracturing fluid filtrate, water sensitivity causes the severest damage, corresponding to 39.08% of core permeability loss, whereas macromolecule adsorption and water lock contribute 13.21% and 0.97%, respectively. Water sensitivity damage causes reduced porosity, decreased permeability, and narrower pores, resulting from hydration, swelling, dispersion and migration of clay minerals. Water lock damage increases the movable pore volume, decreases the permeability, increases the pore radius, decreases the throat radius, and increases the pore throat ratio, which increases the flow resistance to the oil phase. The magnitude of water lock damage is closely related to the surfactant content and performance, rock wettability, and pore throat radius ratio. Macromolecule adsorption damage leads to a decrease in permeability, a reduction in the number of large pores, an increase in the number of small throats, and an increase in the pore throat radius ratio due to the absorption and retention of macromolecules on the surfaces of the pores and throats. Increasing the flowback volume of slickwater fracturing fluid can recover part of the macromolecule absorption damage. This research can provide a reliable reference for the optimization of fracturing fluid performance, enhancement of the fracturing effect and reservoir protection of low-permeability reservoirs.

Quantitative Investigation of Water Sensitivity and Water Locking Damages on a Low-Permeability Reservoir Using the Core Flooding Experiment and NMR Test.

Production of oil and gas energy is often greatly hindered by reservoir formation damage, particularly the occurrences of water sensitivity and water locking damages on a low-permeability reservoir. For the purpose of this paper, a formation damage assessment methodology combining core flooding experiment and NMR (nuclear magnetic resonance) T2 relaxation tests is performed and applied to quantitatively determine water sensitivity/water locking damage on sandstone oil formation. XRD tests are used to analyze the mineral composition of cores. Core flooding experiments are designed to simulate the two damages and determine the permeability reduction. NMR tests are introduced to compare water saturation before and after flooding through rock cores, calculate the porosity damage and changes of the pore size, and analyze the mechanism of water sensitivity and water locking damages. Also, SEM experiments are used to determine the pore morphology before and after damage. Low-permeability sandstone rock cores cored from the Jilantai reservoir are assessed through this whole set of experiments. The results demonstrate that the permeability and porosity of core samples strongly decrease with the occurrence of water sensitivity/water locking damage, reflecting that the Jilantai reservoir has strong water sensitivity and is prone to be damaged by water locking. Compared with the previous formation damage assessment ideas, much attention is given to the microchanges of cores after damage, and using fluorinated oil instead of kerosene can help observe the distribution of water in rock core samples after each flooding by the NMR T2 spectra.

Performance Evaluation of Multistage Fractured Horizontal Wells in Tight Gas Reservoirs at Block M, Ordos Basin

Block M of the Ordos Basin is a typical low-permeability tight sandstone gas accumulation. To develop these reservoirs, various horizontal well fracturing technologies, such as hydra-jet fracturing, open-hole packer multistage fracturing, and perf-and-plug multistage fracturing, have been implemented in practice, showing greatly varying performance. In this paper, six fracturing technologies adopted in Block M are reviewed in terms of principle, applicability, advantages, and disadvantages, and their field application effects are compared from the technical and economic perspectives. Furthermore, the main factors affecting the productivity of fractured horizontal wells are determined using the entropy method, the causes for the difference in application effects of the fracturing technologies are analyzed, and a comprehensive productivity impact index (CPII) in good correlation with the single-well production of fractured horizontal wells is constructed. This article provides a simple and applicable method for predicting the performance of multi-frac horizontal wells that takes multiple factors into account. The results can be used to select completion methods and optimize fracturing parameters in similar reservoirs.

Semi-Supervised Learning–Based Petrophysical Facies Division and “Sweet Spot” Identification of Low-Permeability Sandstone Reservoir

The identification of the “sweet spot” of low-permeability sandstone reservoirs is a basic research topic in the exploration and development of oil and gas fields. Lithology identification, reservoir classification based on the pore structure and physical properties, and petrophysical facies classification are common methods for low-permeability reservoir classification, but their classification effect needs to be improved. The low-permeability reservoir is characterized by low rock physical properties, small porosity and permeability distribution range, and strong heterogeneity between layers. The seepage capacity and productivity of the reservoir vary considerably. Moreover, the logging response characteristics and resistivity value are similar for low-permeability reservoirs. In addition to physical properties and oil bearing, they are also affected by factors such as complex lithology, pore structure, and other factors, making it difficult for division of reservoir petrophysical facies and “sweet spot” identification. In this study, the logging values between low-porosity and -permeability reservoirs in the Paleozoic Es3 reservoir in the M field of the Bohai Sea, and between natural gamma rays and triple porosity reservoirs are similar. Resistivity is strongly influenced by physical properties, oil content, pore structure, and clay content, and the productivity difference is obvious. In order to improve the identification accuracy of “sweet spot,” a semi-supervised learning model for petrophysical facies division is proposed. The influence of lithology and physical properties on resistivity was removed by using an artificial neural network to predict resistivity R0 saturated with pure water. Based on the logging data, the automatic clustering MRGC algorithm was used to optimize the sensitive parameters and divide the logging facies to establish the unsupervised clustering model. Then using the divided results of mercury injection data, core cast thin layers, and logging faces, the characteristics of diagenetic types, pore structure, and logging response were integrated to identify rock petrophysical facies and establish a supervised identification model. A semi-supervised learning model based on the combination of “unsupervised supervised” was extended to the whole region training prediction for “sweet spot” identification, and the prediction results of the model were in good agreement with the actual results.

Study of CO2 Flooding to Improve Development Effect in Conglomerate Reservoirs

For low permeability sandstone reservoirs, CO₂ flooding has been proved to be an effective method to enhance oil recovery. Reservoir A is a typical conglomerate reservoir in Xinjiang oilfield. The reservoir has strong water sensitivity, and the injection pressure continues to rise. Furthermore the oil well pressure continues to drop. According to the screening conditions of CO₂ flooding, the reservoir A can easily achieve CO₂ miscible flooding with moderate temperature. And the reservoir has the advantage of being close to the gas source. Firstly, the relationship curve between CO₂ oil displacement efficiency and oil displacement pressure was obtained by changing the oil displacement pressure using the fine-tube experimental model, and the minimum miscible pressure of CO₂ oil displacement was determined. The minimum miscible pressure of reservoir A was 24.1 MPa. The change of oil phase state after CO₂ injection was further studied by CO₂ gas expansion experiment. The results show that the saturation pressure of formation oil increases significantly after CO₂ injection, and the more CO₂ injection, the higher the saturation pressure of formation oil. When the CO₂ content in the injected crude oil is 55.29 mol%, the saturation pressure of the CO₂ formation crude oil system reaches 31.60 MPa. Then, in order to better simulate the real reservoir conditions of conglomerate reservoir, the 2D visualization model of the outcrop was processed to analyze the microscopic oil displacement mechanism of CO₂. The experimental results show that the remaining oil after water flooding mainly exists in the form of cluster, film, column and blind end, and the remaining oil after gas flooding exists in the form of island, cluster and film, and there is an obvious gravity overlay phenomenon. CO₂ flooding after water flooding significantly improved sweep efficiency and enhanced recovery. Finally, through the analysis of CO₂ field injection effect in reservoir A, it is shown that CO₂ absorption capacity of single well is significantly higher than water absorption capacity. The equilibrium degree of production profile in gas injection stage is better than that in water flooding stage. Injecting carbon dioxide quickly restores formation pressure. The oil recovery effect after gas injection in the trial production stage is obviously improved compared with that in the water flooding stage. The research results of this paper provide a reference for the field application of CO₂ flooding enhanced oil recovery technology in Xinjiang conglomerate reservoir.

Controlling factors of matrix acidizing potential of low permeability clastic reservoir in faulted lacustrine basin

Based on constant rate mercury injection experiment, casting thin section identification, scanning electron microscope observation, clay mineral X-ray and rock specific surface area analysis, the controlling factors of matrix acidizing potential of low-permeability sandstone reservoir in fault depression lacustrine basin were determined from three aspects: pore filling, throat filling and pore-throat combination characteristics. It is concluded that provenance controls the plane partition of reservoir pore fillings. Burial depth controls the longitudinal zoning of key filling material in reservoir throat. The difference of rock structure in sedimentary facies - microfacies controlling zone leads to the change of pore-throat assemblage pattern. The matrix acidizing scheme of low permeability sandstone reservoir in fault depression basin can be formulated according to the law of “provenance zoning, buried depth zoning and being controlled by microfacies in zone”, and the implementation scheme of pre-acid, main acid and post-acid can be put forward respectively. This method can effectively promote the integration process of exploration and development of low permeability clastic reservoir in mature exploration area.

A fractal model for obtaining spontaneous imbibition capillary pressure curves based on 2D image analysis of low-permeability sandstone

Spontaneous imbibition (SI) is the principal production mechanism in naturally fractured reservoirs produced by waterflooding and is essential for fluid flow characterization to predict their future performance. As an alternative to the expensive, time-consuming laboratory measurements, 2D images render a different prospect to obtain SI capillary pressure curves, especially for tight reservoirs. This paper introduces a unique approach to infer SI capillary pressure curves from 2D images through integrating image analysis and fractal theory. Using pore-related information obtained from image analysis, we properly represent the pore structure as bundles of tortuous square and triangular tubes with sinusoidally varying radii to imitate cross-sectional variation between pore bodies and throats. Moreover, we simulate the piston-like and snap-off displacement mechanisms to derive an innovative fractal SI capillary pressure model. The developed model considers the contact angle hysteresis caused by surface roughness and heterogeneity of reservoir rocks. The Mayer-Stowe-Princen (MSP) approach is implemented to compute the entry capillary pressure of piston-like displacement. The laboratory-measured porosity and permeability are utilized to determine the model's 3D-related parameters that cannot be inferred from 2D images. The model reliability is verified with the good accuracy of the predicted capillary pressure curves versus laboratory-measured data of five samples from the Liushagang and Huangliu in the South China Sea. Finally, the fundamental parameters influencing the developed SI capillary pressure model are investigated with sensitivity analysis.

Effect of paraffin precipitation on core flow in porous media capacity during fracturing

Low-permeability sandstone reservoirs have become an important exploration and reserve increase target in China, but most low-permeability sandstone reservoirs with high wax content and high freezing point will reduce their production after fracturing injection, especially in winter. Therefore, it is necessary to analyze the field fracturing construction measures and reservoir characteristics. Generally, the fracturing fluid injected by fracturing operation is at room temperature, even lower than 5 °C in winter, and the viscosity and freezing point of crude oil in this block are high. Therefore, the research focuses on the properties of crude oil and the influence of temperature reduction on oil-bearing cores. In order to find out the mechanism of reservoir cold damage, this paper first observed the pore throat of rock sample slice after displacement experiment, and found that there were black paraffin particles in some pore throats; then the distribution of core pore size after displacement was analyzed by T2 spectrum of NMR, and it was found that the proportion of small pores increased gradually with the decrease of temperature. Finally, the displacement experiment is used to simulate the change of permeability in the process of formation cooling and heating after field fracturing. The permeability of crude oil is tested by changing the ambient temperature of displacement experiment. It is found that the permeability before cooling is larger than that after heating recovery, and the process is irreversible. Therefore, the cause of cold damage is that the injection temperature of fracturing fluid is far lower than the formation temperature and the precipitation of paraffin during the cooling process of crude oil. For reservoirs with high wax content and high freezing point, paraffin precipitation caused by cold damage has a great influence on formation permeability, and cold damage can be prevented by changing injection fracturing fluid temperature or adding paraffin inhibitor.

Examining and applying the theory of “exploring petroleum inside source kitchens” for continental shale oil: A case study from the Kong 2 member of the Cangdong sag in the Bohai Bay Basin, China

Continental shale oil to be studied urgently is an important unconventional “source rock oil and gas” and key domain of “exploring petroleum inside source kitchens”. Based on the “source rock oil and gas” theory and the thought of “exploring petroleum inside source kitchens”, this paper established the ”six determination” exploration workflow for continental shale oil (i.e., determining the background, source rock, reservoir, play, resources, and sweet spot), which geological characteristics and exploration workflow are significantly different from conventional hydrocarbon. A case study was conducted by the workflow in the Kong 2 member (Ek2) of the Cangdong sag in the Bohai Bay Basin, China. Semi-deep to deep lacustrine facies belts and many gentle slope structures (belts) were widespread during Kongdian Formation depositing, thus providing favorable conditions for the formation and large-area accumulation of shale oil. Ek2 developed broader-distributed, and thick-bedded dark mudstone and oil shale, which exhibit high TOC, a good kerogen type, and great hydrocarbon-generating potential. Siltstone to fine sandstone and mud to micritic dolomite reservoirs were found within the low-dip slopes and central zone, which are thick, overlapped, abundant high-angle fractures, and exhibit low porosity and ultra-low permeability. Sandstone-type and dolomite-type shale oil of Ek2 characterized source–reservoir integration and five types of sources–reservoir configurations. They mainly overlapped at the front end of the braided river delta in the slope zone and in the sag center, where are superimposed vertically, and are connected horizontally with conventional structural–lithological oil pools in the up-dip slope. The median geological resources of the two classes shale oil were 5.26×108/t, with the remaining resources accounting for 90% of the total and moderate buried depths, thus the exploration potential is great. Several special exploration wells have obtained industrial oil flow. There are two types of sweet spots: low permeability sandstone layers and interbedded layers of oil shale and dolomite. A few favorable sweet spots were identified as targets for subsequent exploration. Then, three aspects of thinking and recommendations to solve the next exploration direction and technical problems were proposed, which will provide important reference and theoretical guidance for the further exploration of the same type of shale system in China and the world.

Laboratory Investigation of Impact of Slickwater Composition on Multiphase Permeability Evolution in Tight Sandstones

Summary Fracturing fluid filtrate that leaks off during injection is imbibed by strong capillary forces present in low-permeability sandstones and may severely reduce the effective gas permeability during cleanup and post-fracture production. This work aims to investigate the role fracturing fluid filtrate from slickwater has on rock-fluid and fluid-fluid interactions and to quantify the resulting multiphase permeability evolution during imbibition and drainage of the filtrate by means of specialized core laboratory techniques. Three suites of experiments were conducted. In the first suite of experiments, a fluid leakoff test was conducted on selected core samples to determine the extent of polymer invasion and leakoff characteristics. In the second suite, multigas relative permeability measurements were conducted on sandstone plugs saturated with fracturing fluid filtrate. A combination of controlled fluid evaporation and pulse decay permeability technique was used to measure liquid and gas effective permeabilities for both drainage and imbibition cycles. These experiments aim to capture dynamic permeability evolution during invasion and cleanup of fracturing fluid (slickwater). The final suite of experiments consists of adsorption flow tests to investigate, identify, and quantify possible mechanisms for adsorption of the polymeric molecules of friction reducers present in the fluid filtrate to the pore walls of the rock sample. Imbibition tests and observations of contact angles were conducted to validate possible wettability changes. Results from multiphase permeability flow tests show an irreversible reduction in endpoint brine permeability and relative permeability with increasing concentration of friction reducer. Our results also show that effective gas permeability during drainage/cleanup of the imbibed slickwater fluid is controlled to a large degree by trapped gas saturation than by changes in interfacial tension. Adsorption flow tests identified adsorption of polymeric molecules of the friction reducer present in the fluid to the pore walls of the rock. The adsorption friction reducer increases the wettability of the rock surface and results in the reduction of liquid relative permeability. The originality of this work is to diagnose formation damage mechanisms from laboratory experiments that adequately capture multiphase permeability evolution specific to a slickwater fluid system, during imbibition and cleanup. This will be useful in optimizing fracturing fluid selection.

Effect of Viscosity Action and Capillarity on Pore-Scale Oil–Water Flowing Behaviors in a Low-Permeability Sandstone Waterflood

Water flooding technology is an important measure to enhance oil recovery in oilfields. Understanding the pore-scale flow mechanism in the water flooding process is of great significance for the optimization of water flooding development schemes. Viscous action and capillarity are crucial factors in the determination of the oil recovery rate of water flooding. In this paper, a direct numerical simulation (DNS) method based on a Navier–Stokes equation and a volume of fluid (VOF) method is employed to investigate the dynamic behavior of the oil–water flow in the pore structure of a low-permeability sandstone reservoir in depth, and the influencing mechanism of viscous action and capillarity on the oil–water flow is explored. The results show that the inhomogeneity variation of viscous action resulted from the viscosity difference of oil and water, and the complex pore-scale oil–water two-phase flow dynamic behaviors exhibited by capillarity play a decisive role in determining the spatial sweep region and the final oil recovery rate. The larger the viscosity ratio is, the stronger the dynamic inhomogeneity will be as the displacement process proceeds, and the greater the difference in distribution of the volumetric flow rate in different channels, which will lead to the formation of a growing viscous fingering phenomenon, thus lowering the oil recovery rate. Under the same viscosity ratio, the absolute viscosity of the oil and water will also have an essential impact on the oil recovery rate by adjusting the relative importance between viscous action and capillarity. Capillarity is the direct cause of the rapid change of the flow velocity, the flow path diversion, and the formation of residual oil in the pore space. Furthermore, influenced by the wettability of the channel and the pore structure’s characteristics, the pore-scale behaviors of capillary force—including the capillary barrier induced by the abrupt change of pore channel positions, the inhibiting effect of capillary imbibition on the flow of parallel channels, and the blockage effect induced by the newly formed oil–water interface—play a vital role in determining the pore-scale oil–water flow dynamics, and influence the final oil recovery rate of the water flooding.

Feasibility of Gas Injection Efficiency for Low-Permeability Sandstone Reservoir in Western Siberia: Experiments and Numerical Simulation

Gas injection is one of the prospective methods in the development of unconventional oil reserves. Before implementation in the field, it is necessary to justify the effectiveness of using gas agents in specific object conditions. Experiments of oil displacement on physical models with subsequent numerical modeling can provide the information necessary to justify the feasibility of using gas injection in specific reservoir conditions. This work is devoted to a series of experiments determining the minimum miscibility pressure (MMP) on a slim tube model and the analysis of oil displacement dynamics for various gas compositions, as well as numerical modeling. Displacement experiments were carried out using a recombined oil sample from one of the fields in Western Siberia. The MMP was determined by the classical method of inflection point on the displacement efficiency versus injection pressure curve, which was 34.6 MPa for associated petroleum gas (APG) and 49.9 MPa for methane. The dysnamics of oil displacement for different gas compositions at the same injection pressure showed that APG and carbon dioxide (CO2) are the most effective in the conditions of the studied field. The influence of the gas composition on the gas breakthrough point was also shown. It is revealed that the change in the concentration of the displacing agent in the outgoing separation gas helps define in more detail the process of displacement and the processes implemented in this case for various displacing gas agents. Similarly, it is shown that the displacing efficiency of a gas agent in a miscibility injection mode is affected by the configuration of wells when it is necessary to achieve MMP in reservoir conditions. For the immiscible gas injection mode, no influence of the well configuration was observed.