Ultra-low Permeability Research Articles

Comparative analysis of air permeability between UHPC and epoxy-coated normal concrete for hyperloop tube structures

This study evaluates the air permeability of epoxy-coated normal concrete and ultra-high performance concrete (UHPC) for use in Hyperloop tube structures, where maintaining ultra-low air permeability is crucial to preserving the vacuum environment. While UHPC is recognized for its exceptionally low permeability due to its dense microstructure, this research explores epoxy-coated conventional concrete as a cost-effective alternative. Using a vacuum-based permeability test simulating Hyperloop's near-vacuum conditions, the study found that epoxy-coated concrete significantly reduced air permeability compared to uncoated concrete, with specimens coated on both sides approaching near-zero permeability. Although UHPC exhibited superior performance, the epoxy-coated concrete demonstrated air-tightness and was suitable for Hyperloop applications, offering a viable and economical alternative. These findings provide important insights for material selection, suggesting that epoxy-coated conventional concrete can effectively meet the stringent requirements for Hyperloop tube construction while balancing performance with cost-efficiency.

Effects of wellbore and skin zone on co-seismic water level Responses: A numerical study

This study investigates the impacts of wellbore and skin effects on co-seismic water level changes. A numerical model has been developed to integrate hydraulic and geomechanically relevant elements, including the wellbore, aquifer system itself and the skin zone. In the model, Darcy flow and Navier-Stokes flow are coupled to simulate processes in the aquifer and wellbore consistently, incorporating two-phase flow of water and gas in the wellbore. The findings demonstrate the influence of wellbore and skin effects on co-seismic well water oscillation, especially during high-frequency seismic perturbations. The predominant wellbore effects arise from storage effect, friction, and water convection in well screen and casing. Positive skin decreases the oscillation amplitude and augments the phase shift, whereas negative skin displays a reversed effect. The effects of wellbore and skin zone may be negligible for co-seismic step changes in well water levels except the obstructive effect of an ultra-low permeability skin zone that may prevent water flow into or out of the wellbore. This model contributes to the understanding of underlying mechanisms affecting seismically induced water level changes by incorporating process-based water flow dynamics and providing an improved framework for their analysis and prediction.

The Saturation Calculation of NMR Logging Based on Constructing Water Spectrum Function

Tight sandstone oil reservoirs are characterized by complex structures, poor pore connectivity, and strong heterogeneity, with features such as low porosity and ultra-low permeability. Conventional methods for calculating saturation cannot accurately evaluate the hydrocarbon saturation of these reservoirs. To address this, a study was conducted from the perspective of non-electrical logging methods, focusing on the inherent nuclear magnetic resonance (NMR) characteristics of different fluids to develop a saturation calculation method that avoids the influence of the rock matrix, thus enabling precise saturation measurement in tight sandstone oil reservoirs. The traditional NMR porosity model was modified by segmenting it using the clay-bound water cutoff value, aiming to identify the distribution pattern of fluids in pores outside the clay-bound water zone. Through theoretical derivation and water spectrum function simulation, a water spectrum function and its parameter range suitable for the NMR T2 distribution in tight sandstone reservoirs were determined. Using core-sealed core saturation as a reference, the particle swarm optimization (PSO) algorithm was applied to optimize the parameter range and construct the final water spectrum function tailored to tight sandstone oil reservoirs. The accuracy and practicality of this method were validated by applying the derived water spectrum function to NMR logging in the exploration block, allowing for precise saturation calculations and the accurate evaluation of tight reservoir saturation.

Mass transport modelling of two partially miscible, multicomponent fluids in nanoporous media

High-pressure fluid transport in nanoporous media such as shale formations requires further understanding because conventional continuum approaches become inadequate due to their ultralow permeability and complexity of transport mechanisms. We propose a species-based approach for modelling two partially miscible, multicomponent fluids in nanoporous media – one that does not rely on conventional bulk fluid transport frameworks but on species movement. We develop a numerical model for species transport of partially miscible, non-ideal fluid mixtures using the chemical potential gradient as the driving force. The model considers the binary friction concept to include the friction between fluid molecules as well as between fluid molecules and pore walls, and incorporates the key multicomponent transport mechanisms – Knudsen, viscous and molecular diffusion. Under single-phase conditions, the system under consideration is quantified by introducing multicomponent Sherwood number (Sh), Péclet number (Pe) and fluid–solid friction modulus (φ). Despite the complexity of fluid transport in nanopores, the steady-state single-phase transport results reveal the contribution of diffusion in nanopores, where all parameters collapse on a set of master curves for the multicomponent Sh with a dependence on multicomponent Pe and φ. Unsteady state, two-phase transport modelling of the codiffusion process shows that light and intermediate alkanes are produced much higher than heavy alkanes when the vapour phase appears. We demonstrate that the pressure gradient is also crucial in promoting CO2 and alkane mixing during counterdiffusion processes. These results stress the need for a paradigm shift from classical bulk flow modelling to species-based transport modelling in nanoporous media.

Application of a Reservoir Classification Method Based on Core Data from Offshore Tight Reservoirs: A Case Study of the Liushagang Formation in the Beibu Basin

Several methods are currently used to test offshore tight reservoirs. However, the effectiveness of these applications varies among wells, and some exhibit unclear reservoir classifications. These issues lead to difficulties in decision-making during tests and result in higher testing costs. Therefore, to address this issue, this study used reservoirs in the Liushagang Formation of the Beibu Basin as the research object and employed core data to apply the multi-stage FZI method. This method computes the FZI and its cumulative probability, classifying the target reservoir into seven distinct types. According to the Winland R35 method, the target reservoir was classified into five distinct types. Seven characteristic parameters were selected based on the mercury injection experimental data. The K-means clustering method was then used to classify the target reservoirs into two types. The conclusions were that, in this formation, there is predominantly low to extra-low porosity and extra-low to ultra-low permeability. According to relationship models, logged porosity can be used to calculate effective permeability. Combining the multi-stage FZI method with the K-means clustering method for reservoir classification is recommended. This integrated approach facilitates a more comprehensive analysis of the characteristics of offshore low-permeability tight reservoirs at both macro and micro scales after classification. This research provides key insights for enhancing offshore well production.

Evaluation of the Compatibility Between Formation and Injection Water in Ultra-Low Permeability Reservoirs

This study focuses on the reservoir scaling and the under-injection issues of the water injection well during the water injection development of an ultra-low permeability reservoir in Xinjiang due to the complex composition of injected water. Microfluidic experiments were applied to visualize the flow channel changes during water flooding, indoor core flooding experiments were employed to analyze the permeability and ion concentration, and nuclear magnetic resonance (NMR) was used to evaluate the pore structure damage. Together, these experiments were used to clarify the scaling and precipitation characteristics as the injected water met the formation water in porous media and the effects on reservoir damage. The research results showed that the poor compatibility of the injected water with the formation water could easily produce calcium carbonate scaling. The scaling products exhibited a unique network structure of blocks and a radial distribution, mainly composed of calcium carbonate and aluminosilicate. The scaling in the porous media exhibited the characteristics of unstable crystal precipitation, migration, and repeated scaling following water mixing, while the scale crystal growth occurred in the pores and the throats. According to the scaling characteristics, the damage to the reservoir permeability by scaling can be divided into the induction, damage, and stabilization stages. The filling and clogging of the scale crystals enhanced the pore structure heterogeneity, with the median pore radius reduced by 21.61% and the permeability reduced by 50%.

Comparative Analysis and Application of Mass and Heat Transfer Simulation in Fractured Reservoirs Based on Two Fracture Models

The projection-based embedded discrete fracture model (pEDFM) and its counterpart, the embedded discrete fracture model (EDFM), have become standard tools for the depiction of the fractures in reservoir simulations. Despite their widespread use, there are still some unclear areas in modeling the complex processes of mass and heat transfer within fractured reservoirs, particularly in both single-phase and multiphase flow scenarios. Our research introduces a numerical methodology for simulating the mass and heat transfer in fractured reservoirs which is developed by extending the framework of the pEDFM and EDFM. To gauge the effectiveness of these models, we devised two cases which were designed to evaluate the adaptability of the pEDFM and EDFM in scenarios involving an ultra-low permeability fracture or a high permeability fracture under single-phase and multiphase conditions. By using local grid refinement (LGR) as a reference, the results of the pEDFM were in reasonably good agreement with the LGR in terms of pressure, temperature, and saturation distributions. This comparison suggests that the pEDFM has a significant advantage in depicting the mass and heat transfer at the matrix–fracture interface compared to the EDFM. Furthermore, a comprehensive analysis of the flow trajectories in both the pEDFM and EDFM provided a reasonable explanation for their differences. Furthermore, the numerical applications involving the heat extraction of Enhanced Geothermal Systems (EGSs) and the water flooding in fractured reservoirs illustrate the adaptability of the pEDFM in the numerical simulation for complex geological conditions. The insights and conclusions obtained in this paper can enhance our understanding of the distinctions between the pEDFM and EDFM, aiding in the selection of the most suitable method for characterizing the fractures in numerical simulations.

A transfer learning framework for the assessment of unconventional resources opportunities in the Middle East

An inadequate understanding of fluid transport processes in ultra-low permeability rocks has propelled data-driven modeling as an alternative and complementary tool to create recovery forecasts that honor the available data in the field. However, newly discovered fields lack data, which makes it challenging to apply traditional data-driven approaches to decision-making. Transfer learning provides an opportunity to start the early-stage analysis of the asset before adequate data becomes available. Here, we present a transfer learning framework that allows the basin-wide assessment of new shale gas and tight oil prospects. The proposed method is developed on real-world data from several thousand horizontal hydraulically fractured wells in the Eagle Ford super-basin in South Texas. A novel aspect of our method is integrating reservoir engineering domain expertise and the relationship among geologic and petrophysical variables, drilling and completion parameters, and well productivity in the data pre-processing and feature generation steps. We consider the temporal and spatial balancing of the training data to ensure that the resulting predictive models honor the real-world practices followed during unconventional field development. Our full-cycle transfer learning workflow consists of dimensionality reduction and unsupervised clustering, supervised learning, and hyperparameter fine-tuning. We test the workflow by examining the performance of a data-driven model of the Eagle Ford Basin on potential plays in the Middle East: Tuwaiq Mountain and Hanifa. The existence of multiple types of hydrocarbons – liquid oil, condensate, and dry gas – in the Eagle Ford results in a model flexible enough to be tested on various types of assets in a new location. We address the challenge of model overfitting by using data types with a relatively low resolution, which allows generalization to different geologies with basin-wide accuracy.

Evaluation of fractured carbonate reservoir and prediction of favorable areas in the eastern area of Amu Darya Right Bank

Fractured carbonate reservoirs are significantly developed in the eastern area of the Amu Darya Right Bank. However, their types, distributions, and fracture characteristics remain unclear. This uncertainty complicates reservoir prediction and hampers exploration and development processes. Given the strong correlation between fracture development and productivity, analyzing fractures is crucial. Comprehensive evaluation and prediction methods for fractured reservoirs are essential for advancing the oil and gas industry. Based on core and geological data analyses, it finds that these reservoirs exhibit low porosity and low to ultra-low permeability. By employing conventional logging alongside specialized methods, such as electrical imaging, nuclear magnetic resonance, and far detection logging, fractures and their effectiveness can be identified and evaluated, clarifying the characteristics of reservoir spaces. Constrained by the results from core and logging analyses, seismic single attribute analysis techniques is applied to predict fractures in the HX block of Amu Darya. To mitigate the limitations of single-attribute analysis, utilize a well-supervised BP neural network method for comprehensive fracture prediction. This multi-attribute approach increases the fracture prediction probability from less than 70%–72.7%. By integrating geological understanding and well logging, and considering the influence of lithology and structure on the reservoir, synthesize the fracture prediction results to optimally select favorable areas.

Optimization of The Development Plan for Ultra-low Permeability And Weak Volatility Reservoir

Abstract Block F1 of F oil field belongs to ultra-low permeability volatility reservoir. Compared with similar reservoirs at home and abroad, the reservoir property of this block is poor and the permeability is only 1.4 mD. There is no development experience for reference. It is urgent to explore the effective utilization technology of volatility reserves in F oil field. In view of the problems that the preliminary research results of F1 block cannot meet the development needs, the reservoir research is not deep, and the development rules are not clear, Through fine structural interpretation and reservoir prediction, the geological characteristics of the oil reservoir have been clarified; We used multiple indicators to evaluate the initial production capacity of the block, And clarified the initial development rules of the weak volatility reservoir. Perfect the dynamic analysis and production capacity evaluation technology of weak volatility reservoir. By using the reservoir engineering method, we optimized the reasonable working system and the development plan. So we expanded the potential of block development, adjustment and external expansion and optimized the development plan, then we constructed the rational well network deployment technology of weak volatility reservoirs which can provide guidance for the effective development of the F1 block. The results can provide reference for the development of other ultra- low permeability weak volatility reservoirs.

Research on Effective Development Methods and Development Potential of Tight and Difficult to Develop Reservoirs in Hailar Oilfield

Abstract In order to solve the problems of large undeveloped reserves and difficult development in the tight sandstone reservoir of Hailar Oilfield, from the perspective of “revitalizing ineffective and inefficient development wells, effectively utilizing tight reservoirs, and improving oilfield recovery”, with the widespread application of volume fracturing and other technologies, and in line with the principle of “starting with the easy and rich before the difficult and poor” in the development of ultra-low permeability fault block reservoirs, the transformation of tight sandstone reservoirs has been taken as an important supplement to the development and production of oil fields. This article takes the tight sandstone reservoir as the research object, aiming at the characteristics of low reserve abundance, longitudinal non-concentration of oil layers, and scattered development of sand bodies. Through detailed analysis and analysis of regional oil and gas migration systems, reservoir classification evaluation standards, fracturing process optimization, and development models, the potential of reservoir transformation and oil production capacity are systematically evaluated. Effective fracturing and post-fracturing energy-enhancing field tests are carried out for ultra-low permeability elastic mining areas, which have implemented the feasibility of utilizing difficult reservoirs, broken through the technical bottleneck of low production in tight sandstone reservoirs, and developed the theory and supporting technology of tight oil development in Hailar Oilfield. Based on the on-site test results, it is shown that the ultra-low permeability reservoir in Hailar Oilfield has the development conditions, indicating the direction of future development potential.

Mechanism recognition and application effect analysis of air injection development in ultra-low permeability oil reservoirs

Abstract There are few application examples of air drive development technology in ultra-low permeability oil reservoirs in China. The article relies on the air drive development block of H oilfield, and based on the results of core start-up pressure gradient experiment, relative permeability experiment, gas composition experiment, and gas swelling experiment, conducts research and analysis on the seepage mechanism and low-temperature oxidation mechanism of air drive development, demonstrating the advantages of air drive development in oil displacement mechanism of ultra-low permeability oilfield. Based on the basic parameters of oil fields developed by air flooding both domestically and internationally, the specific blocks suitable for air flooding development in H oilfield are selected. The feasibility of conducting air flooding development in low permeability oil fields is demonstrated from three aspects: indoor real core experimental data, safety, and the maturity of existing equipment and technology. At the same time, an analysis is conducted on the development status of the air drive block in H oilfield. By comparing the development effects with adjacent water injection blocks, it is demonstrated that the air drive development effect in ultra-low permeability oilfield is superior to water injection development.

The application of PVC hollow fiber ultrafiltration membrane in ultra-low permeability oilfield

Abstract Oil containing wastewater produced from ultra-low permeability oil fields generally needs to be treated to meet the 5-1-1 standard before it can be reinjected. In order to meet the standards for treating oily wastewater in ultra-low permeability oil fields, PVC hollow fiber ultrafiltration membranes and pre-treatment processes for removing oil, suspended solids, sulfides, etc. before the membrane were selected. The application shows that the aeration air flotation flow sand filtration PVC hollow fiber ultrafiltration membrane process can treat oily wastewater, and the treated water can reach the “5-1-1” standard. In the pre-treatment process of PVC hollow fiber ultrafiltration membrane, the silicone rubber membrane aeration device has good oxidation effect, high efficiency in micro nano air flotation for oil removal and suspended solids, and easy management of sand flow filters. This process has economic feasibility and provides technical support for the treatment of oily wastewater in ultra-low permeability oil fields, with great promotional value.

Enhanced Oil Recovery Technology in High-Temperature Shale Oil Reservoirs: A Review

Abstract As a strategic continuation resource, shale oil has abundant reserves and significant development potential, with the decrease of conventional oil and gas resources. However, in contrast to North American marine shale oil, China’s shale oil is mostly continental, has high reservoir heterogeneity, ultra-low permeability and porosity, and the oil recovery is generally lower than 10%. In this review, the advances in laboratory research and field application of enhanced oil recovery (EOR) technologies such as gas injection, agent injection and nanomaterial injection in high-temperature shale reservoirs are systematically reviewed, and the mechanisms of various technologies are also explained, as well as their advantages and disadvantages. In particular, the problems and challenges faced by EOR are thoroughly analyzed, and suggestions and strategies for the efficient development of shale oil are proposed. Gas injection is an effective method to supplement formation energy in shale reservoirs, which can effectively enhance shale oil production, but there are problems with gas sources, gas channeling and corrosion. At present, injection agents and nanomaterials are still in the laboratory research stage and have not formed large-scale applications in shale reservoirs. In the future, it will be important to thoroughly research the interface impact of various injection medium and oil-water-shale, clarify the applicability of shale oil EOR technologies, accelerate the key test of shale oil stimulation technology, and help scale benefit development and high-quality development of shale oil.

Development and Application of a Chelating Acid for Water Injection Wells of Chang 6 Reservoir of An-Sai Oilfield

Abstract Ansai oilfield is a typical low permeability, low pressure, low yield and serious heterogeneity oilfield. Chang 6 play of Triassic YanChang Formation is a typical ultra-low permeability reservoir. The average porosity of the reservoir is 10 % ~ 14 %, and the average permeability is (0.2 ~ 4.0) × 10−3 μm2. The absolute content of clay minerals in the reservoir is relatively high, with an average content of 18.61 %. The main components are kaolinite, chlorite, illite and illite/montmorillonite interlayer. Due to the reservoir blockage caused by scaling, water sensitivity and formation particle migration in the process of water injection, high injection pressure and under injection wells is increasing dramatically. In view of the above challenges, a fit-for-purpose acid, which contains organic acids and chelating agents, was developed for injection pressure reduction and injection enhancement. It has the characteristics of strong dissolution, good retarding and corrosion inhibition performance. Corrosion rate is 0.5632 g / (m2·h) for J55 steel in 24h, and the core permeability increases by 74.57 % after acid flooding. It has been applied in field test of 3 wells in Chang 6 layer of Ansai oilfield since March 2024. The average daily injection volume increased by 37.87 %, and the validity period was more than 180 days.

Application effect of temporary plugging and diverting fracturing technology in well X1

Abstract The deployment of horizontal well development in the sweet spot area of the main sand body can improve the reservoir control degree and the production of a single well. The X1 well in the X block will be put into production after fracturing in 2022. The target layer of this well is a tight reservoir with low porosity and low permeability, and natural fractures are not developed. Combined with the geological characteristics of the target well, horizontal well soluble bridge plug and temporary plugging and diversion fracturing technology are applied to well X1, and branch fractures are formed through temporary plugging and diversion in the fracture, which increases the complexity of fractures and increases the drainage area. The well is currently in production for 485 days, with a peak oil day of 17.4t and a current oil day of 7t, with a cumulative oil production of 4184.6t. In this paper, the fracturing effect of well X1 is preliminatively analyzed, and it is concluded that under the same reservoir conditions, the single particle size sand combined with temporary plugging in the fracture transformation has a relatively good development effect, which can obviously improve the development effect of tight reservoir. The application effect of soluble bridge plug and temporary plugging diversion fracturing technology in this well has certain reference significance for improving the development effect and benefit of horizontal well in ultra-low permeability reservoir.

Experimental Study on the Treatment of Produced Water from Carbon Dioxide Drive by Aeration Method

Abstract To further explore the effective development of produced water treatment technologies suitable for low to ultra-low permeability oil fields, and to clarify the water quality characteristics of produced water from CO2 flooding. A study was conducted on the basic water quality characteristics of produced water from low to ultra-low permeability oil fields. Indoor CO2 gas removal experiments were conducted using the aeration method under 40°C atmospheric pressure conditions. The research results indicate that the CO2 content in the extracted water is one of the important influencing factors for the changes in characteristic parameters such as water pH, mineralization, and corrosion rate; Under the condition of 40°C atmospheric pressure test, the aeration method has a significant treatment effect on the produced water from CO2 flooding, which can effectively remove 70% of the CO2 in the water, thereby improving the pH of the water to 8, and effectively inhibiting the corrosion rate of the produced water below 0.076mm/a.

Technology and Research on Improving Oil Recovery by Volume Fracturing with Phase Change Permeability in Ultra-low Permeability Reservoirs

Abstract The conventional water injection development production wells in ultra-low permeability reservoirs have low efficiency, low production and low liquid content, and poor economic benefits. Traditional water drive development techniques are difficult to adapt to the requirements of economically effective development in ultra-low permeability reservoirs. Therefore, it is urgent to adjust development ideas and transform water injection development methods. A major development experiment was carried out in the Y284 area of Huaqing Oilfield to transform the water injection development method. Based on the mechanism of reverse osmosis flooding in oil recovery wells, this article uses dynamic monitoring technologies such as downhole microseismic to achieve three-dimensional reservoir transformation, and establishes a large-scale fracturing technology of “collaborative permeability flooding, volume fracturing, and multi-stage temporary plugging” for reverse osmosis wells in ultra-low permeability reservoirs. Research has shown that large-scale fracturing technology for water injection wells can improve single well oil recovery speed by increasing the complexity of fracture networks. The important factors affecting the effectiveness of water injection wells include reservoir properties, fracturing transformation scale, cumulative water injection volume, remaining oil distribution, and heterogeneity of aquifers. At the same time, the construction parameters of large-scale volume fracturing for water injection wells, namely 140-170m, are quantitatively determined based on the actual situation of the mining field ³ The amount of sand added, a sand ratio of 17-22%, and a large displacement of 8-10m3/min, 1400-2000m ³ The amount of liquid entering the ground can most effectively achieve the conditions for reservoir transformation. The conclusion is that large-scale fracturing technology for conversion wells provides technical support for volume fracturing and optimization design of fracturing parameters for low production wells in ultra-low permeability reservoirs, and can provide guidance and reference for the efficient development of other similar ultra-low permeability reservoirs.

Natural gas accumulation conditions and exploration directions of Carboniferous clastic rocks in the northeastern margin of Junggar Basin, China

The Carboniferous strata in the northeastern Junggar Basin are an important exploration field for natural gas in the basin. However, volcanic rocks have long been the primary exploration target. In contrast, the exploration and research of clastic rocks associated with source formations have been largely overlooked, resulting in an insufficient understanding of the reservoir forming conditions and exploration potential of Carboniferous clastic rocks. Through the evaluation of Carboniferous source rocks, effective source stove characterization, clastic reservoir evaluation, oil and gas source correlation, and reservoir formation model construction in this region, three key findings have been made. First, the Carboniferous in the northeastern Junggar Basin has developed three sets of high-quality gas source rocks: the Dishuiquan Formation, the Songkalsu B Member, and the Shiqiantan Formation. These formations correspond to three hydrocarbon source centers: the Sannan–Dishuiquan Sag, the Wucaiwan Sag–Dajing area, and the Dongdao Haizi Sag–Baijiahai High. Second, the Carboniferous system in the northeast has developed multiple types of large-scale reservoirs, including sand conglomerates, sandstones, turbidites, dolomitic rocks, and shale. These reservoirs are generally characterized by low porosity to ultra-low porosity and low permeability to ultra-low permeability reservoirs. There is a dissolution pore development zone at depths of 2900–4500 m. Third, a comparison of oil and gas sources reveals that all three sets of gas source rocks contribute to the natural gas found in the northeast, with obvious characteristics of near-source reservoir formation. The Carboniferous clastic rocks host two types of natural gas reservoirs: unconventional and conventional near-source reservoirs. It is predicted that there is an orderly accumulation pattern of shale gas, tight sandstone gas, and conventional natural gas reservoirs. This study reveals that the Carboniferous clastic rock source and reservoir configuration in the northeastern Junggar Basin is highly favorable, and the natural gas reservoirs in source and near-source clastic rocks represent important exploration directions.

Energy mechanism of gas channeling channels in complex fracture networks for CO2 injection in ultra-low permeability reservoirs

The injection of CO2 into ultra-low permeability can enhance production as well as accomplish storage of carbon. However, the gas channeling phenomenon is serious and there is a lack of explanation of the energy mechanism. Based on the current state of CO2 gas channeling in the Y29-105 well group located in the Huang 3 block of Jiyuan Oilfield, this study utilises the ABAQUS finite element cohesion model to explore the mechanical evolution of the CO2 channel expansion process. And according to the size of the cross-flow channel, intra-fracture pressure, damage displacement and expansion pressure, it is divided into the unconnected stage, the inter-well connected stage and the well group connected stage. Furthermore, we also established energy judgment criteria for the expansion behaviour of gas channeling channels, including stopping at natural fractures, extending along natural fractures, and directly crossing natural fractures. Upon comparison with theoretical and experimental results, it was determined that the energy discrimination criterion is appropriate for expansion along natural fractures and cross natural fractures. It can be seen that our research results can offer energy mechanism support for preventing, controlling, and predicting large-scale CO2 injection in ultra-low permeability reservoirs.