Rock Pore Structure Research Articles

COMSOL-based investigation of the characteristics of microscopic water flooding and residual oil distribution in carbonate reservoirs

Carbonate reservoirs are rich in oil and gas reserves; thus, they have great exploitation potential. Therefore research on the microscopic mechanisms of carbonate reservoirs is of great significance. Based on the thin section images of core castings of typical Well 555 and its pore and fracture features in actual reservoirs, this study designed three kinds of images representing the pore and throat structure of real rocks by applying image stitching and binarization processing methods. A microscopic pore model of carbonate rocks was then established using COMSOL numerical simulation software. The microscopic water flooding characteristics and residual oil distributions of different schemes were observed by designing different fracture development forms. The fractures that developed in parallel main lines showed a more obvious influence on water flooding characteristics compared to fractures that developed in vertical main lines. The cluster residual oil was the main residual oil type in the early stage of water flooding in the pure matrix model. With the progress of water flooding, the continuous cluster residual oil gradually turned into mainly discontinuous porous and columnar residual oils. Vertical mainline fractures reduced the amount of residual oil in clusters and replaced it with columnar residual oil. In contrast, parallel main line fractures expanded the unswept area, with the residual oil appearing in contiguous clusters. This study microscopically analyzed the law and characteristics of water flooding in carbonate reservoirs to provide key theoretical support for enhancing oil recovery.

Pore structure and fractal characteristics of the marine shale of the longmaxi formation in the changning area, Southern Sichuan Basin, China

The pore structure is an important factor affecting reservoir capacity and shale gas production. The shale reservoir of the Longmaxi Formation in the Changning area, Southern Sichuan Basin, is highly heterogeneous and has a complex pore structure. To quantitatively characterize the shale’s pore structure and influencing factors, based on whole rock X-ray diffraction, argon ion polishing electron microscopy observations, and low-temperature nitrogen adsorption-desorption experiments, the characteristics of the shale pore structure are studied by using the Frenkel-Halsey-Hill (FHH) model. The research reveals the following: 1) The pores of the Longmaxi Formation shale mainly include organic pores, intergranular pores, dissolution pores and microfractures. The pore size is mainly micro-mesoporous. Both ink bottle-type pores and semiclosed slit-type pores with good openness exist, but mainly ink bottle-type pores are observed. 2) The pore structure of the Longmaxi Formation shale has self-similarity, conforms to the fractal law, and shows double fractal characteristics. Taking the relative pressure of 0.45 (P/P0 = 0.45) as the boundary, the surface fractal dimension Dsf and the structural fractal dimension Dst are defined. Dsf is between 2.3215 and 2.6117, and the structural fractal dimension Dst is between 2.8424 and 2.9016. The pore structure of micropores and mesopores is more complex. 3) The mineral components and organic matter have obvious control over the fractal dimension of shale, and samples from different wells show certain differences. The fractal dimension has a good positive correlation with the quartz content but an obvious negative correlation with clay minerals. The higher the total organic carbon content is, the higher the degree of thermal evolution, the more complex the pore structure of shale, and the larger the fractal dimension. The results have guiding significance for the characterization of pore structure of tight rocks.

A comparative study of micro-CT and mercury intrusion techniques for predicting permeability and surface area evolution during chemical dissolution

In this paper, we report on experimental and computational studies investigating the evolution of pore structure and permeability of a microporous carbonate rock during chemical dissolution using information provided from X-ray micro-computed tomography (µ-CT) and mercury intrusion porosimetry (MIP) techniques. We consider a chemical dissolution in a core sample by a nonacidic solution wherein a quasi-uniform modification of pore structure occurred. First, we conduct a comparative analysis on the capabilities and limitations of the µ-CT and MIP methods to quantify the evolution of pore size and pore surface area. In particular, we incorporate micropores into the calculations of the pore size-related parameters to highlight the uncertainties that ignoring microporosity causes. In the second part of the paper, we present predictive results on the fractional changes in the permeability of the rock using the Katz-Thompson (KT) and Kozeny-Carman (KC) models. The predictions are based on two characteristic parameters of the pore phase, i.e., the critical pore diameter and the specific pore surface area, and two characteristic macro-scale properties, i.e., porosity and formation factor, all calculated from both the MIP and µ-CT methods. The predicted changes in permeability are compared with those calculated directly on the images using the lattice-Boltzmann (LB) flow simulation on segmented images. The effect of changes in microporosity is also assessed to investigate its role in permeability evolution. The results showed that the KT model could reasonably predict the fractional changes in permeability in terms of the pore structure and macroscale parameters calculated from the MIP and µ-CT methods.

Barite and gypsum precipitation in chalk: A numerical simulation approach revealing the coupled impact of physical and chemical heterogeneities in porous media

In studies relevant to the contaminant transport in geosphere, the evolution of local physicochemical processes imparts potential challenges in safety and critical assessment issues. The transport of such contaminants in a rock pore structure could occur under the advective or diffusive regime. Such transport over the spatial and temporal scale depends upon the coupling between physical properties of the pore structure (permeability, pore size distribution, porosity) and chemical properties of the dissolved ionic species (pH, ionic strength, and surface interactions). The nature of such interactions leads to the generation of local imbalances in pore solution and thereby enhances the dissolution and precipitation of minerals. To predict the occurrence of such processes over large spatial and temporal scales, it is imperative to demonstrate how these physical and chemical processes interact within the heterogeneous porous media. In this context, numerical simulations were conducted to model the results of experimental dataset investigating barite and gypsum precipitation in chalk. In the experimental approach, the selected two minerals are end-members of the sulfate-alkali family and exhibit large differences in the kinetic rate and solubility, and the reference chalk sample resembles heterogeneity in its pore structure. The numerical simulations revealed that at the 1D scale, it was possible to model the overall experimental observations at the boundary monitoring points such as chemistry evolution in reservoirs, porosity loss during barite and gypsum precipitation, the total amount of barite and gypsum formation in clogging zone and the threshold saturation index to initiate precipitation. However, these simulations could not validate the experimentally observed impact of barite and gypsum clogging on the changes in water tracer transport. The underlying reason for such behavior was the formation of a unique clogging zone due to barite and gypsum precipitation. We showed that the 2D simulations incorporating spatial heterogeneity were able to reproduce the observed precipitation patterns, for both of the barite and gypsum experiments. Through 1D and 2D numerical results, we demonstrate the capability of a reactive transport model to validate the experimentally observed barite and gypsum precipitation behavior in chalk samples. Furthermore, it also highlights the interplays between the physicochemical heterogeneities, mineral reactivity and the transport rates that are responsible for the distinct precipitation pattern of the barite and gypsum in chalk samples, and consequently their impacts on transport properties.

Polymer induced permeability reduction: The influence of polymer retention and porous medium properties

Polymer injection is broadly applied for enhanced oil recovery (EOR) in high crude oil viscosity and heterogeneous reservoirs. Although polymer flooding is very effective to decrease the mobility ratio towards favorable values and improve sweep efficiency, some side effects have to be considered including the risk of a severe polymer induced permeability reduction (PIPR) resulting from polymer/rock interaction either near the wellbore of in-depth of the reservoir. Many factors affect the degree of PIPR such as rock mineralogy, oil saturation, temperature, formation water salinity, rock pore structure, polymer type, polymer molecular weight, shear rates in the porous medium, and quality of the injection water (solid particles and oil droplets content). Accurate assessment of PIPR is very important for polymer selection to define the relative merits of polymer flooding for a certain reservoir and avoid polymer injectivity loss during field operations. A severe PIPR can be due to excessive polymer retention inside the reservoir rock, fluid incompatibility of polymer with formation fluids and rocks, clogging of pore throats (accumulation of large polymer molecules at the pore throat), shear thickening due to high shear rate in the near-wellbore area, Improper preparation of the polymer solution, and bad quality of the injection brine used to prepare the polymer solution.In this paper, coreflooding as an assessment technique for PIPR is reviewed and a new interpretation technique is presented to correlated the polymer retention to permeability reduction measured from coreflooding experiments. Coupling the polymer retention and rock quality index was very effective in matching the permeability reduction for data presented in the literature for sandstone and carbonate rock samples.PIPR should be considered as an important design characteristic during any polymer selection workflow. Although different techniques are presented earlier, most of them lack the ability for upscaling. An accurate assessment of PIPR using experimental data permits critical evaluation of polymer flow deeper in the reservoir and prediction of any injectivity problems as well as improving project design.

Experimental Study on Compaction Characteristics and Mechanical Behavior of Crushed Rock Masses

The compaction and consolidation process of a regenerated roof can be divided into two stages, namely, secondary fragmentation of crushed rock masses and pore structure adjustment. Therefore, the mechanical properties of the regenerated roof differs significantly from those of the primary roof. We performed confined compression tests of crushed mudstones and sandy mudstones using a self-developed compression testing apparatus. We studied the influence of the moisture content, compression ratio, particle size, and volume-based degradation on the compression and consolidation characteristics based on the microscopic morphology of the crushed rock masses. Further, the degrees of influence of these factors on the stability of the consolidated bodies were determined. Therefore, the influence mechanism of each factor on the compressive and shear strengths of the consolidated bodies was revealed. The results indicated that the compaction and consolidation of the crushed rock masses involved a constant adjustment of the contact and stress states of the rock masses. Under uniaxial compression and shearing, the consolidated bodies presented the features of ductile failure. The compression ratio and particle size were the most important influencing factors in the compressive and shear strengths of the consolidated bodies. Further, we carried out an orthogonal experiment and built a multivariate nonlinear regression model to quantitatively characterize the combined influence of these factors on the compaction characteristics of the crushed rock masses and the mechanical behavior of the consolidated bodies.

A new method for capillary pressure curve prediction based on NMR echo data using integral transform, the quantum genetic algorithm, and the artificial neural network in tight sandstone

The capillary pressure curve (CPC) is an important tool with which to investigate the petrophysical properties and pore structure of oil and gas reservoir rocks. However, the method of obtaining the CPC directly via laboratory measurements is usually time-consuming and costly, prone to the contamination or destruction of core samples, and can only be applied to limited cores. A new method adopting integral transform, the quantum genetic algorithm, and the artificial neural network (IT-QGA-ANN) based on nuclear magnetic resonance (NMR) echo data is proposed to improve CPC prediction accuracy in tight sandstone. First, 7 parameters that characterize rock properties are directly extracted from echo data using integral transform. This process does not require to obtain the transverse relaxation time (T2) distribution by inversion of echo data, thereby avoiding the influence of inversion uncertainty. These characteristic parameters are then used as the input of the ANN, and the QGA method is utilized to optimize the weights and thresholds of ANN. Numerical simulation results prove the validity of integral transform to extract characteristic parameters. A total of 18 tight sandstones are used for mercury injection and NMR tests. The results indicate that, compared with the traditional nonlinear regression and ANN methods, the proposed IT-QGA-ANN method can more accurately predict the CPC. The proposed method achieves the direct and accurate transformation from echo data to the CPC, and provides important guidance for solving complex nonlinear problems in oil and gas reservoir evaluation based on NMR.

How to avoid multiple scattering in strongly scattering SANS and USANS samples

Small Angle Neutron Scattering (SANS) and Ultra Small Angle Neutron Scattering (USANS) are the only available experimental techniques to provide seamless non-destructive measurements of the geometry of the accessible and inaccessible pore structure of rocks from sub-nanopore size to the scale of macropores. They have therefore become the measurement of choice for tight reservoir rocks such as organic rich shales. A simplifying assumption in the analysis is, however, that during the path of neutrons through the sample each neutron is only scattered once. Shales are samples with a high scattering power and Multiple Scattering (MS) may occur which requires special modelling for deconvolution of the results. The approach to avoid MS is to simply reduce the sample thickness to <0.15–0.5 mm. Here, wepresent a systematic method on wavelength selection and preparation of samples to optimise extraction of microstructural data and minimise parasitic errors. Experimentally measured SAS transmission (TSAS) values are used as a practical criterion for estimation of the extent of MS.Generous beamtime allocations allowed robust testing revealing that sample thicknesses can be twice as thick as predicted using the standard protocol. Analysing thicker samples is particularly beneficial for statistically relevant characterisation of heterogeneous samples making the new protocol the method of choice for such samples.

Investigation of the Effect of Capillary Barrier on Water–Oil Movement in Water Flooding

Water flooding technology is widely used to improve oil recovery efficiency in oilfields. The capillary barrier effect induced by the complex pore structures in the reservoir rocks is a crucial reason for the trapping of a great deal of residual oil in oil reservoirs after water flooding. However, the formation condition along with the effect on the recovery rate of the capillary barrier under different wettability conditions should be investigated further. To bridge the gap between the microscopic mechanism of the capillary barrier effect and the macroscopic mechanism of oil displacement efficiency, a simple conceptual capillary model is constructed to obtain the formation conditions of the capillary barrier using the analysis method, and its influence on macroscopic oil displacement efficiency in the porous media model with an opening angle of 45° is systematically investigated in this study using direct numerical simulations (DNS) coupled with the volume of fluid method. The results showed that the capillary barrier effect plays a significant role in the formation of the residual oil in the reservoir rock and the contact angle and the opening angle are the primary factors for the formation of the capillary barrier. The capillary force is the driving force when the oil–water interface advances in the throat channel under water-wet conditions, while the capillary force hinders the movement of oil–water movement when the liquid flows out of the throat channel and when θ + β &gt; 90o. Furthermore, the highest oil displacement efficiency is achieved at the intermediate capillary number and in the case that the minimum conditions of occurrence of the capillary barrier phenomenon are satisfied. This is of great significance for controlling the optimized contact angle to further enhance the oil recovery rate of current oil reservoirs using waterflooding technology.

Rock-Wettability Impact on CO2-Carbonate Rock Interaction and the Attendant Effects on CO2Storage in Carbonate Reservoirs

Deep saline aquifers and depleted carbonate reservoirs are generally considered promising locations for subsurface CO2 storage. However, carbonate minerals particularly calcite can react with CO2-saturated brine, resulting in dissolution of carbonate and potentially mechanical compaction. Thus, it is crucial to understand the extent of this reaction in both water-wet and oil-wet scenarios, and subsequently its consequences on CO2 storage in depleted carbonate reservoirs. In this study, medical X-ray computed tomography (CT) was used to image water-wet and oil-wet Indiana limestone core samples before and after CO2 flooding. Changes in the rock matrix and pore structure were further assessed from the porosity and permeability data computed from the CT images. In both cases, imaging shows a significant amount of dissolution resulting in an increase in pore volume after core flooding with live brine and subsequently CO2. This increase in porosity is 46.7% and 19% for the water-wet and oil-wet core, respectively. Likewise, the brine permeability for the water-wet core increased from 9.2 mD (before CO2 flooding) to 108 mD (after CO2 flooding), whereas the permeability for the oil-wet core increased modestly from 9.0 mD to 20.1 mD. These results suggests that the reactivity is less pronounced in the oil-wet rock compared to the water-wet rock. Therefore, the wettability state of a target carbonate reservoir and the subsequent potential for the wettability state to be modified should be considered when assessing the CO2 storage capacity and integrity.

Pore Structure Characteristics and Adsorption and Desorption Capacity of Coal Rock after Exposure to Clean Fracturing Fluid.

In the hydraulic fracturing process, fracturing fluid contacts coal rock and physical and chemical reactions occur, which inevitably damage the pore structure of the coal rock and affect the adsorption and desorption capacity of the coal rock. In this paper, a low-temperature N2 adsorption method and scanning electron microscopy (SEM) were used to characterize coal samples. Using gas adsorption/desorption tests, high-, medium-, and low-rank coal samples before and after the clean fracturing fluid treatment were systematically studied. According to the relationship between coal pore structure parameters and gas adsorption/desorption characteristics, a correlation between the microscopic pore structure and the macroscopic gas adsorption/desorption characteristics of coal was obtained. The results show that the number of closed pores in high-, medium-, and low-rank coal samples increased after the clean fracturing fluid treatment. The micropore volume increased by 0.0009, 0.00143, and 0.0035 mL/g, respectively, and the specific surface area increased by 4.87, 9.06, and 57.60%. The fractal dimension also increased compared with that of raw coal. SEM analysis indicated that the influence degree of clean fracturing fluid treatment on the pore structure of different-rank coal samples was Gengcun low-rank coal > Pingba middle-rank coal > Jiulishan high-rank coal. The experimental results of methane adsorption and desorption showed that the adsorption capacity of the coal samples after clean fracturing fluid treatment was enhanced, which is related to increases in the micropore proportion, micropore volume, and specific surface area of the coal. The desorption capacity of the coal samples was also enhanced. The desorption rate of medium- and high-rank coal samples increased after the clean fracturing fluid treatment but that of low-rank coal samples decreased. The main reason is the increase in the number of micropores in low-rank coal, which enhances the gas adsorption ability and makes gas desorption difficult. Therefore, clean fracturing fluid is suitable for medium- and high-grade metamorphic coalbed methane mines. These research results provide a theoretical basis for the application of clean fracturing fluid in different coalbed methane wells.

Experimental studies on the pore structure and mechanical properties of anhydrite rock under freeze-thaw cycles

To study the deterioration mechanisms of anhydrite rock under the freeze-thaw weathering process, the physico-mechanical characteristics and microstructure evolutions of anhydrite samples were determined by a series of laboratory tests. Then, a descriptive-behavioral model was used to measure the integrity loss in anhydrite samples caused by cyclic freeze-thaw. Finally, the freeze-thaw damage mechanisms of anhydrite rock were revealed from the macro and micro aspects. The results show that the pore size of the anhydrite rock is mainly concentrated in the range of 0.001–10 μm. As the number of freeze-thaw cycles increases, there is a growth in the proportion of macropores and mesopores. However, the proportion of micropores shows a declining trend. The relations of the uniaxial compressive strength, triaxial compressive strength, cohesion, and elastic modulus versus freeze-thaw cycles can be fitted by a decreasing exponential function, while the internal friction angle is basically unchanged with freeze-thaw cycles. With the increase of confining pressure, the disintegration rates of the compressive strength and the elastic modulus decrease, and the corresponding half-life values increase, which reveals that the increase of confining pressures could inhibit freeze-thaw damage to rocks. Moreover, it has been proven that the water chemical softening mechanism plays an essential role in the freeze-thaw damage to anhydrite rock. Furtherly, it is concluded that the freeze-thaw weathering process significantly influences the macroscopic and microscopic damages of anhydrite rock.

Evolution of Fractal Pore Structure in Sedimentary Rocks

AbstractGeological processes alter pore spaces over time, and their analysis can shed light on the dynamic fractal structure and fluid flow of rocks over time. This study presents experimental evidence to illustrate that the pore fractal structure evolves with sedimentation, carbonate cementation, clay growth, and dissolution. It examines, describes and characterizes a suite of core samples from the Gaotaizi oil layer of the second and third members of the Qingshankou Formation, Songliao Basin, China. The effects of mechanical compaction and other diagenesis effects on fractal pore structure on sedimentary rocks are discussed. A schematic diagram is proposed that describes the impacts of these diagenetic processes on fractal pore structure at the microscopic scale in sedimentary rocks. This work links the state of diagenetic alteration and fractal pore structure, which can guide practical applications such as predicting the permeability of sedimentary rocks.

Three-dimensional modeling and porosity calculation of coal rock pore structure

Three-dimensional modeling and porosity calculation of coal rock pore structure

Polymer molecular morphology in alkali-surfactant-polymer (ASP) ternary composite system and its influence on rock pore structure

Polymer molecular morphology in alkali-surfactant-polymer (ASP) ternary composite system and its influence on rock pore structure

The 13C-depleted methane in terrigenous shale gas: A case study in the Triassic Yanchang Formation, Ordos Basin

The methane carbon isotopic composition (δ13C1) of some shale gas, and of some conventional gas in shale gas regions, is more depleted in 13CH4 than can be predicted from vitrinite reflectance (Ro) using the δ13C1-Ro equation. This is also often the case for coal bed methane. There is currently no convincing explanation for this phenomenon primarily because wellhead gas or core desorption cannot represent the original, in-situ state of the shale gas, owing to problems of desorption fractionation, lost gas, and residual gas. In this paper, we focus on shale gas in the Yanchang Formation of the Ordos Basin. To avoid the above-mentioned problems and obtain the shale gas in-situ, two shale samples, obtained from pressure coring, were used for parallel experiments. The gas desorption experiment was carried out under normal temperature and heating conditions, the core residual gas was obtained by crushing, and the components and carbon isotopic composition of desorption gas and residual gas were analyzed. The δ13C1 values for the two shale (Ro = 1.2%) desorption gas samples were −50.7‰ and −50.8‰, about 10‰ lighter than the value of −40.6‰ predicted by the empirical δ13C1-Ro formula. The δ13C1 values for the small amount of core residual gas in the two samples were −47.0‰ and −47.6‰, indicating that δ13C1 of Yanchang Formation in-situ shale gas is about 10‰ lighter than the δ13C1-Ro empirical formula predicts. This difference may be related to gas adsorption onto organic matter and clay minerals in shale. The negative δ13C1 is due to the retention of pre-biogas and early thermogenic gas. Dynamic adsorption experiments with activated carbon and a 5 Å molecular sieve show that early methane molecules preferentially occupy adsorption sites with relatively low pore radii and are likely to be replaced by late methane molecules, due to the high adsorption energy. The pore size distribution characteristics of shale in the Yanchang Formation are generally consistent with this pattern. In general, the δ13C1 of shale gas is related to adsorption, and the degree to which it is negative is related to the adsorption intensity and pore structure of the source rock.

Surface analysis of liquid adsorption onto shale

Shale rocks are one of the world's most important unconventional gas resources today, thanks to technical advancements. Fluid adsorption in tight rocks like shale is critical for designing fracturing and treatment fluids. However, adsorption of fluids in shale is not fully understood, and quantifying it remains difficult. In addition, the complicated pore structure of shale rocks makes characterisation challenging. Wettability can be used to understand the affinity of a solid surface to adhere certain fluid. Shales present several basic problems when employing standard techniques because of their small grain size, low permeability, and reactive components. We assessed and compare the wettability of shale using contact angle and spontaneous imbibition methods in two shale samples. The findings showed no correlation between contact angle and imbibition curves. Such behaviour is due heterogeneity of shale surface. Contact angle produces local wetting characteristics, but shale sample is rather complex and contact angle is therefore not representative. Imbibition results might be more reliable since fluids contacts with the whole sample.

Advances in Liquid Nitrogen Fracturing for Unconventional Oil and Gas Development: A Review

Liquid nitrogen (LN2) fracturing is an anhydrous fracturing technology that enhances coal permeability and supports unconventional oil and gas exploitation. In this Review, we provide a systematic review of five aspects of LN2 fracturing. They are the history of the technology’s development, research topics, factors influencing fracturing efficiency, fracturing mechanism, and engineering processes and systems. Liquid nitrogen fracturing transforms coal and rock pore structure through mechanisms such as low temperature, freeze–thaw damage, and gas expansion. It changes coal and rock mechanical properties and improves the pore penetration and efficiency of unconventional oil and gas extraction. However, in-depth studies are still required in many areas. They include theoretical studies of two-phase nitrogen flow in coal and rock, development of technical equipment to support field operations, and plans to monitor and evaluate fracturing efficiency. On the basis of the advances in LN2 fracturing research and the challenges, we conclude that future research should focus on multiphase flow and field equipment and technology.

Studies and Applications of Dual Pore Saturation Model Based on Pore Structure Classification in Tight Reservoirs

The complex pore structure of rock may influence resistivity logs and make it challenging to perform saturation estimations with better precision. For example, water saturation may go higher or lower when Archie’s formulae are used to obtain the saturation as the logging resistivity may become greater or smaller, due to the influences of complex pore structures in the reservoirs. In this paper, having considered the influences of pore structure on logging resistivity, we have developed a different algorithm to improve the equivalent rock element model (EREM, a rock conduction model) to have better water saturation. First of all, the nuclear magnetic resonance (NMR) echo data of cores are inverted by using the optimized inversion to calculate pore parameters, such as the average radius of spherical pore tubular pore, Cd path, and sorting coefficient. Secondly, according to the parameters derived from the optimization inversions, the pore structures of the core are divided into different groups. Based on the classifications of the pore structure, the conduction parameters of rock for different pore structures are determined by fitting the experimental conduction data of rock with a damping factor. Finally, the working flow of calculating fluid saturation according to the EREM model is determined for different conduction parameters. The key feature of the improved EREM saturation model is to eliminate the influence of pore structure on rock conduction, highlight the influence of pore fluid on rock conduction, and then improve the calculation accuracy of saturation in it. The applications of our research show that the saturation estimations derived from the improved EREM model appear to be more reasonable in terms of the saturation value and its numerical trend. Thus, the improved EREM model has potential in petroleum exploration and exploitation.

Influence of structural damage on evaluation of microscopic pore structure in marine continental transitional shale of the Southern North China Basin: A method based on the low-temperature N2 adsorption experiment

Structural damage from sample preparation processes such as cutting and polishing may change the pore structure of rocks. However, changes in pore structure caused by this structural damage from crushing and its effect on marine continental transitional shale have not been well documented. The changes of microscopic pore structure in marine continental transitional shale during the sample preparation have important research value for subsequent exploration and development of shale gas. In this study, the pore structures of transitional shale samples from the Shanxi-Taiyuan Formation of the Southern North China Basin under different degrees of damage were analyzed through low-temperature N2 adsorption experiments, combined with X-ray diffraction, total organic carbon, vitrinite reflectance analysis, and scanning electron microscopy. The results showed that (1) With increasing structural damage, the specific surface area (SSA) changed within relatively tight bounds, while the pore volume (PV) varied significantly, and the growth rate (maximum) exhibited a certain critical value with the crushing mesh number increasing from 20 to 200. (2) The ratio of SSA to PV can be used as a potential proxy for evaluating the influence of changes in the pore structure. (3) Correlation analysis revealed that the microscopic pore structure of marine continental transitional shale from the Shanxi-Taiyuan Formations is mainly controlled by organic matter and clay minerals. Clay minerals play a leading role in the development of microscopic pores and changes in pore structure.