Repurposing depleted offshore gas fields as CO2-plume geothermal (CPG) systems offers a cost-effective pathway to dispatchable, low-carbon power by leveraging existing subsurface data and infrastructure. This study develops and validates an integrated reservoir-wellbore-surface simulation framework for supercritical CO2 (sCO2) heat extraction and electricity generation. The reservoir and non-isothermal wellbore models are solved in COMSOL, and a time-marching coupling scheme transfers transient wellhead temperature, pressure, and mass-flow outputs to MATLAB-based surface power-conversion modules. Three power-generation options are assessed: an Organic Rankine Cycle (ORC), supercritical CO2 direct power generation (sCO2-DPG), and thermoelectric generation (TEG). Model reliability is confirmed by benchmarking the coupled reservoir-wellbore predictions against available analytical solutions and validating the thermodynamic cycle calculations with literature data. Applied to a realistic case in the Yingqiong Basin over a 50-year operating period, the three options exhibit distinct net-power characteristics when parasitic losses are considered (approximate to 20% for ORC and sCO2-DPG). The resulting installed capacities are 2.14 MW for TEG, 1.99 MW for ORC, and 1.58 MW for sCO2-DPG. Owing to its negligible auxiliary power demand and solid-state simplicity, TEG is identified as a competitive option for offshore deployment in this basin. The proposed coupled framework provides a practical tool for screening and designing geothermal repurposing projects in abandoned gas fields.

Hydraulic-fracture transmission across lithologic interfaces governs fracture-height growth and reservoir connectivity in shale–sandstone interbedded reservoirs, yet the coupled effects of mechanical contrast, interface properties, layer geometry, and operational parameters remain insufficiently quantified. A two-dimensional plane-strain hydraulic-fracturing model was developed in ABAQUS by coupling Biot poroelasticity, cohesive-zone damage, and fracture-fluid flow. The model explicitly represents thin, alternating continental shale–sandstone layers, lithology-dependent in situ stress and stiffness, and cohesive interfaces; its implementation was assessed against the KGD solution and published layered-rock fracture morphologies. Under the simulated conditions, increasing the shale-to-sandstone elastic-modulus ratio from 0.4–0.5 to 0.6–0.8 reduced the number of penetrated layers from eight to six. Increasing tensile strength from 4 to 16 MPa reduced the number of penetrated layers from ten to six and the final fracture length from 32 to 21 m, while increasing the maximum aperture from 6.75 to 9.02 mm. A sandstone interlayer thickness of approximately 3 m marked a transition in the present parameter set rather than a universal threshold. Sandstone-centered perforation and higher injection rates promoted vertical connectivity, whereas very high fluid viscosity increased near-wellbore aperture but restricted long-distance fracture-height growth. These results provide a mechanics-based framework for optimizing perforation placement and stage-specific fluid design in continental interbedded shale reservoirs.

In response to intensifying offshore exploration and the shift towards deeper, unconventional targets, this study addresses the Mesozoic buried hill naturally fractured condensate gas-cap reservoir in the Pearl River Mouth Basin, eastern South China Sea, which is characterized by pervasive fracture networks, elevated CO2 concentrations, and a high solution gas oil ratio conditions that render produced gas reinjection a technically and economically compelling enhanced oil recovery (EOR) strategy. Recognizing that optimization of injection-production parameters is essential for reliable reservoir development planning and technical decision-making, this study constructs a three-dimensional numerical model of a naturally fractured condensate reservoir using embedded discrete fracture modeling and compositional simulation techniques, and introduces a rapid optimization workflow that integrates Design of Experiments (DOE) with Response Surface Methodology (RSM). During the screening phase, a two-level Plackett-Burman design systematically evaluated ten candidate operational parameters, revealing that five principal factors of reinjection ratio, production rate, injection-production well ratio, injection period, and injection gas composition collectively account for 90.6 % of the variance in oil recovery. Subsequently, a three-level Box-Behnken design was applied to construct a second-order polynomial regression model relating the recovery factor (RF) to these key variables, demonstrating excellent concordance with compositional simulation results. Finally, response surface analysis delineated the optimal factor settings to maximize RF, and comparative simulations confirmed that CO2 injection yields a 0.84 % incremental increase in oil recovery relative to mixed natural-gas injection. The proposed methodology thus provides reservoir engineers with a statistically rigorous and computationally efficient framework for rapid evaluation and optimization of gas injection schemes under constrained simulation resources. The methodology can be readily applied to similar reservoirs to guide injection-production optimization under resource constraints, providing tangible economic and operational benefits for real-world EOR projects.

This study develops exact analytical solutions for transient elliptical groundwater flow toward an extended well in an anisotropic fractured confined aquifer and then discusses how the resulting hydraulic response can support groundwater-head interpretation in shale-gas development areas. The environmental connection is made at the aquifer-protection scale: the model is not a shale-gas reservoir production model, and it does not solve contaminant transport directly. Instead, it provides a hydraulic interpretation framework for estimating anisotropy, equivalent fracture length, wellbore-storage effects, and the preferential direction of head propagation around possible leakage points, old wells, fractures, or monitoring wells. Based on Mathieu-function theory and the separation-of-variables method, constant-rate and constant-head solutions are derived in Laplace space and inverted to the time domain with the Stehfest algorithm. The analytical results are validated against COMSOL5.2 finite-element simulations, and the effects of anisotropy coefficient and wellbore storage are analyzed through drawdown and flow-rate type curves. A synthetic but field-style water-head example is included to demonstrate how monitoring records can be converted to drawdown, fitted to the elliptical-flow solution, and used to delineate a preliminary hydraulic response zone. The results show that anisotropy mainly controls early-to-middle time response, whereas wellbore storage may obscure early head changes and delay the recognition of fracture connectivity. Therefore, the solution is best regarded as a rapid hydraulic-screening and monitoring-design tool that can precede, but not replace, site-specific contaminant-transport modeling in shale-gas groundwater-protection studies. The relevant technical issues are possible head disturbances and preferential groundwater pathways associated with surface spills, flowback-water handling, old wells, faults, and fracture-connected water-bearing zones. Because verified local field-monitoring records were not available for us, the application example is explicitly described as a synthetic field-style demonstration; it is used to show the workflow and its limitations, not to claim site-specific prediction of contaminant concentration.

Hydrate-based CO2 Sequestration (HBCS) targets deep-ocean settings (>3, 000 m) to exploit negative buoyancy to sink CO(2 )as a primary fail-safe. On the other hand, the vast potential of shallower continental slopes is often overlooked due to risks associated with positive buoyancy. In this study, a 600,000-year simulation of CO(2 )storage in sediments at a water depth of similar to 1,300 m in the Shenhu area of South China Sea is conducted with an extended TOUGH+Hydrate framework with improved salinity-dependent thermodynamics. Contrary to concerns over CO(2 )leakage, the results obtained reveal a robust hydrate cap-density pump coupling mechanism, which ensures long-term sequestration. A critical "temporal transition" process is identified: a self-sealing hydrate cap forms rapidly with liquid CO(2 )injection, serving as a transient barrier that effectively contains the buoyant plume for approximately 1000 years; such a containment time window secures the initiation of the density pump mechanism, which is driven by the gravitation-associated downward convective mixing of CO2 -saturated brine. The density pump mechanism is composed of two stages: liquid CO(2 )dissolution via intense brine fingering, followed by hydrate dissolution. As a result of the above process, all free-phase CO(2 )is sequestered with less leakage risk. Based on the results of this research, the continental slope is a potential place for safe, large-scale carbon neutrality.

Oilfield-associated geothermal energy represents a significant resource, and utilizing abandoned wells for heat extraction offers a promising and cost-effective approach to geothermal exploitation. This study proposes retrofitting two high water-cut vertical oil production wells into a U-shaped configuration to enable heat extraction via closed-loop water circulation. A numerical model is first developed to assess heat extraction performance, followed by an economic evaluation based on a net present value (NPV) model to determine the financial viability of this approach. The effects of various parameters on heat extraction and economic performance are systematically analyzed. The results indicate that repurposing high water-cut oil wells into U-shaped configurations for closed-loop heat extraction is a viable strategy to extend their productive life. For vertical wells with spacing of 218.21 m and an injection rate of 600 m3/day, the initial wellhead temperature of extracted hot water reaches 68.43 degrees C, with a corresponding heat extraction rate of 891.89 kW. A higher water circulation rate enhances the heat extraction but slightly lowers the wellhead temperature, with diminishing returns at higher rates. While increasing the injection temperature raises the wellhead temperature, it reduces the temperature gradient between the reservoir and circulating fluid, leading to a modest decline in heat extraction efficiency. Proper insulation along the production section of U-shaped wells improves the wellhead temperature and enhances the overall heat extraction efficiency. Economic analysis indicates that in configurations with a shorter horizontal section and limited heat exchange capacity, a higher circulation rate may paradoxically extend the payback period and reduce NPV. Similarly, higher injection temperatures decrease economic performance by narrowing the effective temperature gradient. Systems with shorter horizontal sections achieve rapid economic returns, while those with longer sections require more time to reach optimal economic benefits due to higher initial retrofit costs. The findings of this study can aid decision-making for optimizing the economic feasibility of geothermal energy extraction through the repurposing of abandoned oil production wells.

Abstract Proppant distribution within fractures is a crucial factor in enhancing the production from fracturing. Currently, most studies on the transport and settling behavior of proppants in fractures are based on the models of smooth, straight fracture. There is rarely research considering the effects of fracture tortuosity and roughness on proppant movement and settling. To further reveal the trends of proppant transport and setting in tortuous and rough fractures, physical experiments were conducted to observe proppant behavior in smooth and flat fractures firstly. Based on this, established tortuous and rough fracture models to explore proppant movement and settling patterns. Results indicate that larger proppant particle sizes are more conducive to settling within smooth plate fractures, and medium-to-large particle proppants are more likely to accumulate near the branch fracture entrances. For smooth-plate fractures, the increased the injection rates will allow proppants to penetration deeper into both main and branch fractures. For tortuous rough fractures, larger proppants are more impacted by fracture structure, often accumulating in the middle sections and causing blockage; however, increased injection speeds can effectively mitigate these blockages. These findings reveal the influence of various operational factors on proppant transport and settling, offering theoretical guidance for optimizing hydraulic fracturing techniques.

The HZ 26-B buried hill reservoir is located in the eastern part of the South China Sea. This reservoir is characterized by the development of natural fractures, a high density, and a complex geological structure, featuring an upper condensate gas layer and a lower volatile oil layer. These characteristics present significant challenges for oilfield exploration. To address these challenges, this study employed advanced embedded discrete fracture methods to conduct comprehensive numerical simulations of the fractured buried hill reservoirs. By meticulously characterizing the flow mechanisms within these reservoirs, the study not only reveals their unique characteristics but also establishes an embedded discrete fracture numerical model at the oilfield scale. Furthermore, a combination of single-factor sensitivity analysis and the Pearson correlation coefficient method was used to identify the primary controlling factors affecting the development of complex condensate reservoirs in ancient buried hills. The results indicate that the main factors influencing the production capacity are the matrix permeability, geomechanical effects, and natural fracture length. In contrast, the impact of the threshold pressure gradient and bottomhole flow pressure is relatively weak. This study’s findings provide a scientific basis for the efficient development of the HZ 26-B oilfield and offer valuable references and insights for the exploration and development of similar fractured buried hill reservoirs.

AbstractMost hot dry rock geothermal wells are small angle directional wells, and rock cuttings easily accumulate at the bottom of the borehole to form a cuttings bed, causing accidents such as drill sticking, reducing the rate of penetration, and drilling tool breakage. Accurately calculating the resistance coefficient and settling velocity of hot dry rock cuttings can improve cuttings transportation efficiency, design and optimize drilling hydraulic parameters, and is crucial to solving borehole cleaning problems. Through visual experiments, this paper obtained experimental data on the settlement of 167 groups of spherical pellets, 153 groups of granite cuttings, and 174 groups of carbonate cuttings in the Herschel-Bulkley fluid. First, a prediction model for the resistance coefficient of spherical pellets consistent with Herschel-Bulkley fluid was established. Based on this, form factor-Roundness is introduced as the starting point, and two prediction models for the resistance coefficients of granite cuttings and carbonate cuttings in the Herschel-Bulkley fluid were established. The average relative errors between the resistance coefficient model predictions and experimental measurements are 9.61% for granite cuttings and 6.59% for carbonate cuttings. The average relative errors between the predicted and measured values of settlement velocity are 7.27% for granite cuttings and 6.21% for carbonate cuttings, respectively, which verifies the accuracy and reliability of the prediction model. The research results can provide a theoretical basis and engineering application guidance for optimizing drilling fluid rheology and circulation displacement in engineering.

The Carboniferous carbonate reservoir of the Pre-Caspian basin has abundant oil and gas resources. The typical features of low porosity and low permeability and reservoir oil with high concentrations of H2S and CO2 and heavily dissolved gas-oil ratio allow produced gas reinjection as an effective and economic way to enhance oil recovery (EOR). However, the optimal design of injection/production parameters for gas injection processes is the premise for development scheme and technical decision. Compared to the conventional method of one-parameter-at-a-time approach with lack of interactions between various factors and tremendous challenge of main controlling factors identified, in this work we present a rapid optimization methodology to identify the main factors from numerous candidate parameters and obtain optimum levels of key factors. Our chosen methodology is a combination of experimental design with response surface method (RSM). Firstly, the two-level Plackett-Burman experimental design was used to screen and rank ten operational variables for the gas reinjection process. The top five significant parameters with the sum of their influencing weight greater than 94.3 % are bottomhole pressure for producers, reinjection ratio, injection period, injection gas timing and completion interval. Then the three-level Box-Behnken experimental design was employed to perform optimization exploration with the RSM. Regression models of the oil recovery factor (RF) were constructed by using these five key factors, which fits excellently with numerical simulation results. Finally, the optimal levels of controlling factors were determined to maximize oil recovery. This optimization procedure is very practical for reservoir engineers to guide a rapid evaluation of gas injection processes.

In the fourth spud of ultra-deep risk exploration well LH1 in Huabai Oilfield, complex conditions of lost circulation in upper formation, high pressure water and wellbore collapse in lower formation are drilled. To address the drilling complex and enhance well control, After failure of sealing the complex interval with traditional lost circulation materials like bridging agent and cement, reaming and expandable tube were decided to use to seal the complex interval without running additional casing and reduce the wellbore size. Through the analysis of the difficulties during operation, the corresponding countermeasures were established. Through reaming, wellbore tripping, calliper logging, casing scraping, expandable pipe running simulation tripping and rubber plug passing test, wellbore were well prepared to ensure the running, cementing and expanding of expandable pipe. The 838.15 m Φ219 mm expandable pipe was successfully run to 6080 m and expanded, which set a new record for the depth and length of expandable pipe in China. Subsequent cementing logs showed a overall medium cementing quality, and the complex well interval were able to withstand 2.27 g/cm3 drilling fluid without well loss compared to previous well loss ECD of 1.85 g/cm3. The successful application of reaming and expandable pipe technology in ultra-deep well LH1 showed that the combined technology can provide an effective and reliable new solution to solve the engineering problems such as excessive losses and casing program expansion in ultra-deep well.

Hydraulic fracturing is an essential technology in the development of coalbed methane reservoirs. Hydraulic fracturing can create a highly conductive fracture in the reservoir and increase its permeability. At present, the focus of coalbed methane reservoir fracturing optimization is gradually shifting to the fracturing scale. In the current development process, more and more coalbed methane blocks try to increase the fracturing scale to increase the gas production of coalbed methane wells. Field tests show that gas production of coalbed methane wells will increase to a certain extent with the increase of fracturing scale. However, the increase in the scale of fracturing also increases its cost. Therefore, the most economical fracturing scale is not necessarily the optimal fracturing scale for gas production. The field test usually pays more attention to the gas production effect, but the development of a coalbed methane field should pay more attention to the economic benefit, and the optimization of fracturing should take the economic benefit as the goal. Taking economic benefits as the starting point, this paper uses fracturing simulation to calculate the fracture extension under different geological conditions and different fracturing scales. It also uses numerical simulation to calculate the gas well productivity under different fracture extension conditions. The economic evaluation model was established to calculate the economic benefits under different fracturing scales, and the optimal fracturing scale was obtained. Finally, the typical maps of fracturing optimization under different geological conditions are formed. The optimization method of fracturing scale integrating economy, fracturing, and gas reservoir is realized. The research results have been successfully applied to the optimization scheme of Liulin block development, and very good results have been achieved. Because this method is targeted at different geological conditions, it can be used to guide the fracturing optimization of other coalbed methane blocks and has very important significance for the development and optimization of coalbed methane reservoirs.

Well interference has become a common phenomenon with the increasing scale of horizontal well fracturing. Recent studies on well interference in horizontal wells do not properly reflect the physical model of the postfracturing well groups and the realistic fracturing process of infill wells. Establishing the correspondence between well interference causative factors and manifestations is of great significance for infill well deployment and secondary oil recovery. In this work, we develop a numerical model that considers low velocity non-Darcy seepage in shale reservoirs to study the inter-well interference phenomenon that occurs in the Santanghu field, and construct an explicit hydraulic fracture and complex natural fracture network model with an embedded discrete fracture model, focusing on the effect of fracture network morphology on well interactions. The model also considers a multi-segment wellbore model to accommodate the effect of inter-well crossflow on wellbore tubular flow. The changes in formation pressure and water saturation during fracturing are performed by controlling the injection pressure and water injection rate. The result shows that the shape of the fracture network generated by the infill well with the old well determines the subsequent fluid and oil-increasing performance of the disturbed well. The synergistic production or competitive relationship formed by fractures with different connectivity between the two wells determines the positive and negative effects of the interference. The paper also investigates the adaptation study of water injection huff and puff schemes for well groups with different connectivity, and demonstrated a potential yield increase of up to 10.85% under adaptation injection. This method of identifying well interference based on the production dynamics of affected wells and the subsequent corresponding water injection method provides valuable references for the selection of secondary oil recovery measures.

The majority of China’s multi-layer low permeability tight gas reservoirs are currently being extracted through the method of multi-layer co-production. However, due to the significant disparity in physical properties and varying degrees of pressure depletion among the production layers, elucidating the primary factors influencing the productivity contribution of each gas layer remains challenging. A multi-factor analytical model is proposed for commingled gas wells with multiple layers. An unstable model is established for the production of commingled layers, and the problem of flow distribution is addressed using the Duhamel convolution principle. The Laplace transform is subsequently employed to derive the solution in the Laplace domain, which can be inverted utilizing the Stehfest inversion algorithm to obtain a real-time domain solution. The influence of reservoir factors on the stratification contribution rate has been comprehensively analyzed, encompassing permeability, porosity, initial pressure, drainage radius, and layer thickness. The orthogonal test design was employed to conduct range analysis and variance analysis separately, yielding the primary and secondary order as well as influence weight of the five factors. The findings demonstrate that, within this gas reservoir, the discharge radius, thickness, and porosity are identified as the primary factors influencing gas well productivity. Furthermore, seven horizontal flow charts illustrating the double-layer gas reservoir and five horizontal flow charts depicting single-factor variations in the double-layer gas reservoir were constructed. These charts provide a clear visualization of the impact of each reservoir factor on stratification’s contribution rate. In contrast to previous studies, this novel approach presents a comprehensive optimization framework that ranks the influence weights of individual factors and identifies the most significant factors impacting multi-layer gas reservoirs. The presented method also serves as a foundation for the subsequent selection of multi-layer gas reservoirs, formulation of gas well stimulation measures, and efficient development.

Underground reservoir technology can mitigate water shortage and pollution problems in water shortage coal mining areas and has a good application prospect. While still a new technology, the theory and method of underground reservoirs need to be improved. This research focused on the hydrochemical characteristics of mine water and their significance for the site selection of underground reservoirs. With the Shendong coal mining area as a case study, the hydrochemical major ions, toxicological indexes, and stable isotopes of hydrogen and oxygen were tested for the mine water samples, and the water quality was quantitatively evaluated and the origins of over-limit variables were investigated by hydrogeochemical numerical simulation and ionic ratio analysis. The influencing factors of water quality were analyzed and the significance of mine water quality for the site selection of underground reservoirs was discussed. The results show that the main over-standard variables are Na+, F−, SO42−, TDS, and sodium ion adsorption ratio (SAR), and a strong positive correlation exists between F− and SAR and a negative correlation exists between F− and Ca+. Na+ in mine water originates from the dissolution of halite and silicate rocks, as well as reverse cation exchange. F− originates from reverse cation exchange and the displacement between OH− in alkaline water and F− adsorbed on the surface of minerals. On the whole, the mine water quality is better on the east than on the west of the WL River. The water–rock interactions in goaf increase the concentrations of F− and Ca2+ and SAR. The areas where the mine water samples have low concentrations of Na+, F−, and low SAR values, such as the shallow coal seams at the SGT, DLT, and WL mines, are favorable sites for the underground reservoir. The outcomes may benefit the reasonable site selection of underground reservoirs in similar coal mining areas with water shortage.

During exploitation process of fractured reservoir, the complex distribution of natural fracture system may lead to a series of accidents, such as sand plug and multi fracture extension in hydraulic fracturing operation. Considering the difficulties of numerical analysis on formation rock mass fracture system distribution, three-dimensional geometry model of a single fracture formation is proposed in this paper, and fractal geometry method is introduced to build the three-dimensional fractal description model of formation fracture system distribution. On this basis, the effects of fractal parameters on natural fracture porosity, permeability and other properties are analyzed. The results show that: First, the number and propagation of natural fracture are controlled by the fractal dimension, the number of groups and the initial quantity. Second, the fractal dimension of natural fracture distribution has an obvious effect on natural fracture porosity and permeability. Third, porosity and permeability of natural fracture distribution both experience exponential growth as fractal dimension increases. Fourth, when the fractal dimension remains constant, the porosity and permeability of natural fractures both increase with the fracture scale.

Although tight oil reservoirs have abundant resources, their recovery efficiency is generally low. In recent years, CO2 injection huff-n-puff has become an effective method for improving oil recovery on the basis of depleted production of volume-fracturing horizontal wells in tight oil reservoirs. In order to study the effects of CO2 huff-n-puff (CO2-HnP) on production, a compositional numerical simulation study of CO2 huff-n-puff (CO2-HnP) was conducted in tight oil reservoirs with complex fractures. Embedded discrete fracture model technology was used in the simulations to characterize complex fractures. The process of CO2 huff-n-puff (CO2-HnP) was simulated, which consists of CO2 injection, CO2 soaking, and CO2 production. Taking into account the threshold pressure gradient and stress sensitivity in the model, we conducted a series of numerical simulations with different production condition parameters, such as bottom-hole pressure, CO2 injection rate, injection time, soaking time, and the number of cycles of CO2 huff-n-puff (CO2-HnP). Then, the effects of these sensitivity parameters on the cumulative oil production (COP) were studied. The results indicate that the threshold pressure gradient and rock stress sensitivity factors greatly affect the pressure field of tight reservoirs and the cumulative oil production (COP) of multistage-fracturing horizontal wells. The production parameters all have an impact on the COP. The injection rate and circulation number both have optimal values, and the injection time and soak time tend to have less significant effects on the growth of cumulative oil production over time. According to the numerical simulation, the optimal solution is 5 × 104 m3/day injection rate per cycle, 25 days of injection time, 35 days of soaking time, three cycles, and production for 5 years, which can obtain the optimal cumulative oil production.

The distributed acoustic sensor (DAS) uses a single optical cable as the sensing unit, which can capture the acoustic and vibration signals along the optical cable in real-time. So it is suitable for monitoring downhole production activities in the process of oil and gas development. The authors applied the DAS system in a gas production well in the South China Sea for in situ monitoring of the whole wellbore for the first time and obtained the distributed acoustic signals along the whole wellbore. These signals can clearly distinguish the vertical section, curve section, and horizontal production section. The collected acoustic signal with the frequency of approximately 50 Hz caused by the electric submersible pump exhibit a signal-to-noise ratio higher than 27 dB. By analyzing the acoustic signals in the production section, it can be located the layers with high gas production rates. Once an accurate physical model is built in the future, the gas production profile will be obtained. In addition, the DAS system can track the trajectory of downhole tools in the wellbore to guide the operation. Through the velocity analysis of the typical signals, the type of fluids in the wellbore can be distinguished. The successful application of the system provides a promising whole wellbore acoustic monitoring tool for the production of marine gas hydrate, with a good application prospect.

The macroscopic physical properties of rocks are profoundly determined by their microstructure, and the research of accurately characterizing rock pore structure has been extensively carried out in the fields of petroleum engineering and geoscience. Fractal geometry is an effective means of quantitatively estimating the pore structure properties of porous media. In this study, the evolution law of the fractal dimension and the quantitative relationship between the fractal dimension and porosity were investigated based on the digital 3D rock models. First, three kinds of models with gradually changing pore structures, namely sedimentation, compaction, and cementation, were systematically reconstructed by the process-based approach. Then, the fractal dimensions of the skeleton, pore, and surface of the models were computed and analyzed. Finally, the relationships among the fractal dimension, porosity, and complexity were explored qualitatively. These works reveal the changing laws of three types of fractal dimensions for different pore structure models. The pore structure differences in sedimentation model can only be distinguished by the surface fractal dimension, while both pore and surface fractal dimensions are available parameters for characterizing different pore structures in compaction and cementation models. The quantitative relations between box-counting fractal dimension and porosity were established, which can be expressed by combining linear and logarithmic formulas. The comparison of fractal dimensions of compaction and cementation models proves that fractal dimensions can distinguish the subtle pore structure differences in digital 3D rock models. Understanding the evolution law between the fractal dimension and pore structure parameters provides more references for classifying and evaluating rock pore structure features using fractal dimensions.