The deep coalbed methane (DCBM) reservoir is mainly composed of desorbed gas and meanwhile rich in free gas with the characteristics of high gas saturation. During the development of DCBM fields, changes of both reservoir pressure and gas saturation can result in production performances of DCBM wells, thereby influencing their productivities. Based on the Langmuir adsorption isotherm model, this work establishes a transient productivity model of gas-water two-phase and two-zone flows in DCBM fractured horizontal wells after consideration of the content of desorbed gas and free gas changing with the production time. Herein, gas well in Daning-Jixian Block on the Ordos Basin is used to validate this proposed model. Subsequently, comparisons of gas production rate, cumulative gas production and dynamic contribution rate including desorbed gas and free gas of Well JS-1 for 10 years in DCBM reservoirs are implemented, respectively. The results show that the daily gas production of DCBM wells increases rapidly at the early stage. After reaching the peak, it drops rapidly and then gradually declines slowly over the following two years. The daily gas production is composed of free gas and desorbed gas. At the early stage, the contribution rate of free gas is considerably high, while at the later stage, the contribution rate of desorbed gas is higher. The average shares of desorbed gas and free gas production are about 80% and 20% in the daily gas production throughout the entire period of 10 years, respectively. Furthermore, the cumulative gas production increases with the production time. The growth rate of cumulative gas production is faster at the early stage and slows down at the later stage. At the early stage, the contribution rate of cumulative free gas is relatively high in the cumulative gas production. After two years, the contribution rate of cumulative desorbed gas in the cumulative gas production exceeds that of cumulative free gas. Cumulative desorbed gas contribution is 63.54% and cumulative free gas contribution is 36.46% after 10 years. Hence, this model can be used for a judgement of well production performances and dynamic contribution rates including desorbed gas and free gas in DCBM fields throughout full life cycle. Besides, the method in this work has accurate, reliable and fast advantages, and provides theoretical and technical supports for efficient development of DCBM reservoirs.

Shale gas usually exists in a supercritical state in high-temperature and high-pressure reservoirs, but its existence state is affected by both temperature and pressure. Due to the limitations of temperature and pressure conditions, it is difficult to conduct in-depth research through experiments. Thus, it is necessary to apply a molecular dynamics (MD) simulation method to investigate the occurrence state and phase transition of supercritical CH4 serving as the research objective of this work. In this study, a MD model for a serration type of kerogen nanopore is established and implemented to verify the existence form of supercritical CH4 and investigate the process of CH4 entering the supercritical state. The novelty of this work is that the adsorption, diffusion and flow behaviors of supercritical CH4 through serration-type kerogen nanopores driven by pressure gradient under high-temperature and high-pressure conditions are simulated and clarified via a MD method. The key findings of this research show that at 5 MPa, CH4 begins to transform from liquid state to supercritical state at 192 K. Thus, there is a sharp decrease in density, where the rate of decrease is approximately 80 times that after 194 K. At 195 K and 5 MPa, CH4 begins to change from gas state to supercritical state, presenting a form of a sharp increase in density. Furthermore, in the supercritical state, increasing temperature weakens the adsorption capacity of CH4 and thus enhances the fluidity of CH4, while increasing pressure enhances the adsorption capacity of CH4 and thus weakens the fluidity of CH4. And increasing pressure gradient enhances the fluidity of CH4, but initially there is not a significant effect. Hence, the properties of supercritical CH4 are quantified, ultimately contributing to a comprehensive understanding of pressure-driven behaviors for supercritical CH4 adsorption and flow in high-temperature and high-pressure shale gas reservoirs.

Injection of CO2 into unconventional gas reservoirs and desorption of residual CH4 to enhance gas recovery currently are currently hot topics of research worldwide. In order to quantitatively determine the CO2 sequestration capacity and CH4 displacement efficiency during the carbon sequestration process, it is necessary to investigate the adsorption, desorption, flow, and displacement behaviors of CO2 and CH4 at the microscopic level. Thus, this work employs the molecular dynamics (MD) simulation method to assess the influence of CO2 displacement pressure on CH4/CO2 competitive adsorption and flow characteristics, CO2 sequestration, and storage efficiency. The novelty of this work is that a MD kerogen model of complex geological pore structure of shale is built and implemented to calculate the CH4 displacement efficiency, CO2 storage efficiency, and selectivity coefficient of CH4 and CO2 driven by pressure gradient. The key results of this study demonstrate that as CO2 molecules are injected into pores, the sequestration rate of CO2 in pores gradually decreases until it stabilizes. When the number of CH4 molecules in pores reaches a minimum value, the displacement stage is completed. Then, the CO2 and CH4 molecules in the pores are in a competitive adsorption state. Meanwhile, as the CO2 displacement pressure increases, the displacement efficiency gradually increases, while the storage efficiency first rises to reach its maximum value and then decreases. Hence, the CO2 displacement pressure plays a key role in achieving the optimal CO2 storage efficiency and CH4 displacement efficiency, ultimately contributing to the application of pressure-driven carbon sequestration in complex geological pore structures of shale.

Predicting the producing area of fracture-controlled unit created by hydraulic fracturing is crucial to fracturing evaluation, estimation of remaining reserves and formulation of development plan. Under the background of segmented multi-cluster fractured horizontal wells intercepted by line-shaped fractures, this study establishes a transient gas-water two-phase flow model to solve the analytical solutions of gas-water productivity, formation pressure and water saturation in water-bearing shale gas reservoirs, well matching with the field production data and simulation results. Subsequently, by delineating water saturation limit in an analytical nephogram, the producing area of fracture-controlled unit can be determined and calculated. The key contributions to producing areas and gas-water productivities at early, middle and late stages are dynamically identified via a sensitivity analysis, thus demonstrating that both fracture length and initial matrix water saturation are key factors contributing to the producing area and productivity. Meanwhile, the producing area shows a positive relation with matrix permeability, cluster spacing and fracture length whereas has a negative relation with initial matrix water saturation. Furthermore, their relationship between producing area and productivity is formulized to show an approximately linear characteristic. Thus, based on field productivities at different production times, their producing areas of fracture-controlled unit can be estimated to evaluate the potential of remaining reserves. This innovative approach with low requirements on the gas-water production dataset is convenient to yield a rapid prediction of dynamic reserves of gas reservoirs, thereby contributing to high-efficient development of unconventional gas resources.

Reservoir energy is generally measured in terms of the formation pressure and fluctuating pressure created by hydraulic fracturing results in the redistribution of flow field in a reservoir, thereby influencing horizontal well production. Thus, thoroughly investigating transient pressure behaviors of fractured reservoirs is considerably important for fracturing evaluation as well as productivity prediction. In this study, a transient pressure model of the horizontal well intercepted by line-shaped and tree-shaped fracture networks is established with consideration of real-time pressure interferences. Applying line-convergence function, Laplace transform, boundary element method, Stehfest numerical inversion and fractal theory, the transient pressure solution of the mathematical model is solved. Subsequently, validation is conducted by applying the proposed model to a series of cases considered in the literature. The novelty of this model is that the analytical pressure nephograms of the fractured reservoir coupled with the matrix, fracture network and horizontal well at different production times are first presented; the sensibility of fracture pressure interference is visually displayed; and a matching between fracture geometry characterization and reservoir pressure behaviors is comprehensively investigated. Meanwhile, the zone controlled by hydraulic network fracturing is quantified via a defined scope of pressure sweep boundary. Results show that there is a small pressure drop within the fracture while a huge pressure jump from the fracture to the matrix is generated on their contact boundary. This boundary pressure drop which is primarily determined by the fracture geometry characterization, drives the fluid from the low-permeability matrix to the high-conductivity fracture as the only way to the wellbore for fluid flow, thus yielding the well productivity. Hence, these findings contribute to promoting hydraulic network fracturing techniques, thereby fostering high-efficient and sustainable production of clean energy in unconventional gas reservoirs.

Although extensive studies have been conducted on the component ratios and performance of fire extinguishing foams, most research has not explored the coupling relationship between foam wettability and adhesion. Therefore, this study aims to develop an efficient foam extinguishing agent for solid fires by focusing on both wettability and adhesion. First, the influence of chemical functional groups on foam wettability and adhesion was elucidated, and the contributions of individual components to foam properties were experimentally investigated. Second, adhesion and wettability tests revealed a negative correlation between these two properties, consistent with variations in foam solution viscosity and wetting time. Third, a novel adhesion evaluation method was proposed, defined as the time required for foam to flow a fixed distance on inclined wooden surfaces; longer flow times indicated stronger adhesion. Fourth, foaming and fire suppression experiments confirmed the practical performance of the optimized formulations. A composition containing 8 wt% Polyoxyethylene ether and 5 wt% Sulfobetaine yielded a wetting-type foam suitable for rapid cooling, whereas 8 wt% Polyoxyethylene ether combined with 9 wt% Sulfobetaine produced an adhesive-type foam capable of persistent attachment to combustibles. Microscopic observations further demonstrated that foams with superior extinguishing performance developed dense lamellae.

Fracture identification after hydraulic fracturing of tight gas reservoirs is crucial to fracturing evaluation, productivity analysis, and production plan. Owing to fracture branching, bending, extending, and reversing in reservoirs, a simplified straight fracture cannot fully describe fracture characteristics. The novelty of this study is that the coupling mechanism between the complex fracture network characteristics and well production performances is figured out, thus achieving the identification of fracture morphology in fractured reservoirs. In this study, a combined model including Laplace transform, boundary element method, Stehfest numerical inversion, and fractal theory presents transient well performances. The key contributions to productivities at different production stages are dynamically identified via a sensitivity analysis. The results clearly indicate that the fracture total length is the key factor determining productivities due to no fracture interference at initial production stage. Furthermore, the logarithm of productivity linearly depends on the logarithm of production time and the productivity contribution rate equals the ratio of fracture length to total length. Thus, an updated inversion method is proposed by interpreting initial production data based on a tree-shaped fracture network associated with fracture total factor and cross-scale characteristics. The inversion results well match with their targets, with an error of no more than 5 %, ensuring the accuracy and validity of the proposed method. This innovative approach with low requirements on field data is convenient to yield an accurate prediction of fracture morphology, thereby providing a feasible strategy for promoting sustainable production of clean energy in unconventional gas reservoirs.

With the global energy consumption on the rise and the gradual decline in conventional oil production, unconventional reservoirs have received considerable attention in the last decade. However, due to the unique physical properties and a large number of micro/nanopores in unconventional reservoirs, fluid flow in these reservoirs is considerably different from conventional ones. Therefore, it is highly important to conduct research on elucidating these fluid flow mechanisms. Furthermore, to avoid problems associated with the rapid production decline and low recovery efficiency in such reservoirs, an enhanced oil recovery technology that can efficiently and economically develop unconventional reservoirs is urgently required. This paper systematically summarizes the current research on flow mechanisms, including capillary imbibition, molecular-scale fluid flow and productivity prediction in unconventional reservoirs, and introduces the enhanced oil recovery and application status of hydraulic fracturing assisted oil displacement technology, along with a brief analysis of their advantages and disadvantages. This study is intended to serve a reference for the efficient development of unconventional reservoirs. Document Type: Perspective Cited as: Wang, F., Xu, H., Wang, S., Deng, J., Wang, Y. Fluid flow and efficient development technologies in unconventional reservoirs: State-of-the-art methods and future perspectives. Advances in Geo-Energy Research, 2024, 12(3): 237-240. https://doi.org/10.46690/ager.2024.06.07

In water-bearing gas reservoirs, water existence affects gas production performances due to two-phase flows occurring in matrix and fracture systems. Under the background of staged multi-cluster fractured horizontal wells, this work focuses on an improved gas–water two-phase flow model accounting for physical contact behaviors of fractures with total factor characteristics. Combining a point-convergence method with fractal theory and applying Laplace transform and Stehfest numerical inversion, analytical solutions of this proposed model are solved to validate against the field production data and numerical simulation results. Subsequently, the analytical nephograms of formation pressure and water saturation at different stages are given for the first time, throughout which formation pressure and water saturation distributions at different locations of the fractured reservoir embedded with segmented multi-cluster tree-shaped fracture networks are visually exhibited. The results demonstrate that draining area evolution is limited to each segment at early stage and mid-stage, whereas these multi-cluster segments are really integrated into the whole draining area at late stage. Thus, the moving boundary of fracture-controlled unit is also delineated based on water saturation nephograms and expands with continuous production from 65 to 180 m in the y axis direction, contributing to the effective fracturing area for a high productivity. Furthermore, the share of free gas and adsorbed gas are 83% and 17% at early stage, while free gas and adsorbed gas account for 57% and 43% of total gas at the late stage. Those findings contribute to high-efficient and sustainable development of unconventional gas resources.

Vertically fractured wells have been widely used to develop tight gas reservoirs. Characterizing the geometry of fractures created by hydraulic fracturing is a key factor influencing the productivity of such wells. Appropriately modeling the shapes of actual fractures is thus important for accurately predicting the well productivity. Past research in the area has tended to simplify fractures into straight lines, but this does not adequately represent the complex hydraulic fractures encountered in fractured reservoirs. In this study, we propose a generalized model for the productivity of a vertically fractured well to capture the characteristics of hydraulic fractures in gas fields. The proposed model accounts for several relevant mechanisms, including Knudsen slippage, characteristics of complex fracture geometry, and interference caused by multiple fractures. We validate the proposed model by applying it to a series of cases considered in the literature, and analytically examine key parameters such as the fracture number Nf and characteristics of the fracture geometry, including the length ratio a, width ratio b, branching angle θ and level n, fracture penetration ratio l0re, asymmetry in the length of fracture wing, and fracture intersection angle φ et al. The results show that there is a small drop in pressure between the inlet and outlet of the fracture. The well productivity is found to be positively associated with Nf, l0re, φ, and asymmetry in the length of the fracture wing. Furthermore, the productivity of a well intercepted by tree-shaped fractures primarily depends on a and n, and is almost entirely unaffected by b. By contrast, the well productivity gradually decreases with increasing θ. A tree-shaped fracture significantly enhances the well productivity by 110% (a=0.9, n=3), compared with a straight fracture. Finally, we provide an approach to increase the productivity of vertical wells based on the findings of this study.

Fractured horizontal wells are widely utilized to develop tight gas reservoirs. Accurate productivity prediction of horizontal wells intercepted by complex hydraulically induced fractures is highly challenging due to fracture branching, bending, extending, and reversing in tight rock formations. Accounting for complex tree-shaped fracture geometries in reservoirs, this study proposes a cross-scale model of gas flows from the matrix to fractures. Using the proposed framework, the well productivity can be calculated in fractured gas reservoirs with any pore size and a fracture-controlled unit. The novelty of this study is that the total factor characteristics of fractures (i.e., length ratio a, width ratio b, branching angle theta, and branching level n), pressure drop coupling between the reservoir and fracture, and gas flow regime in different scale channels can be perfectly considered in the proposed model, from which the key contributions to well productivity are derived. Subsequently, the val-idity of the proposed cross-scale model is evaluated in comparison with the results of Ning et al. model and field well testing. The characteristic length L0,i, fracture effective width wf, stimulated reservoir volume Vf, fracture pressure pf, pressure gradient Gf, effective permeability kf and flow conductivity Cf of tree-shaped fractures are derived using the proposed model. The results show that the well productivity is jointly determined by Gf and Cf. Moreover, the well productivity mostly depends on a and n, and it is little influenced by b. In contrast, it is almost unaffected by theta. Compared to a straight fracture, a tree-shaped fracture with characteristic parameters of a = 0.9 and n = 3 can dramatically enhance the productivity by 32 % (b = 0.5; theta = 30 degrees ). In contrast, a tree-shaped fracture slightly increases the productivity by only 3 % when b increases from 0.1 to 0.9 (a = 0.2; theta = 30 degrees; n = 3). Furthermore, when theta is increased from 0 degrees to 90 degrees, the productivity of a well with a tree-shaped fracture decreases by 3 % (a = 0.2; b = 0.6; n = 3). Hence, the study findings will contribute to the exploitation of tight gas reservoirs.

In shale, pore structure plays an extremely significant effect on CH4 storage and transportation in a reservoir, especially for the reservoir involving large amounts of extremely tiny nanopore and variance of microstructure. In this study, three molecular dynamics models for different types of kerogen nanopores such as serration type, arc type and great-wall type are established, validated and implemented to assess the impact of pore structure on CH4 adsorption and diffusion behaviors in kerogen matrix and nanopore at temperature 320 380 K, pressure 5 20 MPa and pore size 3 5 nm. The simulation results demonstrate that the CH4 density in the bulk of serration-type, arc-type and great-wall-type pores is 1.6, 1.3 and 1.9 higher than that inside kerogen molecules. Increasing temperature can weaken the adsorption capacity of kerogen, but the serration-type pore is the most sensitive to temperature. Regardless of the pore type, increasing pressure can significantly enhance the adsorption capacity of kerogen which is almost unaffected by pore size, whereas the CH4 diffusion coefficient increases with pore size. Furthermore, the great-wall-type pore can adsorb more CH4 molecules due to its smooth surface, followed by change in the arc-type and serration-type pores in turn. Among these types of pores, the CH4 diffusion coefficient is the most insensitive to the size of arc-type pore. Hence, the influences of kerogen pore structure under different conditions of temperature, pressure and pore size are quantified in this work to improve a comprehensive understanding of CH4 adsorption and diffusion behaviors in shale, thereby contributing to highefficient and sustainable development of shale gas reservoirs.

This study simulated the adsorption and separation of CO2 by the metal-organic frameworks material M-MOF-74, established the skeleton model of M-MOF-74 series adsorbent, and calculated the adsorption of CO2 pure component gas and CO2/N2 mixed gas on M-MOF-74 series adsorbent by the grand canonical Monte Carlo method. Among the CO2 adsorption performances of MOF-74 materials with metal centers of Mg, Co, Ni, and Zn, Mg-MOF-74 had the highest CO2 adsorption capacity, adsorption selection coefficient and adsorption heat. When mixed gas was adsorbed, the law of CO2 adsorption was consistent with that of pure CO2 adsorption. The size law of adsorption heat on MOF-74 was similar to that of adsorption amount. Our findings demonstrated that the interaction between the metal-organic framework material and CO2 is greater than that between the material and N2. The interaction between the gas and the MOF-74 series adsorbent was the main factor affecting the adsorption amount, which reveals the strong influence of metal central atoms on the amount of gas adsorption. Our findings provide new ideas for the design of efficient adsorbent materials.

分子模拟技术作为研究纳米尺度下物质行为的关键技术,在页岩油气开采的微观机理研究方面已成为一种重要的研究手段.本文首先概述了分子模拟技术的原理和方法,对页岩储层的常见分子模型进行了总结,对表征页岩油气在储层的分布特征和动力学性质的物理参数如吸附热、吸附能、密度分布、径向分布函数和扩散系数及应用案例等进行了分析;分析总结了温度、压力、孔径、孔壁类型、组分性质对页岩油气吸附特性的影响及机理;重点介绍了分子动力学模拟纳米限域内单相和两相流动中流体黏度变化、黏附和滑移的边界条件导致的流速低于或高于泊肃叶公式预测流速的现象;并对表活剂驱替及渗吸、超临界二氧化碳吞吐页岩油技术中基于分子动力学的微观作用机理进行了阐释.最后总结了分子模拟技术在非常规油气资源开发的优缺点,并提出分子模拟技术在页岩油气领域的未来发展趋势,为非常规油气的开发提供了微观尺度的理论支撑.

In shale gas exploration, gas adsorbed on the surface of porous medium results in a change in pore size, which is closely relevant to permeability, flow rate, and production capacity of shale gas reservoirs, especially for the reservoir containing large numbers of pores and slits. Thus, the present work investigates the adsorption mechanism and adsorption layer thickness during CH4 flow driven by the pressure gradient in nano-slits by using molecular dynamics simulation. Herein, a slit-pore model in terms of gas storage and grapheme pore is developed, implemented, and verified. The effects of the pressure, temperature, pressure gradient, and pore size on adsorption properties and adsorption layer thickness of CH4 are also examined. Results show that the relative adsorption capacity is positively correlated with the pressure gradient and pore size and negatively correlated with the system pressure, whereas unaffected by temperature. Moreover, the adsorption layer thickness decreases with the pressure and is almost unaffected by the pore size under the small pore size, whereas increasing with the pressure gradient and temperature. The descending order of sensibility to the adsorption layer thickness is temperature, pressure gradient, pore size, and system pressure. Hence, based on those findings, a new formula for calculating the adsorption layer thickness is proposed for the quantitative determination of the effective pore size of porous medium when gas flows in slits, thereby contributing to shale gas high-efficient exploration.

In fractured tight gas reservoirs, complex hydraulically induced fracture networks determine fluid flowing abilities of reservoirs. Thus, characterizing the complex fracture networks and revealing fracture transfer performances become a challenging work because of fracture branching, bending, and reversing in fractured reservoirs. In this paper, a fractal-like tree-shaped fracture model for gas transfer is proposed to optimize flow conductivity, pressure distribution at fracture intersection points, and flow transfer in such a complex fracture network considering the multi-scale effect, and total factor characteristics, including the length ratio, width ratio, branching angle, and branching level. The model is implemented to conduct validation against the experiment data in the literature. Subsequently, applying the proposed fracture model, the productivity equation for a vertical gas well intercepted by the fractal-like tree-shaped fracture network is further formulated. In addition, the good match with productivity simulation validates the accuracy of the developed productivity model for a vertical gas well. As a result, the impacts of the Knudsen number, fracture total factor characteristics, reservoir parameters, etc. on fracture transfer performances and well productivity are examined using the two proposed models. The results demonstrate that optimum fracture transfer performances do not match with the maximum well productivity. In contrast, the well productivity is jointly determined by both inlet flow volume of the fracture network and matrix permeability. Hence, a new formula considering both fracture characteristics and reservoir properties is proposed to match with the optimum fracture total length and maximum well productivity, thereby contributing to high-efficient and economic exploration of tight gas reservoirs.

铁素体不锈钢(ferritic stainless steel,FSS)是中温化环境中固体氧化物燃料电池(solid oxide fuel cell,SOFC)的理想连接体材料.但由于FSS中含有较多的Cr元素,在SOFC工作过程中,连接体表面生成的Cr 氧化物薄膜增厚,会造成连接体导电性能下降;FSS中的Cr元素与H2O或O2发生反应,还会形成易挥发的化合物,这些化合物在阴极界面沉积,将使阴极活性降低,导致阴极"Cr中毒"和SOFC性能衰减,严重制约了 SOFC商业化发展和应用.采用电沉积-热处理技术在FSS表面制备Co-Mn尖晶石保护涂层可有效防止Cr化合物的挥发,改善电池堆的抗氧化性能.在保证SOFC导电性的同时,延长其使用寿命.综述了 FSS表面电沉积-热处理制备Co-Mn尖晶石涂层的主要方法、特点及涂层性能等方面的研究进展,对该领域未来的发展趋势进行了展望.

The process of spontaneous imbibition is the basis of oil recovery from tight oil reservoirs. In this study,spontaneous imbibition experiments were conducted based on tight oil weakly hydrophilic sandstone cores from the Honghe oilfield in the Ordos Basin. Four different types of surfactants,such as nonionic Triton X-100,nonionic Tween-80,cationic dodecyl trimethyl ammonium bromide,and anionic sodium dodecyl benzene sulfonate,were separately dissolved in 30 g/L potassium chloride solution as simulated formation water. The effects of surfactant type on spontaneous imbibition were analyzed,and the results indicated that,because the nonions are adsorbed on the surface via Van der Waals force and adsorb H+ through hydrogen bonds,the two nonionic surfactants altered the wettability of the core from weakly hydrophilic to strongly hydrophilic,the recovery rate was relatively high. The Triton X-100 was selected for subsequent spontaneous imbibition experiments by changing the mass concentration to adjust interfacial tension. It was found that the maximum recovery rate was 32% when the Triton X-100 mass concentration was 0.1%,which indicates that the enhanced recovery rate of spontaneous imbibition requires a sufficiently low wettability factor and a suitably high interfacial tension factor. Finally,the surfactants mixed with 0.03% sodium dodecylbenzene sulfonate and 0.1% Triton X-100 were used for spontaneous imbibition,attaining an oil recovery of up to 45%,which was 21.6% higher than that of single-surfactant imbibition. It was established that the synergistic mechanism depends on the wettability alteration of nonionic surfactant facilitating the spontaneous imbibition,while the anion accelerates oil removal from the core by continuously encasing oil droplets in the aqueous phase. This paper provides a theoretical basis for the imbibition development of weakly hydrophilic tight sandstone with high-salinity formation water.

H13 steel has often been used as a hot-work die material. However, it tends to undergo failure because of wear and crack generation under high-temperature and high-pressure working conditions. Laser cladding is an effective remanufacturing method for such materials. However, the temperature gradient and cooling rate of the formation process are very large owing to rapid cooling and heating characteristics, often inducing excess thermal stress and cracking of the coating. Herein, a numerical simulation of a laser cladding 316L/H13+20%WC composite coating on H13 steel surface was performed. The variation in the temperature gradient and cooling rate with time and the influence of substrate preheating on the temperature gradient and cooling rate were studied. Moreover, to verify the numerical simulation results, a laser cladding formation test of the composite coating was conducted on the H13 steel substrate. Experimental results show that substrate preheating can significantly reduce the temperature gradient and cooling rate on the top surface of the coating and exerts a certain restraining effect on the cracks of the sample surface. The findings of this study provide a reference for the laser cladding modification and repair of H13 steel dies.