Carbonates have great potential for development, but the use of propped hydraulic fracturing or acid fracturing stimulation types alone has limited effectiveness. This study collected four sets of rock samples from three carbonate reservoirs: dolomite, limy dolomite, and limestone. The laboratory analysis focuses on propped hydraulic fracturing, acid fracturing, and acid fracturing plus proppants of these rock types. The aim is to assess acid erosion, proppant embedment depth, and the impact of varying proppant sizes and acid injection on fracture conductivity. The results showed that acid fracturing substantially enhanced the hydraulic conductivity of the three rocks. The embedded depth of the small-sized proppant was greater, but the fracture conductivity of the large-sized proppant was greater. Under the conditions of the actual pressure of formation of 55.2 MPa in the target reservoir, using 70/140 mesh proppant, 20% thickened acid, and an injection rate of 20 mL/min: for the dolomite-type rock, the propped hydraulic fracturing method had the highest fracture conductivity, which reached 151.17 D·cm. For the limy dolomite-type rock, the acid fracturing plus proppant experiment had the highest fracture conductivity, which was 157.26 D·cm. For limestone-type rocks, acid fracturing had the highest fracture conductivity of 210.39 D·cm. This study helps to elucidate the mechanism of different stimulation types and provides useful guidance for the more effective development of carbonate oil and gas reservoirs.

This study investigated the mechanisms influencing hydraulic fracture propagation under the influence of cleat complex geometries. The study established a 3D-DEM (three-dimensional discrete element method) model for complex fracture propagation, utilizing the discrete element method and incorporating complex cleat geometries. The model simulates the propagation patterns of hydraulic fractures within coal seams. The findings indicate the following: (1) The fracture width within coal seam cleats undergoes significant variations. A quantification method for these variations and a novel concept of cleat-induced fracture deflection angle are proposed. As the cleat angle increases from 0° to 45°, the cleat-induced fracture deflection angle also increases, reaching 17.1°, demonstrating that cleats have a directional inducing effect on hydraulic fracture propagation; (2) injection hole pressure decreases during fracture capture by coal cleats, whereas pressure escalation occurs during penetration through these cleats; (3) a smaller angle between the face cleat orientation and the direction of maximum principal stress results in longer fracture lengths and narrower fracture widths; and (4) higher injection rates augment the fracture width, facilitating the entry of proppants.

In this paper, a two dimensional-discrete element method complex fracture extension model was developed to simulate the fracture extension behavior in reservoirs during multi-cluster perforation fracturing of horizontal wells by particulate flow and considering temporary plugging conditions. The effect of particle inhomogeneity on the extension of multi-cluster fractures, the change of fracture extending characteristics before and after temporary plugging, and the effect of geological and construction parameters on the extension of multi-cluster fractures under the consideration of temporary plugging conditions are investigated in this model. The results show that: (1) the middle cluster is more difficult to extend than the outermost cluster due to interstitial stress interference; the increased nonuniformity of particles aggravates interstitial stress interference and favors shear fracture extension. (2) Fractures expand substantially when the fracturing fluid reaches 3/4 of the total fluid volume; after temporary plugging, it can promote the uniform extension of fractures and increase the total length of fractures, but the fractures formed in the middle are easy to be captured by the fractures at the two ends and expand along it, and it is not easy to form complex fractures; the timing of plugging is based on the percentage of perforation clusters with fractures already formed, with fracture extension being preferred. (3) The horizontal principal stress difference mainly affects the direction of fracture extension; the number of clusters mainly affects the uniformity of fracture extension; and the fluid flow mainly affects the length of fracture extension.

With the continuous advancement of coal resource extraction and coalbed methane (CBM) development, revealing the propagation laws of hydraulic fractures in cleated thin-layer coal rocks has become particularly important. This study establishes a three-dimensional complex fracture propagation model considering the cleat system based on the Block Discrete Element Method, systematically investigating the influences of geological, engineering, and perforation factors on hydraulic fracture propagation in coal seams. The results show that: (1) the thickness of coal seams affects the expansion pattern of hydraulic fracture networks by regulating stress distribution, showing a positive correlation with hydraulic fracture length and width, and a negative correlation with fracture height. (2) Cleat spacing significantly affects the fracture network in cleated thin-layer coal rocks; smaller spacing leads to more frequent interactions between fractures and cleat surfaces, resulting in a more complex network. (3) Cleat angle exerts a notable guiding effect on the propagation direction of fractures in thin coal seams; the maximum fracture deflection angle and higher fracture complexity index occur at a cleat angle of 45°. (4) A high injection rate (16–20 m3/min) effectively increases fracture width and stimulated reservoir volume in cleated thin-layer coal rocks, while reducing the risk of fracture penetration into the roof and floor, thus improving CBM recovery efficiency. The findings provide a theoretical basis and technical support for efficient CBM development.

With growing global energy demand, deep and ultra-deep wells have become a focal point in oil and gas development. Wellbore temperature variations significantly impact drilling and completion operations in such wells. To analyze the temperature distribution in ultra-deep wellbores, a numerical model based on the Gauss–Seidel iterative algorithm was developed. This model explicitly accounts for the convective heat transfer coefficient and the distinct thermophysical properties of drilling fluids in both the drill string and the annulus. By employing adaptive meshing, it significantly enhances computational efficiency while ensuring accuracy. This study investigated the influence of key parameters—including drilling fluid density, specific heat capacity, drill pipe thermal conductivity, and formation properties—on bottom-hole temperature. The results show that the average deviation between the actual wellbore temperature and the model-predicted temperature is 0.5%. The heat transfer dynamics model for ultra-deep wells is validated by the close agreement between theoretical predictions and field data. This study offers a valuable theoretical basis for wellbore temperature management and the control of drilling fluid cooling systems, supporting safer and more efficient development of ultra-deep resources.