ABSTRACT: Fuxing continental shale is characterized by poor physical property, strong heterogeneity, low brittleness index, and poor compressibility. Based on the concept of integrated geological and engineering, differential staged fracturing technology of horizontal well was proposed to unlock the production potential and enable commercial productivity. This paper takes well X as an example to perform fracturing design and field application. Firstly, the basic parameters of well X, such as porosity, gas-bearing property, mineral composition, rock mechanic, crustal stress and so on were introduced. Then, a series of numerical simulation was conduct to investigate the effect of pre-fluid, injection rate, natural fractures by using unconventional reservoir model (UFM). Finally, the field application of differential staged fracturing was performed and post-fracturing effect was evaluated by using micro-seismic monitoring technology. Laboratory experiments and logging interpretation show that the porosity of the target layer is 2.85∼6.66%, Young's modulus is 22-34 GPa, Poisson's ratio is 0.2∼0.3, and the horizontal stress difference is 6-10 MPa. Numerical simulation results show that the preferred single fracturing section length is 42-72m, the number of clusters is 6-8, the clusters spacing is 7-9m, the viscosity of pre-flush fluid is 50-100mpa.s, and the discharge rate is 18-20m3/min. Micro-seismic monitoring shows that fracture size is basically formed when the fluid strength exceeds 35 m3/m. This study provides a theoretical basis and reference for the efficient stimulation of continental shale oil. 1. INTRODUCTION China's continental shale oil resources are abundant. Sixteen sets of shale formations have developed in basins such as Songliao, Ordos, Junggar, Bohai Bay, Sichuan, and Qaidam(Li et al., 2022; Sun et al., 2023). The rejuvenation area of the Sichuan Basin is an important area for exploration, increase, and production of shale oil and gas in China. The Fuling, Changning, Weirong, and Yongchuan shale oil and gas fields have been successively discovered. The proved oil and gas reserves exceed 2×1012m3. Continental shale oil differs from marine shale oil. It is characterized by low total organic carbon(TOC), low formation pressure, high clay content, strong plasticity, and low brittleness(Wei et al., 2022).There are significant lateral variations in sedimentary facies, and strong heterogeneity exists. These characteristics determine that the experience of transforming marine shale in North America cannot be simply replicated for continental shale oil. Typically, this type of reservoir utilizes horizontal well closely spaced multi-stage fracturing technology to remodel the target reservoir, aiming to expand the scale of fracture control and achieve the goal of increasing and stabilizing production(Huang et al., 2022; Zhang, 2021). Conventionally, geometric well completions are employed, which evenly distribute stage clusters along the horizontal well section. Statistical results from multi-stage fracturing of horizontal wells in the United States indicate that conventional geometric well completions result in preferential fracturing of clusters corresponding to low stress within the section, with over half of the clusters failing to achieve successful fracturing, leading to insufficient transformation of the target formation and consequently reducing production and increasing construction costs(Waters et al., 2006). 70% of oil and gas production comes from perforation clusters corresponding to low stress in each fracturing stage (Miller et al., 2011). Tang et al. (Tang et al., 2023; Wang et al., 2022; Chen et al.) conducted fracturing design on continental shale oil reservoirs in various regions and found that the main construction parameters affecting reservoir transformation were cluster number, cluster spacing, the viscosity of pre-flush fluid, and the discharge rate.

Abstract The naturally fractured carbonate gas reservoir of Majiagou formation in Ordos Basin is characterized by mixed mineralogy. Since mineralogy determines acid-rock reaction rate, mineral distribution has significant effect on the fracture surface etching profile. Therefore, it is necessary to investigate effect of mixed mineralogy on etching profile and fracture conductivity. In this paper we conducted the research from two aspects: experiment and numerical modeling. In the experiment, we firstly measured mineral distribution by hyperspectral scanning on the core slabs, then did acid flooding, next did 3D scanning to get etching profile, and finally measured acid fracture conductivity, based on which an acid fracture conductivity correlation was built. In numerical modeling, based on mass conservation principle, acid-rock reaction kinetics, and momentum theorem, a 3D acid flow, acid-rock reaction, surface etching model was developed. Mineral distribution on the surfaces was coupled as boundary conditions. Experimentally measured mineral distribution on the slab surface are coupled into the numerical simulation. The model is validated by the experimental results. Based on the model, extensive numerical simulation was conducted to analyze mineral distribution, acid-rock contact time, and temperature on the surface etching pattern and acid concentration distribution. By combining the experimental results and numerical simulation, how the mineral distribution affect etching profile, facture conductivity, and acid concentration distribution is analyzed. The study shows that for mixed mineralogy carbonate, the distribution of mineral is strongly spatially correlated instead of random distribution. Mineral stripes are observed from the mineralogy scanning of core slabs. Due to reaction rate contrast of different minerals and strong spatially correlated distribution, the surface etching profiles are rough, and the channel is obvious. The channels resulted from multiple mineral distribution contributes remarkably to the fracture conductivity. With the similar amount of rock dissolved, the fracture with channels has a much higher conductivity. Temperature has remarkable effect on etching profile. At a high temperature (e.g. 90°C), the difference of overall reaction rate for limestone and dolomite is small, and the etching discrepancy for calcite and dolomite is less. At a low temperature (e.g. 60°C), the difference of overall reaction rate is large, so the etching discrepancy is more distinct. Dolomite surface has an apparent higher acid concentration than limestone at a low temperature, while surface acid concentration is close for calcite and dolomite at a high temperature. The impurities such as quartz, clay, gypsum, etc. are not dissolved by the acid. Even small amount of impurities contributes to the differential etching on the surfaces. In the lab scale, the acid concentration inside the fracture has identifiable decrease from the inlet to the outlet.

In vuggy, naturally fractured carbonate reservoirs, hydrocarbon is mainly stored in vugs and natural fractures (NFs). To enhance oil production in such reservoirs, matrix acidizing is used to generate wormholes to connect the wellbore with NFs and vugs. Due to the simultaneous existence of NFs and vugs, the acid flow and interaction with rock in acidizing is complicated, and the wormhole propagation behavior needs to be clarified. To this end, the pore structure characterization method accounting for the matrix, vugs, and NFs is established based on geostatistics methods, which is then combined with the two-scale wormhole model to simulate wormhole propagation in the vuggy, naturally fractured carbonate reservoirs. The effects of geological factors and engineering factors on wormholing behavior are analyzed through extensive numerical simulations. The research shows that both the dimensionless correlation length and the areal proportion of vugs affect wormhole propagation. There is an optimal combination of the dimensionless correlation length and the areal proportion (evaluated by comprehensive influence coefficient), rendering more vugs being connected with wormholes. NFs have a dominant effect on wormhole propagation. The optimal natural fracture density and dimensionless length of NFs exist for a given formation with the same vug distribution. The distribution of the NFs and the vugs has a dominant effect on wormhole pattern and vugs that can be connected. In engineering practice, retarded acid system with low diffusion coefficient of hydrogen ions (H+) is recommended to obtain longer wormholes so as to increase the possibility of connecting remote vugs with the wellbore. Meanwhile, for vuggy, naturally fractured carbonate reservoirs, increasing the injection rate promotes acid flow in NFs, facilitating wormhole propagation and connecting with more vugs with the same injection volume as long as the pumping pressure is lower than the formation breaking pressure. This research provides theoretical basis for matrix acidizing in vuggy, naturally fractured carbonate reservoirs.

In situ-generated acid is commonly employed in ultra-deep, high-temperature carbonate reservoirs during acid fracturing to increase the effective acid penetration distance. However, the variation pattern of acid-etched fracture conductivity with in situ-generated acid has not been systematically studied. This paper investigates the evolution of the conductivity of primary and secondary fractures through a series of experiments involving in situ acid displacement and acid-etched fracture conductivity measurement. Based on the experimental results, a calculation model for the conductivity of acid-etched fractures with in situ-generated acid was established. The study indicates that after acid etching, rough particulate points and grooved dissolution patterns form on the surfaces of primary and secondary fractures, respectively. The dissolution volume in primary fractures is greater than that in secondary fractures, with both showing a linear increase over time. Due to the presence of dissolution grooves on the surfaces of secondary fractures, their conductivity is higher than that of primary fractures under the same acid–rock contact time. The conductivity of both primary and secondary fractures increases with the acid–rock contact time. However, beyond approximately 70 min of contact time, the conductivity of primary fractures shows no significant increase. The conductivity of primary and secondary fractures with in situ-generated acid is slightly lower than that with gelled acid under the same contact time, but significantly higher than that with crosslinked acid. This study provides guidance for the design and parameter optimization of acid fracturing in ultra-deep, high-temperature carbonate reservoirs.

Successful exploitation of the fractured-vuggy carbonate reservoirs (FVCR) requires establishing long-term connectivity between the wellbore and vugs where hydrocarbon is stored. Acid fracturing is a common practice to create passageways for such reservoirs. However, the fracture propagation behavior is complex due to the interaction among hydraulic fractures (HFs), natural fractures (NFs), and vugs. Yet, a comprehensive investigation accounting for the geological genesis of FVCRs, fracture propagation behavior analysis, and exploitation strategies has not been conducted so far. To this end, taking the Shunbei oil field, Tarim Basin, China, as an example, this study using the RFPA (Realistic Failure Process Analysis) simulator classifies the possible NF distribution patterns in the Shunbei oil field through forward modeling in the first place. Then, the interaction mechanism among HFs, NFs, and vugs is analyzed from the perspective of damage mechanics. The results indicate that the vugs can be connected either hydraulically or mechanically. Finally, the field scale fracture propagation simulations are performed to examine the effect of engineering parameters and geological properties on the stimulation effectiveness. The exploitation strategies for different geological conditions are proposed based on the field scale simulation.

Tight naturally fractured carbonate reservoirs require acid fracturing to build the connectivity between the wellbore and natural fractures (NFs), where hydrocarbon is stored. The high leakoff nature of the NF complicates the acid flow and etching pattern, raising the difficulty in acid fracturing design and optimization. To explore the acid flow and reaction behavior in such reservoirs, an acid fracturing model accounting for the NF distribution is developed, which consists of a fracture surface characterization model, a fracture propagation model, and an acid-etching model. Based on the model, the effects of injection parameters and the NF properties on the effectiveness of acid fracturing are investigated. Then, strategies for acid fracturing the tight naturally fractured carbonate reservoirs are proposed. Results show that high pumping rates and retarded acids with low hydrogen ion (H+) diffusion coefficient is conducive to achieving a long acid penetration distance, while a low pumping rate and acids with a high H+ diffusion coefficient facilitates the NF etching. Therefore, a large stimulated area can be achieved by applying a multi-stage alternating injection of the crosslinked acid with a high pumping rate followed by the gelled acid with a low injection rate. NFs impact acid fracturing in two distinct ways: enhancing the non-uniform etching of the fracture surface and reducing the effective acid-etched fracture length through high leakoff. When NF density is high, leakoff control techniques should be employed; and when the NF inclination is high, non-uniform etching techniques should be used to generate acid-etched channels in flow barriers.

The Shunbei oil formation is a deep, high-temperature carbonate reservoir. Acid fracturing is an effective technology to stimulate this formation. For acid fracturing, the temperature field is fundamental information for the acid system selection, acid–rock reaction, live acid penetration distance prediction, acid fracturing design, etc. Therefore, in this paper, we conduct a numerical study on the temperature field in acid fracturing to account for the acid–rock reaction in the Shunbei formation. Firstly, a new mathematical model of the fracture temperature field during acid fracturing is established based on the laws of mass and energy conservation and acid–rock reaction kinetics. The fracture model is based on a PKN model, which accounts for a few factors, such as the acid–rock reaction heat, acid–rock reaction rate dependence on the temperature, and the fracture width change with acid erosion. Then, the numerical mode is developed. Next, an extensive numerical study and a parameter analysis are conducted based on the model with the field data from the Shunbei formation. The study shows that the acid–rock reaction in acid fracturing has obvious effects on the temperature field, resulting in a 10~20 °C increase in the Shunbei formation. The acid–rock reaction dependence on temperature is a factor to be accounted for. The rock dissolution increases first and then decreases from the inlet to the tip of the fracture, unlike the monotonous decrease without temperature dependence. The temperature gradient is high near the inlet and then decreases gradually. Beyond half of the fracture, the temperature is close to the formation temperature. The temperature drops fast in the initial injection stage and tends to stabilize at about 50 min.

Hydraulic fracturing promotes the shale gas revolution worldwide. Since most of the fracturing fluids used now are water-based, shale hydration could happen before and after the treatment. However, the effects of shale hydration on hydraulic fracture initiation, fracture complexity, and proppant distribution have not been clarified. Thus, we performed shale hydration experiments on thin discs and cubic specimens under confining conditions to investigate the microstructure evolution through the scanning electron microscope (SEM) and acoustic emission (AE) system. Later, the hydrated cubic specimens were fractured to examine the impact of shale hydration on hydraulic fracturing through CT scanning. The results show that under confining conditions, water imbibition volume increases with time, but the effect of the fluid pressure inside the perforation on shale hydration is limited. The SEM images show that the preexisting microfractures extend at the beginning but stop growing with width reduction in 6 h, which is indirectly evidenced by the AE. The confining pressure inhibits the preexisting microfractures from opening and further propagation, resulting in closure of the microfractures near the perforation and the water imbibition stagnating. Those findings obtained from hydration experiments are verified by the hydraulic fracturing experiments, which show that the breakdown pressure increases with shale hydration. Meanwhile, the CT scanning shows that the fractures initiated from the vertical perforation become more complex after hydration, which leads to the width reduction of individual fractures and, consequently, poor proppant distribution. Therefore, it is suggested to utilize the optimal hydration time when microfractures expand or use clay inhibitors to decrease the breakdown pressure and facilitate the proppant placement.

Thin interbedded tight sandstone of Shanxi Formation in Ordos basin, China, contains mudstone interlayers and laminas universally, and exhibits ultra-low matrix permeability, low brittleness, and areal heterogeneity. The stimulation effectiveness of this formation depends largely on whether multiple hydraulic fractures (HFs) can initiate and penetrate into the multiple thin sandstone layers upward and downward. To clarify the multi-fracture growth behavior of such formation, multi-cluster fracturing experiment in the horizontal well was performed on specimens prepared from the sandstone-mudstone outcrops of Shanxi Formation based on a true triaxial fracturing simulation system. The influences of interlayer stress difference, mudstone thickness, fluid viscosity, pumping rate and the number of clusters were mainly analyzed through post-fracturing specimen splitting and pressure curve analysis. Results show that the difference of rock mechanical parameters between sandstone and mudstone is relatively large. When interlayer stress difference is less than 3 MPa, the mudstone layer cannot function as a barrier to restrain the vertical growth of HFs, and the essential mechanism causing HF height containment is mainly the opening of laminas or/and interfaces. By contrast, when the interlayer stress difference is equal to or greater than 3 MPa and the dimensionless thickness of mudstone is more than 0.4, the HF height tends to be restrained. Increasing the fluid viscosity or/and pumping rate can reduce filtration, and fa-cilitates HFs penetrating through the laminas or interfaces and consequently propagating into adjacent layers. It has been observed that when fluid viscosity reaches 100 mPa s (cross-linked gel) and pumping rate is 100 mL/ min, HFs can pass through the overlaying mudstones. However, uniform initiation of all clusters is difficult to achieve due to the low brittleness of sandstone and heterogeneity along the horizontal wellbore. The experi-mental results prove that temporary plugging within the wellbore using the plugging agent of appropriate particle size is necessary to create multiple HFs in such formation.

Temporary plugging and diverting fracturing (TPDF) is widely used to improve the stimulation effectiveness in coal seam. To study the fracture propagation behavior during TPDF in coal formation, a series of laboratory hydraulic fracturing experiments were performed on natural coal samples. Based on the results of sample splitting and fracture reconstruction, the influences of horizontal stress difference and the size of temporary plugging agent (TPA) as well as the concentration of TPA on hydraulic fracture growth were analyzed. Experimental results show that TPDF is beneficial for improving the fracture complexity even under high stress difference of 8 MPa. When the TPA of small particle size (70/100 mesh) was applied, the primary fracture could not be fully blocked whereas increasing the particle size of TPA to 20/40 mesh tended to cause accumulation and bridging in the wellbore, resulting in an abnormally high fracturing pressure. TPA with particle size of 40/70 mesh tended to be a reasonable choice for the target formation, as it could form effective plugging in primary fractures and promote the generation of new fractures. Meanwhile, optimizing the concentration of TPA was also conducive to improving the plugging effectiveness. Effective temporary plugging can be achieved by using appropriate TPA of proper size and concentration, which varies with different treatment parameters and formations. Laboratory experiments are expected to provide guidance for the parameter optimization for TPDF in coal seam.

Shale reservoirs contain a certain amount of clay minerals, which can hydrate through imbibition when in contact with various water-based fluids during drilling and completion. Shale hydration can lead to structural changes in the shale such as the expansion of bedding planes and propagation of microfractures, consequently affecting the initiation and propagation of hydraulic fractures. However, the effect of shale hydration under confining pressure on hydraulic fracture propagation and stimulation effect is still unclear. To this end, a novel experimental method integrating shale hydration and hydraulic fracturing was proposed based on the laboratory triaxial hydraulic fracturing simulation system. This method enables a more realistic simulation of shale hydration and hydraulic fracturing process happening in downhole conditions. The experimental results show that under simulated reservoir conditions, water imbibition increases over time with the imbibition rate reaching its peak within 24 h. The breakdown pressure, number of fractures, and complexity of fractures are positively correlated with imbibition time. The increase in fracture complexity could be attributed to the increase in the number of fractures. In contrast, imbibition pressure (injection pressure for imbibition) has little influence on water imbibition. For specimens under different imbibition pressure, the breakdown pressure and the number of fractures are close, and the complexity of fractures does not change prominently; all are T-shaped fractures. It is believed that the closure of microfractures under confining pressure caused by hydration is the main reason for the increase in breakdown pressure. Higher breakdown pressure means higher net pressure in the wellbore, which facilitates fracture initiation where the breakdown pressure is higher. Therefore, shale hydration is conducive to the initiation of multiple fractures, thus increasing the number and complexity of fractures.