Shiyuan Li

Conventional Diagnostic Fracture Injection Tests (DFITs) are widely used for formation pressure estimation, but in practice, they frequently require days, weeks, or even months of extended shut-in periods, a challenge particularly pronounced when large injection volumes are coupled with ultra-low formation permeability. While recent studies have proposed various modified DFIT approaches to reduce testing time, direct physical validation confirming the reliability of the derived formation pressure estimates remains scarce in the literature. This study applies a low-rate/volume injection mini-frac approach that integrates flow regime identification and Horner analysis. Two complementary field cases are presented: a standard DFIT in a shale reservoir to validate the baseline methodology, and a low-volume mini-frac in a tight granite formation to demonstrate rapid estimation. Results show that low-volume injections exhibit a flow regime evolution identical to standard DFITs, yet this approach is expected to accelerate the transition to the pseudo-radial flow regime. To verify the reliability of formation pressure estimates derived from such methods, the formation pressure estimated in the low-rate/volume injection mini-frac case was benchmarked against a decade of continuous downhole fluid pressure monitoring data from the same well, yielding a relative error of less than 5%. The findings suggest that employing a lower injection rate and volume can improve formation pressure testing efficiency, with potential applications in unconventional hydrocarbon development and deep geo-energy engineering.

Composite salt formation is a high-quality caprock for oil and gas resources. The accident encountered in composite salt formation drilling is a big problem to be solved in the drilling process. According to statistics, nearly 50% of drilling accidents occur in composite salt formations. The composite salt formation is mainly composed of salt, gypsum, and interbed mud, and the lithology is complex and changeable. Therefore, it is very important to study the deformation mechanism and leading influencing factors of composite salt formation in view of the problem of frequent accidents in the drilling process. In this article, the creep parameters based on the constitutive equation of creep of salt rock are obtained by combining theoretical with experimental research. A three-dimensional directional wellbore mechanical model is established to analyze the influence of inclination on borehole shrinkage.

Hydraulic fracturing is the main means for developing low-permeability shale reservoirs. Whether to produce artificial fractures with sufficient conductivity is an important criterion for hydraulic fracturing evaluation. The presence of clay and organic matter in the shale gives the shale creep, which makes the shale reservoir deform with time and reduces the conductivity of the fracture. In the past, the influence of shale creep was ignored in the study of artificial fracture conductivity, or the viscoelastic model was used to predict the conductivity, which represents an inaccuracy compared to the actual situation. Based on the classical Perzyna viscoplastic model, the elasto-viscoplastic constitutive model was obtained by introducing isotropic hardening, and the model parameters were obtained by fitting the triaxial compression creep experimental data under different differential stresses. Then, the constitutive model was programmed in a software platform using the return mapping algorithm, and the model was verified through the numerical simulation of the triaxial creep experiment. Then, the creep calculation results of the viscoplastic constitutive model and the power law model were compared. Finally, the viscoplastic constitutive model was applied to the simulation of the long-term conductivity of the fracture to study the influence of creep on the fracture width, and sensitivity analysis of the influencing factors of the fracture width was carried out. The results show that the numerical calculation results of the viscoplastic model were in agreement with the experimental data. The decrease in fracture width caused by pore pressure dissipation and reservoir creep after 72 h accounts for 32.07% of the total fracture width decrease.

The directional wells can effectively improve the development efficiency of deep and ultra-deep pre-salt oil and gas reservoirs in the Kuqa Mountains of Tarim basin. Under the condition of deep temperature and pressure, the mechanical properties of the composite salt-gypsum layers are complex. During the directional drilling process, that the salt rock is easy to creep causes the drill stick. Under the condition of controlling the well inclination, it is difficult to choose the appropriate drilling fluid density to resist creep and thus maintain the stability of the wellbore. On the basis of rock mechanics experiments, this study established a two-dimensional finite element model considering the combination of composite salt-gypsum layers and inclined well with the effect of in-situ stress, analyzed the influence of temperature, differential stress and well deviation on the salt rock creep. The density of drilling fluid for preventing creep sticking is calculated, and a safe drilling fluid density chart for preventing creep shrinkage of composite salt-gypsum layers is compiled. The results show that when the differential stress is less than 10 MPa, the creep rate of the Tarim composite salt-gypsum layers are at least 10 times higher than that of the Gulf of Mexico salt layers; the creep rate increases with the increase of the differential stress and temperature, and the creep rate is an incremental curve; taking the highly deviated well in the Bozi area as an example, where the shrinkage ratio caused by sticking is set to be 5%, the drilling fluid density chart for creep resistance at 45° and 60° inclination is built, which is consistent with the actual drilling in the field. The results can provide design basis for the selection of anti-creep drilling fluid density in the directional wells in the Kuqa Piedmont composite salt-gypsum layers.

The composite salt layer of the Kuqa piedmont zone in the Tarim Basin is characterized by deep burial, complex tectonic stress, and interbedding between salt rocks and mudstone. Drilling such salt layers is associated with frequent salt rock creep and inter-salt rock lost circulation, which results in high challenges for safe drilling. Especially, the drilling and completion processes of the salt-gypsum layers of one typical group are found with frequent downhole accidents and complex issues, such as hole shrinkage, sticking, well kick, and lost circulation, which leads to high difficulties in delivering desirable cementing quality and severely hinders the subsequent safe rapid drilling. Reaming while drilling can effectively enlarge the wellbore diameter, provide extra tolerance for creep shrinkage of salt layers, and ultimately help to shorten drilling time, reduce accidents and complex issues, and improve the lifecycle of wells. In this research, a numerical simulation method was developed to invert the creep laws of composite salt layers, based on reaming while drilling. It is generally believed that the dislocation creep mechanism is dominant in coarse-grained salt rocks, while the pressure solution creep mechanism is dominant in fine-grained salt rocks. Here a well in the Dabei area was taken as an example and the numerical simulation of hole shrinkage at the wellbore scale was performed, based on the actual data before and after reaming and also the theoretical analysis of the two salt rock creep mechanisms and corresponding laws. Furthermore, the inversion results were validated using field data. This research discussed the selection of creep parameters and their variation, in cases of the dominance of the dislocation creep and pressure solution creep mechanisms. This presented method can accurately predict the creep behavior of salt layers and can be used as an effective supplement tool for other test methods like laboratory experiments.

This paper studies the impact of shape factor on a mass-based hybrid nanofluid model for Homann stagnation-point flow in porous media. The HAM-based Mathematica package BVPh 2.0 is suitable for determining approximate solutions of coupled nonlinear ordinary differential equations with boundary conditions. This analysis involves discussions of the impact of the many physical parameters generated in the proposed model. The results show that skin friction coefficients of Cf_x and Cf_y increase with the mass of the first and second nanoparticles of the hybrid nanofluids w₁ and w₂ and with the coefficient of permeability in porous media. For the axisymmetric case of γ = 0, when w₁ = w₂ = 10 gr, w_f = 100 gr and Cf_x = Cf_y = 2.03443, 2.27994, 2.50681, and 3.10222 for σ = 0, 1, 2, and 5. Compared with w₁ = w₂ = 10 gr, w_f = 100 gr, and σ = 0, it can be found that the wall shear stress values increase by 12.06%, 23.21%, and 52.48%, respectively. As the mass of the first and second nanoparticles of the mass-based hybrid nanofluid model increases, the local Nusselt number Nu_x increases. Values of Nu_x obviously decrease and change with an increase in the coefficient of permeability in the range of γ < 0; otherwise, Nu_x is less affected in the range of γ > 0. According to the calculation results, the platelet-shaped nanoparticles in the mass-based hybrid nanofluid model can achieve maximum heat transfer rates and minimum surface friction.

A non-Darcy flow with moving boundary conditions in a low-permeability reservoir was solved using the homotopy analysis method (HAM), which was converted into a fixed-boundary mathematical model via similarity transformation. Approximate analytical solutions based on the HAM are guaranteed to be more accurate than exact analytical solutions, with relative errors between 0.0089% and 2.64%. When λ = 0, the pressure drop of the Darcy seepage model could be instantaneously transmitted to infinity. When λ > 0, the pressure drop curve of the non-Darcy seepage model exhibited the characteristics of tight support, which was clearly different from the Darcy seepage model’s formation pressure distribution curve. According to the results of the HAM, a moving boundary is more influenced by threshold pressure gradients with a longer time. When the threshold pressure gradients were smaller, the moving boundaries move more quickly and are more sensitive to external influences. One-dimensional, low-permeability porous media with a non-Darcy flow with moving boundary conditions can be reduced to a Darcy seepage model if the threshold pressure gradient values tend to zero.

The composite salt formations in West China are characterized by the deep burial, complex tectonic stress, and alternating development of salt rock and mudstone, and salt rock creep during drilling poses great challenges to the safety of drilling. This research is aimed at the serious blockage and sticking in build-up sections in deep composite salt formations. A 2D mechanical model for inclined wells penetrating multiple vertical layers was established by combining the analysis of creep mechanisms of composite salt formations with the high-temperature creep experiment results so as to investigate the wellbore stability of directional wells in composite salt formations in a certain block from the perspective of rock mechanics and probe the influence of inclination angles on borehole shrinkage under different in situ stress and interlayer conditions. Moreover, a directional well in the block was taken as an example to analyze the creep and borehole shrinkage in composite salt formations. The method for wellbore stability control was proposed, and the drilling fluid density chart was established. This research reveals the relationship among the wellbore trajectory, the degree of borehole shrinkage, and drilling fluid density in build-up sections of directional wells in composite salt formations and provides a theoretical reference for the establishment of the method for controlling blockage and sticking accidents in directional wells.

This paper studies the convective heat transfer of a hybrid nanofluid in the inclined channel, whose walls are both heated by the uniform heat flux. The governing ordinary differential equations are made nondimensional and solved analytically, in which explicit distributions of velocity, temperature and pressure are obtained. The effects of flow reversal, wall skin friction and Nusselt number with the hybrid nanofluid depend on the nanoparticle volume fractions and pressure parameters. The obtained results indicate that the nanoparticle volume fractions play a key role in delaying the occurrence of the flow reversal. The hybrid nanofluids hold more delayed range than conventional nanofluids, which is about 2.5 times that of nanofluids. The calculations have been compared with the base fluid, nanofluid and two kinds of hybrid models (type II and type III). The hybrid model of type III is useful and simplified in that it omits the nonlinear terms due to the interaction of different nanoparticle volumetric fractions, with the relative error less than 3%. More results are discussed in the results section below.