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Abstract Shale reservoirs have complex mineral compositions and are rich in micro-scale pores. It is of great scientific and engineering significance to explore the mechanism of external fluids on the pore throat structure of shale. In this paper, pure carbonaceous shale is taken as the research object, and the mechanism of the influence of slip water and reflux fluid on the pore throat structure is analyzed by using nuclear magnetic resonance (NMR) technology. Then, the sensitivity of different types of shale to external fluids is comparatively analyzed and summarized. The results show that (1) the oil slick has a certain effect on the total porosity of different types of shale. The rate of change is shown as carbonaceous shale (− 7.1%) > pure shale (− 1.6%). (b) For slickwater, the average reduction of macro- and micro/nanopores in carbonaceous shale is 90.0% and 5.0%, respectively, while the average reduction of macro- and mesopores in pure shale is 17.7% and 6.8%, respectively. (c) Total porosity of different shale types is insensitive to refluxing fluids. The average increase in macro-, meso-, and small pores of carbonaceous shale is 31.8%, 23.6%, and 20.2%, respectively; the average increase in macro- and small pores of pure shale is 17.1%.

Horizontal salt caverns represent a prime choice for energy storage within bedded salt formations. Constructing multi-step horizontal salt caverns involves intricate fluid and chemical dynamics, including salt boundary dissolution, cavern development, brine flow, heat transfer, and species transportation. In this paper, the influence of heat transfer and turbulent flow is considered in developing a 3D multi-physics coupled flow model for the construction of multi-step horizontal salt caverns. The feasibility and accuracy of the model are verified by comparisons with the field data of the Volgograd horizontal salt cavern. The effects of turbulent flow and heat transfer on the dissolution process are thoroughly analyzed. By analyzing the characteristics of the flow field, the brine concentration distribution, and cavern expansion, the results indicate a steady rise in cavity brine concentrations throughout the leaching phases, with the previously formed cavities continuing to enlarge during subsequent leaching stages, albeit at a diminishing rate of expansion. Furthermore, the results reveal that a larger injection flow rate results in a larger cavern volume, whereas higher injection concentrations result in smaller cavern volumes. While the step distance has a minimal impact on cavern volume, identifying the optimal step distance remains crucial. This analysis of construction parameters aims to provide valuable insights into the design and engineering practices involved in developing multi-step horizontal salt caverns for energy storage purposes.

Oil-water two-phase flow through the complex pipeline, consisting of varying pipes and fittings in series or parallel, is commonly encountered in the petroleum industry. However, the majority of the current study is mainly limited to single constant-radius pipe. In this paper, a unified model of oil-water two-phase flow in the complex pipeline is developed based on the combination of pipe serial-parallel theory, flow pattern transformation criterion, two-fluid model, and homogenous model. A case is present to verify the unified model and compare with CFD results. The results show that the proposed unified model can achieve excellent performance in predicting both the flow distributions and pressure drops of oil-water two-phase flow in the complex pipeline. Compared with CFD results for water volumetric fractions ranging from 0% to 100%, the highest absolute percentage error of the proposed model is 14.4% and the average is 9.8%.

The prediction accuracy of the five horizontal wellbore single-phase drop models (Siwon, Asheim, Su, Yuan, Ouyang) is evaluated and compared based on the high-quality experimental data measured by a self-developed experimental system with large size horizontal wellbore (ID: 139.7 mm). The results show that the pressure drop prediction accuracy of the five models is, from high to low, Ouyang, Siwon, Asheim, Yuan, and Su. Generally, the Su and Yuan models have high predictions and the Siwon and Asheim model have low predictions. The Ouyang model has good prediction performance, its average relative error is only 5.5%, and the example also proves its good prediction effect, but it can't represent complex mechanisms such as the resistance effect caused by wall perforation. The models for predicting the pressure drop of single-phase flow in a horizontal wellbore need to be further improved to completely represent complex mechanisms of the variable mass flow in the horizontal wellbore, such as the resistance effect caused by wall perforation and lubrication flow drag reduction effect caused by wall influx. Key words: pressure drop model, horizontal wellbore, perforated completion, large-scale wellbore, prediction accuracy evaluation

In the process of thermal recovery of heavy oil, the energy exchanges with its surrounding environment during steam migration in a tube, so as to heat will be lost and the steam enthalpy will decrease gradually. It will seriously affect the steam-simulation effect of heavy oil wells if string structure, horizontal section length, steam injection volume, and steam dryness are not reasonably designed. Therefore, the accurate calculation and forecast of thermodynamic parameters of steam along the wellbore, such as pressure, temperature, and dryness, is the key to evaluate the gas injection effect. It also has great significance for the optimization of steam-simulated parameters. In this paper, a dynamic model for calculating thermal parameters in horizontal wells with steam huff and puff is established based on one-dimensional unsteady heat-transfer theory, in which the characteristics of the variable mass flow in the horizontal segment is considered. The results shows that the maximum relative error between the calculation results and the measured data is less than 5%, which proves the accuracy of the model. The effect of wellhead steam parameters on the distribution of steam thermodynamic parameters in horizontal wellbore is almost consistent. The steam-injection rate is in direct proportion to the horizontal wellbore extension distance. In addition, the influence of steam-injection time on steam temperature, pressure, and dryness can be ignored. [ABSTRACT FROM AUTHOR]

In this article, a more-general flow-pattern classification of oil/water two-phase flow in the horizontal wellbore is proposed first according to the theoretical analysis and previous research achievements, on the basis of which a simplification is then performed through reasonable incorporation, and the ultimate flow patterns considered for modeling are reduced to two categories containing only six standard patterns. By use of the classical twofluid and homogeneous modeling methodologies stemming from oil/water two-phase flow in conventional pipes, combined with the simplified classification, a mechanistic model is developed to predict the flow characteristics including the flow patterns and pressure losses for oil/water two-phase variable-mass flow in the horizontal wellbore. Model implementation is performed on the basis of the universal principle that a system will stabilize to the equilibrium state of minimum energy. Overall performance of the mechanistic model is then validated against the new data sets measured upon a large-scale experimental apparatus at the China University of Petroleum (CUP), which is designed and constructed to simulate the gas/oil/water multiphase flow in horizontal wellbores with wall mass transfer. Results show that the model developed in this paper can not only properly predict the flow patterns of oil/water two-phase flow in the horizontal wellbore, but also has high prediction accuracy for the pressure drops. Compared with the new experimental data for oil/water two-phase variable-mass flow that covers a series of input water-volumetric fractions ranging from 10 to 90%, the highest absolute average percentage error of the new unified model is 12% and the whole error is 9.2%, which demonstrates an acceptable performance. Investigations conducted in this study further enrich and develop the theory of hydrodynamic calculation for oil/water flow in the horizontal wellbore with wall influx. [ABSTRACT FROM AUTHOR]