Experimental study on physical modeling of flow mechanism in volumetric fracturing of tight oil reservoir

Abstract

This paper investigates the characteristics of oil–water two-phase flow after volumetric fracturing of horizontal wells in tight reservoirs. Based on a large-scale high-pressure, high-temperature experimental system for modeling horizontal well injection and production, the characteristics of the pressure distribution, cumulative liquid production, recovery factor, and liquid production rate of a matrix model and fractured model during the waterflooding process are compared and analyzed. The results show that, for both types of reservoirs, the fluid forms a high-pressure zone and a low-pressure zone during water injection. As the development progresses, the high-pressure zone continuously moves forward. There is a pressure step between the high-pressure zone and the low-pressure zone, which gradually decreases in magnitude as the pressure wave reaches the well. By this time, the main resistance before water breakthrough is the pressure step at the waterflooding front. The ultimate recovery is found to be 26.71% for the matrix model and 28.48% for the fractured model. Without an effective displacement system, the resistance of the horizontal well during waterflooding mainly acts on the oil–water interface. After the establishment of an effective displacement scheme, the resistance gradually expands to both sides of the water-swept zone. At this point, the formation of a dominant channel greatly weakens the displacement performance. Thus, it is necessary to rely on imbibition or surfactants in the later stages to improve the recovery factor.

Geological Characteristics of Lower Paleozoic Shale Gas Accumulation in the Yuxi Region, Southern Sichuan Basin: In View of High-Density Methane Inclusions

“…The calculated results show that the density of methane inclusions in the Longmaxi shale fracture calcite veins in well H201 varied from 0.257 to 0.275 g/cm 3 and that of the Wufeng-Longmaxi shales in well H202 varied from 0.274 to 0.285 g/cm 3 .…”

“…where ρ is the density of methane inclusions (g/cm 3 ) and D = v 1 − v 0 , in which v 1 is the measured methane Raman scattering peak of methane inclusions and v 0 is the methane Raman scattering peak of methane inclusions when the pressure is close to 0.…”

“…Based on eq 2, the density of methane inclusions varies greatly, which can be divided into low-pressure gas-phase methane inclusions and supercritical high-density methane inclusions. Subsequent research needs to select supercritical high-density methane inclusions, so the calculated density of well H201 according to Raman spectroscopy ranges from 0.249 to 0.286 g/ cm 3 , with an average of 0.270 g/cm 3 and that of well H202 ranges from 0.246 to 0.293 g/cm 3 , with an average of 0.264 g/ cm 3 ; there is no Raman reflection peak in methane inclusions observed in well Z202 (Table 2). The density of methane inclusions calculated by this method is similar to that obtained by microtemperature measurement of methane inclusions.…”

“…China has great potential for unconventional resource development, − among which shale gas is the mainstay of natural gas. , Currently, several sets of shale gas formations have been discovered in the Sichuan Basin, among which the Upper Ordovician Wufeng Formation-Lower Silurian Longmaxi Formation is the main field of shale gas exploration and development in China. Shale gas demonstration areas such as Changning, Weiyuan, Fuling, and Zhaotong have been successively established to realize economies of scale development in medium and shallow layers with a burial depth of 2000–3500 m .…”

A Fundamental Moving Boundary Problem of 1D Commingled Preferential Darcian Flow and Non-Darcian Flow Through Dual-Layered Porous Media

“…Abundant physical experiments (Bear, 1972;Prada and Civan, 1999;Dou et al, 2014;Wang et al, 2016;Hu et al, 2018;Tian et al, 2018;Wang and Cheng, 2020;Chi and Wang, 2021;Zhao et al, 2021;Yin et al, 2022) and theoretical analysis (Cai, 2014;Wang et al, 2018;Zhang et al, 2018;Zhang et al, 2019a;Ye et al, 2019) have demonstrated when the formation permeability is low, the seepage flow in the formation will belong to the low-velocity non-Darcian flow with a threshold pressure gradient (TPG). The TPG can introduce additional formation energy consumption, which hinders the fluid flow ability through the formation.…”