Preparation and Performance Evaluation of CO2 Foam Gel Fracturing Fluid

Abstract

The utilization of CO₂ foam gel fracturing fluid offers several significant advantages, including minimal reservoir damage, reduced water consumption during application, enhanced cleaning efficiency, and additional beneficial properties. However, several current CO₂ foam gel fracturing fluid systems face challenges, such as complex preparation processes and insufficient viscosity, which limit their proppant transport capacity. To address these issues, this work develops a novel CO₂ foam gel fracturing fluid system characterized by simple preparation and robust foam stability. This system was optimized by incorporating a thickening agent CZJ-1 in conjunction with a foaming agent YFP-1. The results of static sand-carrying experiments indicate that under varying temperatures and sand-fluid ratio conditions, the proppant settling velocity is significantly low. Furthermore, the static sand-carrying capacity of the CO₂ foam gel fracturing fluid exceeds that of the base fluid. The stable and dense foam gel effectively encapsulates the proppant, thereby improving sand-carrying capacity. In high-temperature shear tests, conducted at a shear rate of 170 s^-1 and a temperature of 110 °C for 90 min, the apparent viscosity of the CO₂ foam gel fracturing fluid remained above 20 mPa·s after shear, demonstrating excellent high-temperature shear resistance. This work introduces a novel CO₂ foam gel fracturing fluid system that is specifically tailored for low-permeability reservoir fracturing and extraction. The system shows significant promise for the efficient development of low-pressure, low-permeability, and water-sensitive reservoirs, as well as for the effective utilization and sequestration of CO₂.

Keywords: CO2 foam gel fracturing fluid; high-temperature shear resistance; sand-carrying performance; unconventional oil and gas resources.

Figure 1

Foaming volume of foaming agent screening experiment.

Figure 2

Half-life of foam in foaming agent screening experiment.

Figure 3

Foaming volume in thickening agent screening experiment.

Figure 4

Half-life of foam in thickening agent screening experiment.

Figure 5

Variable temperature sand-carrying experiment with a high-temperature visualized static sand-carrying sealed device.

Figure 6

Variable temperature sand-carrying experiment with a measuring cylinder.

Figure 7

Sand-carrying experiment with a large sand ratio using a visualized static sand-carrying sealed device.

Figure 8

Sand-carrying experiment with a large sand ratio using a measuring cylinder.

Figure 9

Steady shear curve of the CO₂ foam gel fracturing fluid.

Figure 10

Test on temperature and shear resistance of base fluid.

Figure 11

Test on temperature and shear resistance of the CO₂ foam gel fracturing fluid.

Figure 12

Schematic diagram of the CO₂ foam gel fracturing fluid preparation.

Figure 13

High-temperature visualized static sand-carrying sealed device: 1—fracturing fluid inlet valve; 2—transparent observation window; 3—temperature controlled cylinder; 4—pressure relief valve; 5—high-speed video camera; 6—data acquisition system; 7—inner cylinder.