Saltwater-based fracturing fluid
a technology of saltwater and fracturing fluid, applied in fluid removal, chemistry apparatus and processes, borehole/well accessories, etc., can solve the problems of less efficient removal, poor circulation, and increased rig time cos
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example 1
[0086]Both rheology and coreflooding experiments were conducted to evaluate a developed fracturing fluid system. Seawater (Gulf seawater) with a composition as shown in Table 1 was used to prepare the fracturing fluid as a base. GLDA chelating agent with a pH of 12 was used at two different concentrations; 5 wt % for the unconventional reservoir fracturing and 10 wt % for the conventional reservoir fracturing. The polymer concentration in both cases was 0.45 wt %, relative to the total weight of the fluid. HPHT viscometer was used to measure the viscosity and coreflooding was used to assess the effect on permeability and fluid loss. FIG. 1 shows the flooding set-up used to evaluate the developed systems on actual outcrop core samples for unconventional and conventional reservoirs; one with high permeability and the other one with low permeability. Table 2 shows the different polymers tested with the GLDA in this work along with their stable range of temperature. In addition, Table 3...
example 2
[0087]FIG. 2 and FIG. 3 show viscosity measurements of a fracturing fluid composition that includes 10 wt % GLDA and 45 pptg co-polymer diluted in seawater at 300° F. and 300 psi. The viscosity increased to an average value of 350 lb / 100 ft2 and remained stable for more than 4 hours and then declined to 0.5. As a result, this fluid composition can be used for high permeability or conventional reservoirs. The pH of the fluid was about 12.
[0088]FIG. 4 and FIG. 5 show viscosity measurements of a second fracturing fluid composition that includes 5 wt % GLDA and 45 pptg co-polymer diluted in seawater at 300° F. and 300 psi. The viscosity increased to an average value of 135 lb / 100 ft2 and remained stable for more than 6 hours and then declined to 0.5. As a result, this fluid composition can be used for low permeability or unconventional reservoirs. The pH of the fluid was around 12.
[0089]FIG. 6 shows the two coreflooding samples (Berea and Scioto sandstone cores) used in this study and t...
example 3
[0090]FIG. 7 and FIG. 8 show the coreflooding behavior of the two experiments for the conventional and the unconventional coreflooding samples. FIG. 7 shows that the pressure elevated soon after GLDA / polymer solution was injected, and the outlet flow rate remained zero for more than two hours. After reaching a peak value, the pressure went down due to a breakage of the solution. The core permeability was observed to be 150 md before and after the experiment. As a result, the coreflooding did not damage to the formation, due to a zero fluid loss behavior of the treating fluid.
[0091]Similarly, FIG. 8 shows that the pressure went up after GLDA / polymer solution was injected, and the outlet flow rate remained zero for more than four hours. After reaching a peak value, the pressure went down due to a breakage of the solution. The core permeability was observed to be 3.2 md before and after the experiment, which implies no damage to the formation, due to a zero fluid loss behavior of the t...
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