Enhancing acid fracture conductivity

1. A method of acid fracture treatment, comprising:

initiating fracturing of a subterranean formation in which a wellbore is formed to create

a formation fracture by flowing a fracturing pad fluid into the wellbore to break down the formation to thereby create the formation fracture;

after initiating the fracturing for a period of time, injecting an acidic fluid into the wellbore

to etch walls of the formation fracture to thereby create fracture conductivity;

introducing a gas into the wellbore to foam fluids in the wellbore;

increasing a foam quality of the fluids with time during the treatment, wherein the foam quality is based on a volume of the introduced gas and a volume of the fluids in the wellbore; and

alternately performing steps of injecting the fracturing pad fluid and the acidic fluid, while keeping introducing the gas during the steps.

2. The method of claim 1 , further comprising:

monitoring reaction of the fracture to the acidic fluid during the treatment; and

controlling the increasing of the foam quality based on the monitored reaction by adjusting at least one of an injection rate of the acidic fluid, an injection volume of the acidic fluid, an introduction rate of the gas, or an introduction volume of the gas.

3. The method of claim 2 , wherein monitoring reaction of the fracture comprises:

monitoring at least one of parameters including a treating pressure, a wellhead pressure, a bottomhole pressure, a fluid pumping rate, a gas pumping rate, and a slurry rate; and

determining the reaction of the fracture based on the monitored parameters.

4. The method of claim 1 , further comprising:

calculating the foam quality based on the volume of the introduced gas and the volume of the fluids in the wellbore; and

correcting the calculated foam quality with at least one of a calculated wellhead foam

quality, a predicted bottomhole foam quality, or a calculated actual bottomhole foam quality.

5. The method of claim 4 , further comprising:

calculating the calculated wellhead foam quality based on an actual wellhead pressure and a temperature;

predicting the predicted bottomhole foam quality based on a predicted bottomhole internal phase; and

calculating the calculated actual bottomhole foam quality based on a calculated bottomhole internal phase that is calculated based on a bottomhole pressure and the temperature.

6. The method of claim 1 , further comprising:

determining that a dimension of the created formation fracture reaches a value, and in response, injecting the acidic fluid into the wellbore.

7. The method of claim 1 , wherein introducing the gas comprises:

introducing the gas after the creation of the formation fracture and until completion of the treatment.

8. The method of claim 1 , further comprising:

decreasing an injection rate of the acidic fluid with time during the treatment.

9. The method of claim 1 , wherein injecting the acidic fluid comprises:

injecting the acidic fluid at a pressure lower than a fracture closure pressure that is capable of causing a closure of the formation fracture.

10. The method of claim 9 , wherein injecting the acidic fluid comprises:

keeping an injection rate of the acidic fluid constant with time during the treatment.

11. The method of claim 9 , wherein injecting the acidic fluid comprises:

increasing an injection rate of the acidic fluid with time during the treatment.

12. The method of claim 1 , wherein a volume of the introduced gas for a current step is no smaller than a volume of the introduced gas for a previous step.

13. The method of claim 1 , wherein a volume of the introduced gas for a current step is smaller than a volume of the introduced gas for a previous step.

14. The method of claim 1 , wherein an injection rate of the introduced gas for a current step is no smaller than an injection rate of the introduced gas for a previous step.

15. The method of claim 1 , wherein the fracturing pad fluid comprises at least one of a gelled water or a crosslinked gel fluid.

16. The method of claim 1 , wherein introducing a gas into the wellbore comprises:

generating the gas in-situ in the fluids in the wellbore.

17. The method of claim 1 , wherein the acidic fluid is configured to dissolve the formation and comprises at least one of:

hydrochloric (HCl) acid with a concentration from 0.1 to 32 wt. %,

formic acid with a concentration from 0.1 to 12 wt. %,

acetic acid with a concentration from 0.1 to 20 wt. %,

methaneseleninic (MSA) acid with a concentration from 0.1 to 92 wt. %,

chelating agent with a concentration from 0.1 to 40 wt. %, or

a carboxylic acid system.

18. The method of claim 1 , wherein the acidic fluid is configured to be

gelled by linearly polymers,

gelled by crosslinked polymer system,

gelled by viscoelastic surfactant (VES) system,

emulsified by diesel or oil, or

foamed by a particular gas.

19. The method of claim 1 , wherein the introduced gas has low density and low viscosity and comprises at least one of:

nitrogen (N2),

carbon dioxide (CO2),

air,

methane, or

natural gas.

20. The method of claim 1 , further comprising:

adding a diversion fluid to the acidic fluid, wherein the diversion fluid comprises at least one of a crosslinking polymer, a surfactant based material, or a crosslinked non-reactive fluid.

21. The method of claim 1 , further comprising:

cleaning the wellbore after closure of the formation fracture.