Determination of downhole conditions using circulated non-formation gasses

1. A method determining downhole conditions in a subterranean formation during a drilling operation, comprising:

introducing a non-formation gas into a downhole flow of a drilling fluid as the drilling fluid is pumped by a first pump located at a surface into a drill string disposed in a borehole, wherein the non-formation gas is introduced between the first pump and the borehole where the drilling fluid enters the borehole;

pumping, by a second pump located below the surface, the drilling fluid that has exited the drill string into an annulus between the drill string and the borehole to a fluid conduit located at the surface, wherein the fluid conduit is in fluid communication with the annulus at the surface;

receiving, at the fluid conduit, the non-formation gas extracted from the flow of the drilling fluid returned from downhole, wherein the non-formation gas is extracted from the fluid conduit upstream of a mud tank and wherein receiving the non-formation gas comprises:

extracting gasses from a drilling fluid sample; and

determining a percentage of the extracted gas corresponding to the non-formation gas; and

determining a downhole condition with respect to the borehole based, at least in part, on the received non-formation gas and the percentage of the extracted gas corresponding to the non-formation gas, wherein the downhole condition comprises at least a percentage of the drilling fluid that is lost to the subterranean formation.

2. The method of claim 1 , wherein

introducing the non-formation gas into the downhole flow of the drilling fluid comprises introducing the non-formation gas into the flow of the drilling fluid at the fluid conduit in fluid communication with the drill string disposed within the borehole in the drilling operation; and

receiving the non-formation gas from the flow of the drilling fluid returned from downhole comprises receiving a sample of the drilling fluid from a return line in fluid communication with the borehole.

3. The method of claim 2 , wherein the downhole condition comprises at least one of a fluid loss percentage within the subterranean formation, a volume of the borehole, a volume of an annulus between the drill string and the borehole, a volume of a complete circulation through the borehole, a percentage of the borehole that is washed out or caved in, and a pump efficiency.

4. The method of claim 1 , wherein receiving the non-formation gas comprises

plotting the percentage of the extracted gas corresponding to the non-formation gas over time.

5. The method of claim 4 , wherein determining the downhole condition based, at least in part, on the received non-formation gas comprises analyzing the plot.

6. The method of claim 5 , wherein analyzing the plot comprises fitting the plot with at least one of a Gaussian, Lorentzian, polynomial, power law, and logarithmic equation.

7. The method of claim 5 , where analyzing the plot comprises integrating the plot over a first time period in which the non-formation gas is present to determine at least one of a total mass or a total volume of the non-formation gas.

8. The method of claim 7 , wherein

the first time period corresponds to at least one of the time in which the received non-formation gas is detected and a spike in the plot; and

determining the downhole condition based, at least in part, on the received non-formation gas further comprises

determining a first concentration of the non-formation gas introduced into the downhole flow in a volume of the drilling fluid;

determining a second concentration of the received non-formation gas in a volume of the drilling fluid returned from downhole based, at least in part, on the plot integration; and

comparing the first concentration of the introduced non-formation gas to the second concentration of the received non-formation gas.

9. The method of claim 8 , wherein the first time period corresponds to the time in which the received non-formation gas is detected; and comparing the concentration of the introduced non-formation gas to the concentration of the received non-formation gas comprises determining a fluid loss percentage to the formation.

10. The method of claim 9 , wherein the first time period corresponds to the spike in the plot; and comparing the concentration of the introduced non-formation gas to the concentration of the received non-formation gas comprises identifying a wash-out in the borehole.

11. A system for determining downhole conditions in a subterranean formation during a drilling operation, comprising:

a gas injector containing a non-formation gas in fluid communication with a first flow of a drilling fluid, pumped by a first pump located at a surface, entering a borehole in the subterranean formation, wherein the gas injector is between the first pump and the borehole;

a gas analyzer in fluid communication with a fluid conduit located at the surface, wherein a second flow of the drilling fluid is pumped by a second pump located below the surface, wherein the fluid conduit is in fluid communication with an annulus of the borehole at the surface, wherein the second flow of drilling fluid is pumped by the second pump from downhole through the annulus; and

an information handling system communicably coupled to the gas injector and the gas analyzer, the information handling system comprising a processor and a memory device coupled to the processor and containing a set of instructions that, when executed by the processor, cause the processor to

introduce the non-formation gas into the first flow of the drilling fluid at the gas injector, wherein the non-formation gas is introduced where the drilling fluid enters the borehole;

determine a percentage of extracted gas from a drilling fluid sample corresponding to the non-formation gas; and

determine a downhole condition with respect to the borehole based, at least in part, on the non-formation gas extracted from the flow of the drilling fluid returned from downhole and received at the gas analyzer and the percentage of the extracted gas corresponding to the non-formation gas, wherein the non-formation gas is extracted from the fluid conduit upstream of a mud tank, wherein the downhole condition comprises at least a percentage of the drilling fluid that is lost to the subterranean formation.

12. The system of claim 11 , wherein

the gas injector is in fluid communication with the first flow of drilling fluid entering the borehole through the fluid conduit in fluid communication with a drill string within the borehole; and

the gas analyzer is in fluid communication with the second flow of drilling fluid exiting the borehole through a return line in fluid communication with the borehole.

13. The system of claim 12 , wherein the downhole condition comprises at least one of a fluid loss percentage within the subterranean formation, a volume of the borehole, a volume of an annulus between the drill string and the borehole, a volume of a complete circulation through the borehole, a percentage of the borehole that is washed out or caved in, and a pump efficiency.

14. The system of claim 11 , wherein the set of instructions that causes the processor to determine the downhole condition based, at least in part, on the non-formation gas received at the gas analyzer further causes the processor to

plot the percentage of the extracted gas corresponding to the non-formation gas over time.

15. The system of claim 14 , wherein the set of instructions that causes the processor to determine the downhole condition based, at least in part, on the non-formation gas received at the gas analyzer further causes the processor to analyze the plot.

16. The system of claim 15 , wherein the set of instructions that causes the processor to analyze the plot further causes the processor to fit the plot to at least one of a Gaussian, Lorentzian, polynomial, power law, and logarithmic equation.

17. The system of claim 15 , wherein the set of instructions that causes the processor to analyze the plot further causes the processor to integrate the plot over a first time period in which the non-formation gas is present to determine at least one of a total mass or a total volume of the non-formation gas.

18. The system of claim 17 , wherein

the first time period corresponds to at least one of the time in which the non-formation gas returned from downhole and received at the gas analyzer is detected and a spike in the plot; and

wherein the set of instructions that causes the processor to determine the downhole condition based, at least in part, on the received non-formation gas further causes the processor to

determine a first concentration of the introduced non-formation gas in a volume of the drilling fluid;

determine a second concentration of the non-formation gas returned from downhole and received at the gas analyzer in a volume of a drilling fluid sample based, at least in part, on the plot integration; and

compare the first concentration of the introduced non-formation gas to the second concentration of the non-formation gas returned from downhole and received at the gas analyzer.

19. The system of claim 18 , wherein the first time period corresponds to the time in which the non-formation gas returned from downhole and received at the gas analyzer is detected; and wherein the set of instructions that causes the processor to compare the concentration of the introduced non-formation gas to the concentration of the non-formation gas returned from downhole and received at the gas analyzer further causes the processor to determine a fluid loss percentage to the formation.

20. The system of claim 19 , wherein the first time period corresponds to the spike in the plot; and wherein the set of instructions that causes the processor to compare the concentration of the introduced non-formation gas to the concentration of the non-formation gas returned from downhole and received at the gas analyzer further causes the processor to identify a wash-out in the borehole.