Systems and methods for estimating the position of solid fills and optimizing their removal during coiled tubing cleanout operations

1 . A method for wellbore cleanout using coiled tubing, the method comprising:

(a) generating a plurality of depth of solids origin (DSO) guesses, each DSO guess representing a respective estimated initial depth location of an accumulation of solids below a surface at an initial bed position in a wellbore traversing a hydrocarbon-bearing formation, the accumulation of solids comprising an accumulation of material remaining in the wellbore from a previous wellbore operation;

(b) using a plurality of calibrated flow models (FMs) running in parallel to each predict a respective amount of solids at a surface location of the wellbore based at least in part on the DSO guess, each FM model including a different DSO guess among the plurality of DSO guesses;

(c) for each of the plurality of FMs, comparing the predicted amount of the solids at the surface location of the wellbore to a measured amount of solids at the surface location of the wellbore;

(d) selecting an FM among the plurality of FMs outputting a predicted amount of the solids that best matches the measured amount of solids;

(e) determining that the DSO guess of the selected FM is equal to an actual DSO within the wellbore when the predicted amount of the solids at the surface location of the wellbore matches the measured amount of solids at the surface location of the wellbore;

(f) setting operational parameters using the determination from step (e), the operational parameters comprising one or more of coiled tubing movement, pump rates, or fluid selection; and

(g) injecting fluids via a coiled tubing system to flush the accumulation of solids below the surface to the surface location using the operational parameters set in step (e), starting at the estimated initial depth location by injecting fluids into the coiled tubing system such that one or more operational parameters of the coiled tubing system are set based on the actual DSO when the DSO guess of the selected FM is determined to be equal to the actual DSO.

2 . The method of claim 1 , further comprising adjusting the one or more operational parameters of the coiled tubing system to reduce an amount of the solids at the actual DSO within the wellbore.

3 . The method of claim 1 , further comprising adjusting the one or more operational parameters of the coiled tubing system to minimize a volume of pumped fluids required to reduce an amount of the solids at the actual DSO within the wellbore.

4 . The method of claim 1 , further comprising adjusting the one or more operational parameters of the coiled tubing system to minimize a time taken to reduce an amount of the solids at the actual DSO within the wellbore.

5 . The method of claim 1 , further comprising adjusting the one or more operational parameters of the coiled tubing system to:

reduce an amount of the solids at the actual DSO within the wellbore;

minimize a volume of pumped fluids required to reduce an amount of the solids at the actual DSO within the wellbore; and

minimize a time taken to reduce an amount of the solids at the actual DSO within the wellbore.

6 . The method of claim 1 , further comprising iteratively repeating steps (a)-(e) while adjusting the DSO guess until the predicted amount of the solids at the surface location of the wellbore matches the measured amount of solids at the surface location of the wellbore.

7 . The method of claim 6 , further comprising re-calibrating the FM between iterations of repeating steps (a)-(e).

8 . The method of claim 1 , further comprising calibrating each FM prior to step (a) by:

(i) inputting static input data and measured dynamic input data into the FM;

(ii) using the FM to generate dynamic output data based at least in part on the static input data and measured dynamic input data;

(iii) comparing the dynamic output data to measured dynamic output data; and

(iv) determining that the FM is calibrated when the dynamic output data matches the measured dynamic output data.

9 . The method of claim 8 , further comprising iteratively repeating steps (i)-(iv) while adjusting the static input data and measured dynamic input data relating to at least one input until the dynamic output data matches the measured dynamic output data.

10 . The method of claim 1 , wherein:

each FM comprises wellbore flow velocities along the wellbore computed during calibration of the FM prior to step (a); and

the wellbore flow velocities are used to predict the amount of solids at the surface location of the wellbore.

11 . The method of claim 1 , wherein:

the DSO guess is generated based on one or more sensed downhole parameters of the wellbore; and

the one or more sensed downhole parameters of the wellbore comprise one or more of: a weight on bit (WOB), a torque acting on a downhole well tool, a downhole pressure, or a downhole differential pressure.

12 . The method of claim 11 , wherein:

the DSO guess is generated further based on one or more sensed surface parameters at the surface location in combination with the one or more sensed downhole parameters; and

the one or more sensed surface parameters comprise one or more of: a pump-related parameter, a pump rate of a pump unit, a circulating pressure of the pump unit, a parameter related to fluid returns, wellhead pressure, a return fluid flow rate, a choke setting, an amount of proppant returned, data from coiled tubing of the coiled tubing system, a surface weight of the coiled tubing, a speed of the coiled tubing, or a rate of penetration of the coiled tubing.

13 . The method of claim 1 , wherein the generating the DSO guess for each of the plurality of FMs comprises using changes in wellbore fluid apparent density, tubing weight anomalies, or acoustic or pressure wave reflections.

14 . The method of claim 1 , wherein the generating the DSO guess for each of the plurality of FMs comprises iteratively matching simulated solids production obtained using stored flow velocities from FM calibration to measured surface solids production.

15 . A processing and control system for wellbore cleanout using coiled tubing, the system configured to:

(a) generate a plurality of depth of solids origin (DSO) guesses, each DSO guess representing a respective estimated initial depth location of an accumulation of solids below a surface at an initial bed position in a wellbore traversing a hydrocarbon-bearing formation, the accumulation of solids comprising an accumulation of material remaining in the wellbore from a previous wellbore operation;

(b) use a plurality of calibrated flow models (FMs) running in parallel to each predict a respective amount of solids at a surface location of the wellbore based at least in part on the DSO guess, each FM model including a different DSO guess among the plurality of DSO guesses;

(c) for each of the plurality of FMs, compare the predicted amount of the solids at the surface location of the wellbore to a measured amount of solids at the surface location of the wellbore;

(d) select an FM among the plurality of FMs outputting a predicted amount of the solids that best matches the measured amount of solids;

(e) determine that the DSO guess of the selected FM is equal to an actual DSO within the wellbore when the predicted amount of the solids at the surface location of the wellbore matches the measured amount of solids at the surface location of the wellbore;

(f) set operational parameters using the determination from step (e), the operational parameters comprising one or more of coiled tubing movement, pump rates, or fluid selection; and

(g) inject fluids via a coiled tubing system to flush the accumulation of solids below the surface to the surface location using the operational parameters set in step (e), starting at the estimated initial depth location by injecting fluids into the coiled tubing system such that one or more operational parameters of the coiled tubing system are set based on the actual DSO when the DSO guess of the selected FM is determined to be equal to the actual DSO.

16 . The processing and control system of claim 15 , wherein the processing and control system is configured to adjust the one or more operational parameters of the coiled tubing system to reduce an amount of the solids at the actual DSO within the wellbore.

17 . The processing and control system of claim 15 , wherein the processing and control system is configured to adjust the one or more operational parameters of the coiled tubing system to minimize a volume of pumped fluids required to reduce an amount of the solids at the actual DSO within the wellbore.

18 . The processing and control system of claim 15 , wherein the processing and control system is configured to adjust the one or more operational parameters of the coiled tubing system to minimize a time taken to reduce an amount of the solids at the actual DSO within the wellbore.

19 . The processing and control system of claim 15 , wherein the processing and control system is further configured to adjust one or more operational parameters of the coiled tubing system to:

reduce an amount of the solids at the actual DSO within the wellbore;

minimize a volume of pumped fluids required to reduce an amount of the solids at the actual DSO within the wellbore; and

minimize a time taken to reduce an amount of the solids at the actual DSO within the wellbore.

20 . The processing and control system of claim 15 , wherein the processing and control system is further configured to iteratively repeat steps (a)-(e) while adjusting the DSO guess until the predicted amount of the solids at the surface location of the wellbore matches the measured amount of solids at the surface location of the wellbore.

21 . The processing and control system of claim 20 , wherein the processing and control system is further configured to re-calibrate each FM between iterations of repeating steps (a)-(e).

22 . The processing and control system of claim 15 , wherein the processing and control system is further configured to calibrate each FM prior to step (a) by:

(i) inputting static input data and measured dynamic input data into the FM;

(ii) using the FM to generate dynamic output data based at least in part on the static input data and measured dynamic input data;

(iii) comparing the dynamic output data to measured dynamic output data; and

(iv) determining that the FM is calibrated when the dynamic output data matches the measured dynamic output data.

23 . The processing and control system of claim 22 , wherein the processing and control system is further configured to iteratively repeat steps (i)-(iv) while adjusting the static input data and measured dynamic input data relating to at least one input until the dynamic output data matches the measured dynamic output data.

24 . The processing and control system of claim 15 , wherein:

each FM comprises wellbore flow velocities along the wellbore computed during calibration of the FM prior to step (a); and

the wellbore flow velocities are used to predict the amount of solids at the surface location of the wellbore.