Detecting a Drill String Washout Event

Abstract

A method for detecting a drill string washout event. The method includes locating a drill string in a wellbore formed in a subterranean formation. A drilling fluid is pumped into the drill string. The drill string includes a turbine that spins in response to the drilling fluid flowing therethrough. A comparison is made between a rate that the drilling fluid is pumped into the drill string and a spin rate of the turbine. A defect is determined to be formed in the drill string based upon the comparison.

Description

BACKGROUND

Embodiments described herein generally relate to systems and methods for detecting a drill string washout. More particularly, embodiments described herein relate to systems and methods for detecting the existence and location of a defect (e.g., an undesirable crack or opening) in a drill string that may cause a drill string washout.

Drill string washout is commonly encountered in subterranean drilling operations. Drill string washout is caused by a defect formed in the drill string that allows pressurized drilling fluid to leak or flow from the interior of the drill string to the outer annulus. The defect may be caused by mechanical fatigue, corrosion, abrasive wear, the use of corrosive drilling fluid, and/or high temperature and pressure drilling operations.

If left undetected, what begins as a small leak may increase in size, diverting drilling fluid from downhole motors, turbines, underreamers, drill bits, and the like. In addition, this may lead to the failure of the drill string (commonly referred to as a “twistoff”). Such twistoff failures often result in lost rig time and may even result in a lost bottom hole assembly.

SUMMARY

This summary is provided to introduce a selection of concepts that are further described below in the detailed description. This summary is not intended to identify key or essential features of the claimed subject matter, nor is it intended to be used as an aid in limiting the scope of the claimed subject matter.

A method for detecting a drill string washout event is disclosed. The method includes locating a drill string in a wellbore formed in a subterranean formation. A drilling fluid is pumped into the drill string. The drill string includes a turbine that spins in response to the drilling fluid flowing therethrough. A comparison is made between a rate that the drilling fluid is pumped into the drill string and a spin rate of the turbine. A defect is determined to be formed in the drill string based upon the comparison.

In another embodiment, the method includes locating a drill string in a wellbore formed in a subterranean formation. An annulus is formed between the drill string and a wall of the wellbore. A drilling fluid is pumped into the drill string from a surface location. The drilling fluid flows through a drill bit positioned at an end portion of the drill string and back to the surface location via the annulus. A flow rate into the drill string is measured with a first flow rate sensor disposed at the surface location. A downhole flow rate is measured with a second flow rate sensor disposed within the wellbore. A flow rate out of the annulus is measured with a third flow rate sensor disposed at the surface location. A multi-dimensional relationship is established based upon the flow rate into the drill string, the downhole flow rate, and the flow rate out of the annulus.

A computer program embodied on a non-transitory computer readable medium is also disclosed. When executed by a processor, the computer program controls a method for detecting a drill string washout event. The method includes establishing a multi-dimensional relationship based upon a flow rate into a drill string, a downhole flow rate, and a flow rate out of an annulus. The drill string is disposed in the wellbore, and the annulus is formed between the drill string and a wall of the wellbore. A determination that a defect is formed in the drill string is made using at least one of the flow rates, a pressure differential, and a depth of a drill bit coupled to an end portion of the drill string. The pressure differential is the difference in pressure measured by two sensors. The two sensors may be selected from the group consisting of a sensor disposed at the surface location and adapted to measure a pressure of the drilling fluid being pumped into the drill string, a sensor disposed within the drill string and adapted to measure a pressure of the drilling fluid within the drill string, a sensor disposed within the annulus and adapted to measure a pressure of the drilling fluid within the annulus, and a sensor disposed at the surface location and adapted to measure a pressure of the drilling fluid flowing out of the annulus.

BRIEF DESCRIPTION OF THE DRAWINGS

Embodiments of “Detecting a Drill string Washout Event” are described with reference to the following figures. The same numbers are used throughout the figures to reference like features and components.

FIG. 1 depicts an illustrative drill string disposed within a wellbore, according to one or more embodiments disclosed.

FIG. 2 depicts an illustrative flow chart for determining the existence of a defect in the drill string, according to one or more embodiments disclosed.

FIG. 3 depicts an illustrative graph used to determine the existence of a defect in the drill string, according to one or more embodiments disclosed.

FIG. 4 depicts another illustrative graph used to determine the existence of a defect in the drill string, according to one or more embodiments disclosed.

FIG. 5 depicts another illustrative graph used to determine the existence of a defect in the drill string, according to one or more embodiments disclosed.

FIG. 6 depicts an illustrative graph showing the surface flow rate “in”, the downhole flow rate, and the surface flow rate “out” when the flow rates are substantially equal, according to one or more embodiments disclosed.

FIG. 7 depicts an illustrative graph showing the pressure of the drilling fluid as it flows down through the drill string, through the drill bit, and back up through the annulus when the flow rates are substantially equal, according to one or more embodiments disclosed.

FIG. 8 depicts an illustrative graph showing the downhole flow rate being less than the surface flow rate “in” and the surface flow rate “out”, according to one or more embodiments disclosed.

FIG. 9 depicts an illustrative graph showing the pressure of the drilling fluid as it flows down through the drill string, through the drill bit, and back up through the annulus when the downhole flow rate is less than the surface flow rate “in” and the surface flow rate “out”, according to one or more embodiments disclosed.

FIG. 10 depicts an illustrative graph showing the downhole flow rate being greater the surface flow rate “in” and the surface flow rate “out”, according to one or more embodiments disclosed.

FIG. 11 depicts an illustrative graph showing the surface flow rate “in” being less than the downhole flow rate and the surface flow rate “out”, according to one or more embodiments disclosed.

FIG. 12 depicts an illustrative graph showing the surface flow rate “in” being greater than the downhole flow rate and the surface flow rate “out”, according to one or more embodiments disclosed.

FIG. 13 depicts an illustrative graph showing the surface flow rate “out” being less than the surface flow rate “in” and the downhole flow rate, according to one or more embodiments disclosed.

FIG. 14 depicts an illustrative graph showing the pressure of the drilling fluid as it flows down through the drill string, through the drill bit, and back up through the annulus when the surface flow rate “out” is less than the surface flow rate “in” and the downhole flow rate, according to one or more embodiments disclosed.

FIG. 15 depicts an illustrative graph showing the surface flow rate “out” being greater than the surface flow rate “in” and the downhole flow rate, according to one or more embodiments disclosed.

FIG. 16 depicts an illustrative graph showing the pressure of the drilling fluid as it flows down through the drill string, through the drill bit, and back up through the annulus when the surface flow rate “out” is greater than the surface flow rate “in” and the downhole flow rate, according to one or more embodiments disclosed.

FIG. 17 depicts the drill string having a plurality of distributed internal pressure while drilling sensors and a plurality of distributed annular pressure while drilling sensors, according to one or more embodiments disclosed.

FIG. 18 depicts an illustrative graph showing the pressure of the drilling fluid as it flows down through the drill string, through the drill bit, and back up through the annulus when there is a defect in the drill string, as may be caused by a drill string washout, according to one or more embodiments disclosed.

FIG. 19 depicts an illustrative graph showing the pressure of the drilling fluid as it flows down through the drill string, through the drill bit, and back up through the annulus when a portion of the drilling fluid is being lost into the formation, according to one or more embodiments disclosed.

FIG. 20 depicts an illustrative graph showing the pressure of the drilling fluid as it flows down through the drill string, through the drill bit, and back up through the annulus when fluid (e.g., hydrocarbon fluid such as oil or gas) is flowing out of the formation and to the surface with the drilling fluid, according to one or more embodiments disclosed.

FIG. 21 depicts a schematic view of an illustrative computer system, according to one or more embodiments disclosed.

DETAILED DESCRIPTION

A method for detecting a drill string washout event is disclosed. The method includes locating a drill string 30 in a wellbore 40 formed in a subterranean formation 38. A drilling fluid is pumped into the drill string 30. The drill string 30 includes a turbine 50 that spins in response to the drilling fluid flowing therethrough. A comparison is made between a rate that the drilling fluid is pumped into the drill string 30 and a spin rate of the turbine 50. A defect 39 is determined to be formed in the drill string 30 based upon the comparison.

FIG. 1 depicts an illustrative drill string 30 disposed within a wellbore 40, according to one or more embodiments disclosed. A drilling rig 10 may be positioned over a subsea oil or gas formation 38. A conduit 18 may extend from the drilling rig 10 to a wellhead 22 disposed on the sea floor 16. The drilling rig 10 may include a derrick 12 and a hoisting apparatus for raising and lowering the drill string 30 within the conduit 18 and within a wellbore 40 formed in the formation 38.

The drill string 30 may include a bottom hole assembly 31 disposed at a lower end portion thereof. The bottom hole assembly 31 may include a drill bit 32 for drilling the wellbore 40 in the formation 38. The bottom hole assembly 31 may also include a turbine 50. More particularly, the turbine 50 may be disposed within a measurement while drilling (“MWD”) tool, a logging while drilling (“LWD”) tool, a rotary steerable tool, or the like. The turbine 50 may rotate or spin in response to the drilling fluid flowing through the drill string 30.

A pump 43 may cause pressurized drilling fluid to flow downhole through the drill string 30 to the drill bit 32. The drilling fluid may flow through the drill bit 32 and circulate back to the surface via an annulus 37 formed between the drill string 30 and the wall of the wellbore 40 or between the drill string 30 and the conduit 18. The drilling fluid may suppress formation pressure, lubricate the drill string 30, flush cuttings away from the drill bit 32, cool the bottom hole assembly 31, drive the turbine 50, and/or power a downhole cavity motor (not shown). The drilling fluid may further serve as a communications channel for transmitting pressure pulses to the surface, for example, via mud pulse telemetry techniques.

The drill string 30 may have one or more defects (one is shown 39) disposed thereon or formed therein. The defect 39 may be or include an undesirable crack or opening that provides a (radial) path of fluid communication from the interior of the drill string 30 into the annulus 37. Flow of the drilling fluid through the defect 39 diverts the drilling fluid into the annulus 37, thereby reducing the flow rate of drilling fluid to downhole tools such as the turbine 50, the drill bit 32, a mud motor (not shown), and the like. This results in decreased power generated by the turbine 50 and mud motor and less efficient removal of cuttings at the drill bit 32.

One or more sensors may be used to determine the existence of the defect 39, the flow rate through the defect 39, and/or the depth or location of the defect 39. The sensors may be flow rate sensors, pressure sensors, or the like. More particularly, a first surface flow rate sensor 60 may be disposed at a surface location surface (e.g., on the drilling rig 10) or within the wellhead 22. The first surface flow rate sensor 60 may be adapted to measure the flow rate of drilling fluid being pumped into the drill string 30 by the pump 43. This sensor 60 may also be referred to as the surface flow rate “in” sensor, and the flow rate of the drilling fluid being introduced to the drill string 30 may be referred to as the flow rate “in”.

A downhole flow rate sensor 62 may be disposed within and/or coupled to the bottom hole assembly 31. The downhole flow rate sensor 62 may be adapted to measure the flow rate of the fluid flowing through the drill string 30 proximate the bottom hole assembly 31 and/or the flow rate of fluid flowing through the annulus 37 proximate the bottom hole assembly 31.

A second surface flow rate sensor 64 may be disposed at the surface location (e.g., on the drilling rig 10) or within the wellhead 22. The second surface flow rate sensor 64 may be adapted to measure the flow rate of the fluid flowing up and out of the annulus 37. This sensor 64 may also be referred to as the surface flow rate “out” sensor, and the flow rate of the fluid flowing up and out of the annulus 37 may be referred to as the flow rate “out”.

A first surface pressure sensor 66 may be disposed at the surface location (e.g., on the drilling rig 10) or within the wellhead 22. The first surface pressure sensor 66 may be adapted to measure the pressure of the drilling fluid being pumped into the drill string 30 by the pump 43. For example, the first surface pressure sensor 66 may be adapted to measure the stand pipe pressure. This sensor 66 may also be referred to as the surface stand pipe pressure sensor.

A first downhole pressure sensor 68 may be disposed within the bottom hole assembly 31. The first downhole pressure 68 may be adapted to measure the pressure of the drilling fluid flowing through the drill string 30 proximate the bottom hole assembly 31. This sensor 68 may also be referred to as the downhole internal pressure while drilling sensor.

A second downhole pressure sensor 70 may be coupled to the exterior of the bottom hole assembly 31. The second downhole pressure 70 may be adapted to measure the pressure of the fluid flowing through the annulus 37 proximate the bottom hole assembly 31. This sensor 70 may also be referred to as the downhole annular pressure while drilling sensor.

A second surface pressure sensor 72 may be disposed at the surface location (e.g., on the drilling rig 10) or within the wellhead 22. The second surface pressure sensor 72 may be adapted to measure the pressure of the fluid flowing up and out of the annulus 37. This sensor 72 may also be referred to as the surface mud line return pressure sensor.

FIG. 2 depicts an illustrative flow chart 200 for determining the existence of the defect 39 in the drill string 30, according to one or more embodiments. Drilling fluid may be pumped through the drill string 30 using the pump 43, as shown at 202. The rate that the turbine 50 spins may be measured and monitored, as shown at 204. The spin rate may be obtained, for example, from a measured turbine voltage. In at least one embodiment, the pressure of the drilling fluid in the drill string 30 may be measured using the internal pressure while drilling sensor 68. The spin rate of the turbine 50 and/or the pressure of the drilling fluid in the drill string 30 may be transmitted to the computer system 2100 (FIG. 21) using wired drill pipe or mud pulse telemetry, as shown at 206.

The flow rate “in” may be measured using the surface flow rate “in” sensor 60, as shown at 208. In at least one embodiment, the pressure of the drilling fluid being pumped into the drill string 30 by the pump 43 may be measured using the surface stand pipe pressure sensor 66. A comparison (e.g., a ratio) of the spin rate of the turbine 50 and the flow rate “in” may be determined (e.g., using the computer system 2100), as shown at 210. The comparison may then be evaluated as an indicator of a possible defect 39 formed in the drill string 30 that may lead to a drill string washout, as shown at 212. For example, the computer system 2100 may determine that the defect 39 exists when the ratio decreases below a predetermined amount or threshold.

If the defect 39 is detected, the computer system 2100 may process the spin rate of the turbine 50, the pressure of the drilling fluid in the drill string 30, the flow rate “in”, and/or the pressure of the drilling fluid being pumped into the drill string 30 to determine the flow rate of the drilling fluid through the defect 39 and/or the depth (or axial location) of the defect 39, as shown at 214.

The turbine 50 may be any downhole turbine and/or alternator. The drilling fluid (e.g., drilling mud) may cause a rotor of the turbine 50 to spin. The spin rate of the rotor may be directly proportional to the flow rate through the turbine 50. As such, if a portion of the drilling fluid is diverted to the annulus 37 through the defect 39 causing the flow rate through the turbine 50 to decrease, the spin rate of the rotor may decrease proportionately. The voltage generated by the turbine 50 may be proportional to the spin rate of the rotor. The voltage of the turbine 50, therefore, may provide an accurate indication of the flow rate through the turbine 50.

It has been observed that during a normal drilling operation, a ratio of the spin rate of the turbine 50 to the flow rate “in” is substantially constant and stable during drilling. This may be expressed mathematically, for example, as follows:

$\begin{array}{cc}\frac{R}{Q}\approx k& \mathrm{Equation}1\end{array}$

where R represents the spin rate of the turbine 50, Q represents the flow rate “in”, and k represents the constant. The spin rate to flow rate “in” ratio is monitored while drilling (at 210 and 212). During normal drilling conditions, the ratio is substantially constant with small perturbations, for example, owing to various noise sources. The value of the constant k may be used as a reference in evaluating a drill string washout.

As described above, a drill string washout occurs when the defect 39 develops in the drill string 30 or bottom hole assembly 31. The defect 39 allows drilling fluid to escape into the wellbore annulus 37, thereby bypassing the turbine 50 (as well as other downhole tools). Bypassing the turbine 50 results in a reduced spin rate of the turbine 50 and, therefore, a correspondingly reduced ratio as computed in Equation 1.

FIG. 3 depicts an illustrative graph 300 used to determine the existence of the defect 39 in the drill string 30, according to one or more embodiments. The X-axis of the graph 300 is time, and the Y-axis of the graph 300 is the ratio of the spin rate of the turbine 50 to the flow rate “in” (as determined by Equation 1).

As indicated at 322, the ratio is approximately constant with minor perturbations during normal drilling conditions. It may be appreciated that substantially any suitable statistical averaging techniques or data smoothing algorithms may be utilized to reduce the data noise, for example, including the techniques disclosed in the commonly assigned, co-pending U.S. Patent Publication 2011/0220410. Beginning at 324 and continuing at 326, the ratio is shown to decrease with time, possibly due to a drill string washout event. Various procedures may be utilized to further identify drill string washout conditions. For example, statistical methods may be employed to calculate a probability that the ratio has been ramping downward (decreasing) for a time period longer than some predetermined value 328. An alarm may sound when the downturn exceeds the time threshold (e.g., 1 minute) and/or a probability threshold (e.g., 99 percent). Substantially any suitable statistical methods may be utilized, for example, including a Bayesian estimation algorithm. Bayesian statistics make use of standard procedures and equations known to those of skill in the mathematical arts. While such statistical methods may be utilized herein, the disclosed embodiments are not so limited.

FIG. 4 depicts another illustrative graph 400 used to determine the existence of a defect 39 in the drill string 30, according to one or more embodiments. Similar to the graph 300, the X-axis of the graph 400 is time, and the Y-axis of the graph 400 is the ratio of the spin rate of the turbine 50 to the flow rate “in” (as determined by Equation 1).

The ratio is approximately constant during normal drilling conditions, as shown at 422. The ratio is shown to decrease beginning at 424 and continuing at 426. Similar statistical methods may be employed to calculate a probability that the ratio has fallen below the reference value by more than a predetermined threshold 432. Again, an alarm may sound when the downturn exceeds the ratio and/or probability thresholds.

It will be understood that the ratio of the spin rate of the turbine 50 to flow rate “in” may not be smooth, especially over a wide range of flow rate values. In some such cases, the ratio may be expressed as a function of flow rate, for example, as follows:

$\begin{array}{cc}\frac{R}{Q}=k-\frac{d}{Q^2}& \mathrm{Equation}2\end{array}$

where R, Q, and k are as defined above with respect to Equation 1 and d represents a fitting factor.

FIG. 5 depicts another illustrative graph 500 used to determine the existence of the defect 39 in the drill string 30, according to one or more embodiments. The X-axis of the graph 500 is the flow rate “in”, and the Y-axis of the graph 500 is the ratio of the spin rate of the turbine 50 to the flow rate “in” (as determined by Equation 1).

Data may be collected and plotted as indicated at 542. The data may then be fit with Equation 2 and used to compute values for k and d and obtain a reference curve as indicated at 544. A washout event results in a reduction in the ratio computed in Equation 1, causing the plotted value to fall below the reference curve 544 as indicated at 546. Similar statistical methods may be employed to calculate a probability that the ratio has fallen below the reference curve 544 by more than a predetermined threshold 548. Again, an alarm may sound when the downturn exceeds the ratio and/or probability thresholds.

In further disclosed embodiments, measurements of the spin rate of the turbine 50 and the flow rate “in” may be combined with downhole pressure measurements (e.g., from the downhole internal pressure while drilling sensor 68) and standpipe pressure measurements (e.g., from surface standpipe pressure sensor 66) to estimate at least one of a leak rate and a measured depth of the defect 39. Determining a leak rate may enable the severity of the washout event to be estimated. Obtaining a measured depth of the defect 39 may enable rig operators to quickly locate the damaged pipe section (or sections) when tripping out of the wellbore 40, thereby potentially saving considerable rig time.

As described above with respect to Equation 1, a ratio of the spin rate of the turbine 50 to the flow rate “in” is approximately constant. This ratio may be expressed more generally as a linear relationship, for example, as follows:

R=aQ+b  Equation 3

where R and Q are as defined above with respect to Equation 1 and a and b are fitting factors (a representing the slope of the linear relationship and b representing the Y-axis intercept when the flow-in equals zero). It will be understood that the fitting factor b may be zero as the turbine 50 does not spin at zero flow (i.e., when the flow-in equals zero). The fitting factor b may also have a small negative value as there may be some minimal flow to spin the turbine 50. Notwithstanding the above, values for a and b may be obtained via fitting the spin rate of the turbine 50 and the flow-in at two or more values along the X-axis.

In a drill string washout event, Equation 3 may be modified as follows:

R=a(Q−q)+b  Equation 4

where q represents the leak rate of drilling fluid through the defect 39 in the drill string 30 such that (Q−q) represents the drilling fluid flow rate at the turbine 50 (i.e., below the leak). Since a, b, Q and R are known quantities, Equation 4 may be rearranged to solve for the leak rate q as follows:

$\begin{array}{cc}q=Q-\frac{R-b}{a}& \mathrm{Equation}5\end{array}$

A standpipe pressure measurement (e.g., from the surface standpipe pressure sensor 66) may be related to a downhole internal pressure measurement (e.g., from the internal pressure while drilling sensor 68) as follows:

$\begin{array}{cc}{P}_{\mathrm{sp}}=P_{in}-\rho \mathrm{gh}+\frac{2\mathrm{fL}\rho Q^2}{{\pi }^2D^5}& \mathrm{Equation}6\end{array}$

where P_sp represents the standpipe pressure measurement, P_in represents the downhole internal pressure measurement, ρ represents the average density of the drilling fluid, g represents the rate of acceleration due to gravity, h represents the total vertical depth of the internal pressure while drilling sensor 68, f represents the Fanning friction factor, L represents the measured depth of the internal pressure while drilling sensor 68, Q represents flow rate “in”, and D represents a nominal internal diameter of the drill string 30. Those of ordinary skill may appreciate that P_sp=P_in−ρgh represents the relationship between the standpipe pressure and the internal drilling fluid pressure in static (no circulation) conditions. The term 2fLρQ²/π²D⁵ is one example of an expression that takes into account frictional effects during circulation.

Equation 6 may be simplified as follows:

P_sp=P_in−ρgh+cLQ²  Equation 7

where c may be assumed to be a constant and is given as follows:

$\begin{array}{cc}c=\frac{2f\rho }{{\pi }^2D^5}& \mathrm{Equation}8\end{array}$

As stated above, the constant c is one example of an expression that takes into account frictional effects during circulation. It will be understood that the disclosure is not limited to this particular mathematical expression. In another embodiment, the constant c may be obtained via rig site calibration, for example, similar to the calibration methodology disclosed in commonly assigned U.S. Pat. No. 6,427,125 for calibrating hydraulic equivalent density.

When there is a drill string washout event above the internal pressure while drilling sensor 68, Equation 7 may be modified as follows:

P_sp=P_in−ρgh+clQ²+c(L−1)(Q−q)²  Equation 9

where the term clQ² accounts for frictional effects during circulation of the drilling fluid down to the depth of the defect 39 in the drill string 30 (i.e., to a depth l) and the term c(L−l)(Q−q)² accounts for the frictional effects during circulation of the drilling fluid between the defect 39 and the internal pressure while drilling sensor 35 (i.e., between depths l and L). Note that the flow rate between the defect 39 and the internal pressure while drilling sensor 68 is reduced by the leak rate q and is therefore represented as (Q−q). Equation 9 may be rearranged to provide an analytical expression for the depth l of the defect 39, for example, as follows:

$\begin{array}{cc}l=\frac{P_{\mathrm{sp}}-P_{in}+\rho \mathrm{gh}-{\mathrm{cL}\left(Q-q\right)}^2}{\mathrm{cq}\left(2Q-q\right)}& \mathrm{Equation}10\end{array}$

It will be understood that each of the parameters in Equations 5 and 10 are known (or can be readily obtained). Therefore, the leak rate q and the depth l of the defect 39 in the drill string 30 may be readily computed from the measured spin rate of the turbine 50 and the measured flow rate “in”.

In at least one embodiment, downhole fluid flow rates may be obtained using water flow logs based on oxygen activation techniques or from frictional pressure losses along the length of the drill string 30. For example, frictional pressure losses along the length of the drill string 30 may be compared to the flow rate “in”. Deviations from established normal trends may then be used to evaluate and identify potential drill string washout events. Pressure measurements made by internal pressure while drilling sensors 68 distributed along the drill string 30 may be compared with a discontinuity in the corresponding pressure gradient used to identify and locate potential drill string washout events. These same methodologies may also be adapted to confirm the absence of a drill string washout event, and indicate instead the failure of one or more of the concerned sensors, or defective pumps or other hydraulic leaks at the surface, which otherwise may be mistaken as an indicator of drill string washout.

FIGS. 6-16 depict an illustrative process for identifying a drill string washout, a formation loss, and/or a formation kick. Referring to FIGS. 1 and 6-16, drilling fluid may be pumped down through the drill string 30, through the drill bit 32, and back up through the annulus 37 to the surface. The flow rate “in” may be measured using the surface flow rate “in” sensor 60. In another embodiment, the pressure drop inside the drill string 30 may be measured. For example, the pressure drop may be the difference between the pressure measured by the surface stand pipe pressure sensor 66 and the internal pressure while drilling sensor 68. The pressure drop may be a proxy for the average flow rate inside the drill string 30 along the length of the drill string 30.

The flow rate “out” may be measured using the surface flow rate “out” sensor 64. In another embodiment, the pressure drop outside the drill string 30 may be measured. For example, the pressure drop may be the difference between the pressure measured by the downhole annular pressure while drilling sensor 70 and the surface mud line return pressure sensor 72. The pressure drop may be a proxy for the average flow rate outside the drill string 30 along the length of the drill string 30.

The downhole flow rate may also be measured by the downhole flow rate sensor 62. In another embodiment, the pressure drop between the internal pressure while drilling sensor 68 and the annular pressure while drilling sensor 70 may be measured. The pressure drop may be a proxy for the downhole flow rate of the drilling fluid.

The flow rate sensors 60, 62, 64 may be Venturi type flow sensors. In other embodiments, the flow rates may be measured by or inferred from turbine measurements, water flow log measurements, mud tank volume measurements, distributed pressure measurements, and/or gradiomanometer measurements. The term “flow rate” may include volumetric flow rate and/or mass flow rate. The term “pressure drop” may refer to a difference in hydrostatic pressure.

FIG. 6 depicts an illustrative graph 600 showing the surface flow rate “in” 61, the downhole flow rate 63, and the surface flow rate “out” 65 when the flow rates 61, 63, 65 are substantially equal, according to one or more embodiments. The flow rate “in” 61, the downhole flow rate 63, and the flow rate “out” 65 may be substantially equal during normal drilling conditions. A first multi-dimensional relationship may be determined based upon the flow rates 61, 63, 65. The first relationship may be determined using a parametric theoretical model, statistical analysis techniques (e.g., principal component analysis), a factor analysis, and/or neural network empirical correlations. An alarm may be triggered if one or more of the flow rates 61, 63, 65 deviate from the first relationship by a predetermined amount or threshold.

FIG. 7 depicts an illustrative graph 700 showing the pressure of the drilling fluid as it flows down through the drill string 30, through the drill bit 32, and back up through the annulus 37 when the flow rates 61, 63, 65 are substantially equal, according to one or more embodiments. The X-axis represents pressure, and the Y-axis represents depth in the wellbore 40. The line 602 represents the drilling fluid within the drill string 30, and line 604 represents the drilling fluid in the annulus 37. As the drilling fluid is introduced to the drill string 30, the surface flow rate “in” sensor 60 may measure the flow rate “in” 61, and the surface standpipe pressure sensor 66 may measure the stand pipe pressure 67.

The pressure of the drilling fluid may increase as the drilling fluid flows through the drill string 30 to greater depths, as shown by line 602. The downhole flow rate sensor 62 may measure the flow rate 63 of the drilling fluid proximate the bottom hole assembly 31. More particularly, the downhole flow rate sensor 62 may measure the flow rate 63 of the drilling fluid inside the drill string 30 and/or outside the drill string 30 (i.e., in the annulus 37). The internal pressure while drilling sensor 68 may measure the pressure 69 of the drilling fluid within the drill string 30 and proximate the bottom hole assembly 31. The annular pressure while drilling sensor 70 may measure the pressure 71 of the drilling fluid outside the drill string 30 (e.g., in the annulus 37) and proximate the bottom hole assembly 31. As shown, there may be a slight drop in pressure as the drilling fluid flows through the drill bit 32 and into the annulus 37.

The pressure of the drilling fluid may decrease as the drilling fluid flows through the annulus 37 toward the surface, as shown by line 604. The surface flow rate “out” sensor 64 may measure the flow rate “out” 65, and the surface mud line return pressure sensor 72 may measure the pressure 73 of the drilling fluid flowing out of the annulus 37.

FIG. 8 depicts an illustrative graph 800 showing the downhole flow rate 63 being less than the surface flow rate “in” 61 and the surface flow rate “out” 65, according to one or more embodiments. When the downhole flow rate 63 is less than the flow in rate 61 and/or the flow rate “out” 65 by a predetermined amount (or threshold), the alarm may trigger. The alarm may indicate a defect 39 in the drill string 30, as may be caused by a drill string washout. In another embodiment, the alarm may indicate a failure in the downhole flow rate sensor 62.

FIG. 9 depicts an illustrative graph 900 showing the pressure of the drilling fluid as it flows down through the drill string 30, through the drill bit 32, and back up through the annulus 37 when the downhole flow rate 63 is less than the flow rate “in” 61 and the flow rate “out” 65, according to one or more embodiments. Referring to FIGS. 8 and 9, the flow rate or leak rate through the defect 39 may be determined using the first relationship, the downhole flow rate 63, and/or at least one of the surface flow rate “in” 61 and the surface flow rate “out” 65. For example, the leak rate may be the difference between the flow rate “in” 61 and the downhole flow rate 63 or the difference between the flow rate “out” 65 and the downhole flow rate 63.

The location or depth 906 of the defect 39 may be determined using the first relationship, the leak rate, at least one of the flow rates 61, 63, 65, a pressure differential between two of the measured pressures 67, 69, 71, 73, and/or the measured and true vertical depth of the drill bit 32. One of the pressure measurements used to determine the pressure differential may be the surface stand pipe pressure 67 or the surface mud line return pressure 73.

The depth 906 of the defect 39 may be the depth on the graph 900 at which the slope of the line 902 (representing the flow through the drill string 30) changes and/or the depth on the graph 900 at which the slope of the line 904 (representing the flow through the annulus 37) changes. As shown, these changes in the slope occur at the same depth. The determinations of the leak rate through the defect 39 and/or the location 906 of the defect 39 may be determined using the computer system 2100, as discussed in more detail below.

In another embodiment, the leak rate through the defect 39 and the location 906 of the defect 39 may be determined using the first relationship, at least one of the surface flow rates 61, 65, at least two pressure differentials, and/or the measured and true vertical depth of the drill bit 32. The pressure differentials may be determined using any of the measured pressures 67, 69, 71, 73.

In yet another embodiment, the leak rate through the defect 39 and the location 906 of the defect 39 may be determined using the first relationship, the downhole flow rate 63, at least two pressure differentials, and/or the measured and true vertical depth of the drill bit 32. Each of the pressure differentials may use the surface stand pipe pressure 67 or the surface mud line return pressure 73.

FIG. 10 depicts an illustrative graph 1000 showing the downhole flow rate 63 being greater the surface flow rate “in” 61 and the surface flow rate “out” 65, according to one or more embodiments. When the downhole flow rate 63 is greater than the flow rate “in” 61 and/or the flow rate “out” 65 by a predetermined amount (or threshold), the alarm may trigger. In this instance, the alarm may indicate a failure in the downhole flow rate sensor 62.

FIG. 11 depicts an illustrative graph 1100 showing the surface flow rate “in” 61 being less than the downhole flow rate 63 and the surface flow rate “out” 65, according to one or more embodiments. When the flow rate “in” 61 is less than the downhole flow rate 63 and/or the flow out rate 65 by a predetermined amount (or threshold), the alarm may trigger. In this instance, the alarm may indicate a failure in the surface flow rate “in” sensor 60.

FIG. 12 depicts an illustrative graph 1200 showing the surface flow rate “in” 61 being greater than the downhole flow rate 63 and the surface flow rate “out” 65, according to one or more embodiments. When the flow rate “in” 61 is greater than the downhole flow rate 63 and/or the flow rate “out” 65 by a predetermined amount (or threshold), the alarm may trigger. In this instance, the alarm may indicate a failure in the surface flow rate “in” sensor 60.

FIG. 13 depicts an illustrative graph 1300 showing the surface flow rate “out” 65 being less than the surface flow rate “in” 61 and the downhole flow rate 63, according to one or more embodiments. When the flow rate “out” 65 is less than the surface flow rate “in” 61 and/or the downhole flow rate 63 by a predetermined amount (or threshold), the alarm may trigger. The alarm may indicate that a portion of the drilling fluid is being lost into the formation 38 (e.g., through fractures in the formation 38). In another embodiment, the alarm may indicate a failure in the surface flow rate “out” sensor 64.

FIG. 14 depicts an illustrative graph 1400 showing the pressure of the drilling fluid as it flows down through the drill string 30, through the drill bit 32, and back up through the annulus 37 when the surface flow rate “out” 65 is less than the surface flow rate “in” 61 and the downhole flow rate 63, according to one or more embodiments. Referring to FIGS. 13 and 14, the flow rate or leak rate into the formation 38 may be determined using the first relationship, the surface flow rate “out” 65, and/or at least one of the surface flow rate “in” 61 and the downhole flow rate 63.

The location or depth 1406 of the fractures into which the drilling fluid is leaking may be determined using the first relationship, the leak rate, at least one of the flow rates 61, 63, 65, a pressure differential between two of the measured pressures 67, 69, 71, 73, and/or the measured and true vertical depth of the drill bit 32. One of the pressure measurements used to determine the pressure differential may be the surface stand pipe pressure 67 or the surface mud line return pressure 73. For example, the depth 1406 of the defect 39 may be the depth on the graph 1400 at which the slope of the line 1404 (representing the flow through the annulus 37) changes. The determinations of the leak rate into the formation 38 and/or the location 1406 of the fractures may be determined using the computer system 2100, as discussed in more detail below.

In another embodiment, the leak rate into the formation 38 and the location 1406 of the fractures may be determined using the first relationship, at least one of the surface flow rates 61, 65, at least two pressure differentials, and/or the measured and true vertical depth of the drill bit 32. The pressure differentials may be determined using any of the pressure sensors 66, 68, 70, 72.

In yet another embodiment, the leak rate into the formation 38 and the location 1406 of the fractures may be determined using the first relationship, the downhole flow rate 63, at least two pressure differentials, and/or the measured and true vertical depth of the drill bit 32. Each of the pressure differentials may use the surface stand pipe pressure 67 or the surface mud line return pressure 73.

FIG. 15 depicts an illustrative graph 1500 showing the surface flow rate “out” 65 being greater than the surface flow rate “in” 61 and the downhole flow rate 63, according to one or more embodiments. When the flow rate “out” 65 is greater than the flow rate “in” 61 and/or the downhole flow rate 63 by a predetermined amount (or threshold), the alarm may trigger. The alarm may indicate that fluid (e.g., hydrocarbon fluid such as oil or gas) is flowing out of the formation 38 and to the surface with the drilling fluid. This is known as a “formation kick.” In another embodiment, the alarm may indicate a failure in the surface flow rate “out” sensor 64.

FIG. 16 depicts an illustrative graph 1600 showing the pressure of the drilling fluid as it flows down through the drill string 30, through the drill bit 32, and back up through the annulus 37 when the surface flow rate “out” 65 is greater than the surface flow rate “in” 61 and the downhole flow rate 63, according to one or more embodiments. Referring to FIGS. 15 and 16, the formation kick flow rate may be determined using the first relationship, the surface flow rate “out” 65 and/or at least one of the surface flow rate “in” 61 and the downhole flow rate 63.

The location or depth 1606 of the fractures through which the formation fluid flows may be determined using the first relationship, the formation kick flow rate, at least one of the flow rates 61, 63, 65, a pressure differential between two of the measured pressures 67, 69, 71, 73, and/or the measured and true vertical depth of the drill bit 32. One of the pressure measurements used to determine the pressure differential may be the surface stand pipe pressure 67 or the surface mud line return pressure 73. For example, the depth 1606 of the defect 39 may be the depth on the graph 1600 at which the slope of the line 1604 (representing the flow through the annulus 37) changes. The determinations of the formation kick flow rate and/or the location 1606 of the fractures may be determined using the computer system 2100, as discussed in more detail below.

In another embodiment, the formation kick flow rate and the location 1606 of the fractures may be determined using the first relationship, at least one of the surface flow rates 61, 65, at least two pressure differentials, and/or the measured and true vertical depth of the drill bit 32. The pressure differentials may be determined using any of the pressure measurements 67, 69, 71, 73.

In yet another embodiment, the formation kick flow rate and the location 1606 of the fractures may be determined using the first relationship, the downhole flow rate 63, at least two pressure differentials, and/or the measured and true vertical depth of the drill bit 32. Each of the pressure differentials may use the surface stand pipe pressure 67 or the surface mud line return pressure 73.

FIGS. 17-20 depict another illustrative process for identifying a drill string washout, a formation loss, and/or a formation kick. More particularly, FIG. 17 depicts the drill string 30 having a plurality of distributed internal pressure while drilling sensors 68 and a plurality of distributed annular pressure while drilling sensors 70, according to one or more embodiments.

The internal pressure while drilling sensors 68 may be disposed within the drill string 30 and spaced axially apart from one another. The distance between any two internal pressure while drilling sensors 68 may range from about 0.5 m to about 2 m, about 2 m to about 5 m, about 5 m to about 10 m, about 10 m to about 25 m, about 25 m to about 50 m, about 50 m to about 100 m, about 0.5 m to about 100 m, or more. The internal pressure while drilling sensors 68 may measure the pressure 69 of the drilling fluid at predetermined locations along the drill string 30. For example, the distance between each pair of internal pressure while drilling sensors 68 may be substantially the same.

The annular pressure while drilling sensors 70 may be disposed on an exterior of the drill string 30 and spaced axially apart from one another. The distance between any two annular pressure while drilling sensors 70 may range from about 0.5 m to about 2 m, about 2 m to about 5 m, about 5 m to about 10 m, about 10 m to about 25 m, about 25 m to about 50 m, about 50 m to about 100 m, about 0.5 m to about 100 m, or more. The annular pressure while drilling sensors 70 may measure the pressure 71 of the drilling fluid in the annulus 37 at predetermined locations along the drill string 30. For example, the distance between each pair of annular pressure while drilling sensors 70 may be substantially the same.

Drilling fluid may be pumped down through the drill string 30, through the drill bit 21, and back up through the annulus 37 to the surface. The internal pressure while drilling sensors 68 may measure the pressure 69 of the drilling fluid at predetermined locations within the drill string 30. The annular pressure while drilling sensors 70 may measure the pressure 71 of the drilling fluid in the annulus 37 at predetermined locations along the drill string 30. The measured depth of the drill bit 32 and the true vertical depth of the drill bit 32 may also be measured. One or more of the surface flow “in” rate 61, the downhole flow rate 63, and the surface flow “out” rate 65 may be measured. The rate of rotation of the drill string 30 may also be measured.

A second multidimensional relationship may be determined based upon the distributed pressure measurements 69, 71, the depth measurements of the drill bit 32, and the flow rates 61, 63, 65 based upon normal drilling conditions. The second relationship may be determined using a parametric theoretical model, statistical analysis techniques (e.g., principal component analysis), factor analysis, and/or neural network empirical correlations. An alarm may trigger when the internal pressure measurements 69, the annular pressure measurements 71, or both deviate from the second relationship by a predetermined amount (or threshold).

FIG. 18 depicts an illustrative graph 1800 showing the pressure of the drilling fluid as it flows down through the drill string 30, through the drill bit 32, and back up through the annulus 37 when there is a defect 39 in the drill string 30, as may be caused by a drill string washout, according to one or more embodiments. When the internal pressure measurements 69 and the annular pressure measurements 71 deviate from the second relationship by the predetermined amount (or threshold), this may be an indication that a defect 39 exists in the drill string 30, as may be caused by a drill string washout.

The depth 1806 of the defect 39 may be the depth on the graph 1800 at which the slope of the line 1802 (representing the flow through the drill string 30) changes and/or the depth on the graph 1800 at which the slope of the line 1804 (representing the flow through the annulus 37) changes. As shown, these changes in the slope occur at the same depth.

The flow rate or leak rate through the defect 39 may be determined using first relationship, the downhole flow rate 63, and/or at least one of the surface flow rate “in” 61 and the surface flow rate “out” 65. The flow rates 61, 63, 65 may be measured directly using the surface flow rate “in” sensor 60, the downhole flow rate sensor 62, and the surface flow rate “out” sensor 64, respectively. In another embodiment, the flow rates 61, 63, 63 may be inferred from the distributed internal pressure measurements 69 and the distributed annular pressure measurements 71 using the second relationship.

FIG. 19 depicts an illustrative graph 1900 showing the pressure of the drilling fluid as it flows down through the drill string 30, through the drill bit 32, and back up through the annulus 37 when a portion of the drilling fluid is being lost into the formation 38, according to one or more embodiments. When the annular pressure measurements 71 deviate from the second relationship by the predetermined amount (or threshold), and the distributed pressure profile of line 1904 is convex at the depth 1906, this may be an indication that a portion of the drilling fluid is being lost into the formation 38.

The location or depth 1906 of the fractures into which the drilling fluid is leaking may be the depth on the graph 1900 at which the slope of the line 1904 (representing the flow through the annulus 37) changes. The flow rate into the formation 38 may be determined using first relationship, the flow rate “out” 65, and/or at least one of the surface flow rate “in” 61 and the downhole flow rate 63. The flow rates 61, 63, 65 may be measured directly using the surface flow rate “in” sensor 60, the downhole flow rate sensor 62, and the surface flow rate “out” sensor 64, respectively. In another embodiment, the flow rates 61, 63, 65 may be inferred from the distributed internal pressure measurements 69 and the distributed annular pressure measurements 71 using the second relationship.

FIG. 20 depicts an illustrative graph 2000 showing the pressure of the drilling fluid as it flows down through the drill string 30, through the drill bit 32, and back up through the annulus 37 when fluid (e.g., hydrocarbon fluid such as oil or gas) is flowing out of the formation 38 and to the surface with the drilling fluid, according to one or more embodiments. When the annular pressure measurements 71 deviate from the second relationship by the predetermined amount (or threshold), and the distributed pressure profile of line 2004 is concave at the depth 2006, this may be an indication that fluid (e.g., hydrocarbon fluid such as oil or gas) is flowing out of the formation 38 and to the surface with the drilling fluid.

The location or depth 2006 of the fractures through which the formation fluid is flowing may be the depth on the graph 2000 at which the slope of the line 2004 (representing the flow through the annulus 37) changes. The flow rate from the formation 38 may be determined using first relationship, the flow rate “out” 65, and/or at least one of the surface flow rate “in” 61 and the downhole flow rate 63. The flow rates 61, 63, 65 may be measured directly using the surface flow rate “in” sensor 60, the downhole flow rate sensor 62, and the surface flow rate “out” sensor 64, respectively. In another embodiment, the flow rates 61, 63, 65 may be inferred from the distributed internal pressure measurements 69 and the distributed annular pressure measurements 71 using the second relationship.

FIG. 21 depicts a schematic view of the computer system 2100, according to one or more embodiments. The computer system 2100 may be disposed within the drill string 30 or at the surface (e.g., on the drilling rig 10). The computer system 2100 may include a processor, microprocessor, or central processing unit (“CPU”) 2102, an input device or keyboard 2104, and a monitor 2106. The computer system 2100 may also include a memory 2108 to store data and/or software or program information. The computer system 2100 may further include additional input and output devices such as a mouse 2110, a microphone 2112, and/or a speaker 2114, which may be used for universal access and voice recognition or commanding. The monitor 2106 may be touch-sensitive to operate as an input device as well as a display device.

The computer system 2100 may interface with a database 2116, a processor 2118, or the Internet via an interface 2120. It should also be understood that the database 2116 and the processor 2118 are not limited to interfacing with computer system 2100 using the network interface 2120 and can interface with the computer system 2100 in any manner sufficient to create a communications path between the computer system 2100 and the database 2116 and/or processor 2118. For example, in an illustrative embodiment, the database 2116 may interface with the computer system 2100 via a USB interface while the processor 218 may interface via another high-speed data bus without using the network interface 2120.

The computer system 2100 may receive signals indicative of the spin rate of the turbine 50. The computer system 2100 may also receive signals from the flow rate sensors 60, 62, 64 and/or signals from the pressure sensors 66, 68, 70, 72. The processor 2102 of the computer system 2100 may be configured to execute a computer program or instructions embodied on a non-transitory computer readable medium. When executed by the processor 2102, the computer program may process the signals to determine the first relationship and/or the second relationship. The computer program may also determine the existence of a defect 39 in the drill string 30, the flow rate through the defect 39, and the location of the defect 39. Moreover, the computer program may determine the existence of formation losses or a formation kick.

It should be understood that even though the computer system 2100 is shown as a platform on which the illustrative methods described may be performed, the methods described may be performed on a number of computer or microprocessor based platforms. For example, the various illustrative embodiments described herein may be used or implemented on any device that has computing/processing capability. These devices may include, but are not limited to: supercomputers, arrayed server networks, arrayed memory networks, arrayed computer networks, distributed server networks, distributed memory networks, distributed computer networks, desktop personal computers (PCs), tablet PCs, hand held PCs, laptops, devices sold under the trademark names BLACKBERRY® or PALM®, cellular phones, hand held music players, or any other device or system having computing capabilities.

Although only a few example embodiments have been described in detail above, those skilled in the art will readily appreciate that many modifications are possible in the example embodiments without materially departing from “Detecting a Drill string Washout Event.” Accordingly, all such modifications are intended to be included within the scope of this disclosure. In the claims, means-plus-function clauses are intended to cover the structures described herein as performing the recited function and not only structural equivalents, but also equivalent structures. Thus, although a nail and a screw may not be structural equivalents in that a nail employs a cylindrical surface to secure wooden parts together, whereas a screw employs a helical surface, in the environment of fastening wooden parts, a nail and a screw may be equivalent structures. It is the express intention of the applicant not to invoke 35 U.S.C. §120, paragraph 6 for any limitations of any of the claims herein, except for those in which the claim expressly uses the words ‘means for’ together with an associated function.

Certain embodiments and features have been described using a set of numerical upper limits and a set of numerical lower limits. It should be appreciated that ranges including the combination of any two values, e.g., the combination of any lower value with any upper value, the combination of any two lower values, and/or the combination of any two upper values are contemplated unless otherwise indicated. Certain lower limits, upper limits and ranges appear in one or more claims below. All numerical values are “about” or “approximately” the indicated value, and take into account experimental error and variations that would be expected by a person having ordinary skill in the art.

Various terms have been defined above. To the extent a term used in a claim is not defined above, it should be given the broadest definition persons in the pertinent art have given that term as reflected in at least one printed publication or issued patent. Furthermore, all patents, test procedures, and other documents cited in this application are fully incorporated by reference to the extent such disclosure is not inconsistent with this application and for all jurisdictions in which such incorporation is permitted.

Claims

1. A method for detecting a drill string washout event, comprising:

locating a drill string in a wellbore formed in a subterranean formation;

pumping a drilling fluid into the drill string, wherein the drill string comprises a turbine, and wherein the turbine spins in response to the drilling fluid flowing therethrough;

comparing a rate that the drilling fluid is pumped into the drill string to a spin rate of the turbine; and

determining that a defect is formed in the drill string based upon the comparison.

2. The method of claim 1, wherein comparing the rate that the drilling fluid is pumped into the drill string to the spin rate of the turbine comprises determining a ratio of the rate that the drilling fluid is pumped into the drill string to the spin rate of the turbine.

3. The method of claim 2, further comprising determining that the defect is formed in the drill string when the ratio is below a predetermined threshold.

4. The method of claim 3, further comprising triggering an alarm when the ratio is below the predetermined threshold for a predetermined amount of time.

5. The method of claim 1, wherein the defect comprises a crack or opening formed in the drill string that allows the drilling fluid to flow therethrough and into an annulus formed between the drill string and a wall of the wellbore.

6. The method of claim 5, further comprising determining a flow rate through the defect.

7. The method of claim 5, further comprising determining a location of the defect in the drill string.

8. A method for monitoring fluid flow in a wellbore, comprising:

locating a drill string in a wellbore formed in a subterranean formation, wherein an annulus is formed between the drill string and a wall of the wellbore;

pumping a drilling fluid into the drill string from a surface location, wherein the drilling fluid flows through a drill bit positioned at an end portion of the drill string and back to the surface location via the annulus;

measuring a flow rate into the drill string with a first flow rate sensor disposed at the surface location;

measuring a downhole flow rate with a second flow rate sensor disposed within the wellbore;

measuring a flow rate out of the annulus with a third flow rate sensor disposed at the surface location; and

establishing a multi-dimensional relationship based upon the flow rate into the drill string, the downhole flow rate, and the flow rate out of the annulus.

9. The method of claim 8, wherein the multi-dimensional relationship is determined using a parametric theoretical model, a statistical analysis technique, a principal component analysis, a factor analysis, neural network empirical correlations, or combinations thereof.

10. The method of claim 8, further comprising determining that a defect is formed in the drill string if the downhole flow rate is less than the flow rate into the drill string by a predetermined amount, if the downhole flow rate is less than the flow rate out of the annulus by the predetermined amount, or both, wherein the defect comprises a crack or opening formed in the drill string that allows the drilling fluid to flow therethrough and into the annulus.

11. The method of claim 10, further comprising determining a location of the defect in the drill string using:

at least one of the flow rate into the drill string, the downhole flow rate, and the flow rate out of the annulus;

a pressure differential between two sensors, wherein the two sensors are selected from the group consisting of a sensor disposed at the surface location and adapted to measure a pressure of the drilling fluid being pumped into the drill string, a sensor disposed within the drill string and adapted to measure a pressure of the drilling fluid within the drill string, a sensor disposed within the annulus and adapted to measure a pressure of the drilling fluid within the annulus, and a sensor disposed at the surface location and adapted to measure a pressure of the drilling fluid flowing out of the annulus; and

a depth of the drill bit.

12. The method of claim 8, further comprising determining that a portion of the drilling fluid is flowing into the subterranean formation if the flow rate out of the annulus is less than the flow rate into the drill string by a predetermined amount, if the flow rate out of the annulus is less than the downhole flow rate by the predetermined amount, or both.

13. The method of claim 12, further comprising determining a location where the drilling fluid flows into the formation using:

at least one of the flow rate into the drill string, the downhole flow rate, and the flow rate out of the annulus;

a pressure differential between two sensors, wherein the two sensors are selected from the group consisting of a sensor disposed at the surface location and adapted to measure a pressure of the drilling fluid being pumped into the drill string, a sensor disposed within the drill string and adapted to measure a pressure of the drilling fluid within the drill string, a sensor disposed within the annulus and adapted to measure a pressure of the drilling fluid within the annulus, and a sensor disposed at the surface location and adapted to measure a pressure of the drilling fluid flowing out of the annulus; and

a depth of the drill bit.

14. The method of claim 8, further comprising determining that formation fluid is flowing into the annulus from the subterranean formation if the flow rate out of the annulus is greater than the flow rate into the drill string by a predetermined amount, if the flow rate out of the annulus is greater than the downhole flow rate by the predetermined amount, or both.

15. The method of claim 14, further comprising determining a location where the formation fluid flows from the formation using:

at least one of the flow rate into the drill string, the downhole flow rate, and the flow rate out of the annulus;

a pressure differential between two sensors, wherein the two sensors are selected from the group consisting of a sensor disposed at the surface location and adapted to measure a pressure of the drilling fluid being pumped into the drill string, a sensor disposed within the drill string and adapted to measure a pressure of the drilling fluid within the drill string, a sensor disposed within the annulus and adapted to measure a pressure of the drilling fluid within the annulus, and a sensor disposed at the surface location and adapted to measure a pressure of the drilling fluid flowing out of the annulus; and

a depth of the drill bit.

16. The method of claim 8, wherein at least one of the flow rate into the drill string, the downhole flow rate, and the flow rate out of the annulus is determined using a plurality of distributed pressure sensors coupled to the drill string.

17. The method of claim 8, wherein the downhole flow rate comprises a flow rate within the drill string, a flow rate in the annulus, or both.

18. A computer program embodied on a non-transitory computer readable medium that, when executed by a processor, controls a method for detecting a drill string washout event, comprising:

establishing a multi-dimensional relationship based upon a flow rate into a drill string, a downhole flow rate, and a flow rate out of an annulus, wherein the drill string is disposed in the wellbore, and the annulus is formed between the drill string and a wall of the wellbore; and

determining that a defect is formed in the drill string using: at least one of the flow rate into the drill string, the downhole flow rate, and the flow rate out of the annulus; a pressure differential between two sensors, wherein the two sensors are selected from the group consisting of a sensor disposed at the surface location and adapted to measure a pressure of the drilling fluid being pumped into the drill string, a sensor disposed within the drill string and adapted to measure a pressure of the drilling fluid within the drill string, a sensor disposed within the annulus and adapted to measure a pressure of the drilling fluid within the annulus, and a sensor disposed at the surface location and adapted to measure a pressure of the drilling fluid flowing out of the annulus; and a depth of a drill bit coupled to an end portion of the drill string.

19. The method of claim 18, wherein the multi-dimensional relationship is determined using a parametric theoretical model, a statistical analysis technique, a principal component analysis, a factor analysis, neural network empirical correlations, or combinations thereof.

20. The method of claim 18, wherein at least one of the flow rate into the drill string, the downhole flow rate, and the flow rate out of the annulus is determined using a plurality of distributed pressure sensors coupled to the drills string.