Patent Publication Number: US-2017356284-A1

Title: Method of Pressure Testing a Wellbore

Description:
CROSS-REFERENCE TO RELATED APPLICATIONS 
     None 
     BACKGROUND 
     This disclosure relates generally to methods for testing subterranean wellbores. More specifically, this disclosure relates to methods for utilizing downhole pressure measurements to determine pressure gradients and wellbore pressure conditions. 
     Subterranean formations can generally be characterized as having a “formation pressure” and a “fracture pressure.” The formation pressure is the pressure at which formation fluids are stored within the pores of the formation. The fracture pressure is the pressure at which the formation will yield or fracture. During conventional drilling, the total pressure applied on the wellbore, which is the drilling fluid&#39;s hydrostatic column plus any additional applied pressure from the surface, is generally maintained at a level above the formation pressure, to prevent formation fluids from flowing into the wellbore, and below the fracture pressure, to prevent damage to the formation. 
     Both the formation pressure and the fracture pressure change along the depth of the wellbore as hydrostatic pressure changes and different formations are encountered. To stabilize the wellbore, wellbores are often lined with pipes, known as casings or liners, which are cemented into place and isolate the wellbore from the surrounding formation. Casings and liners are conventionally installed in series with each successive casing or liner having a smaller inner diameter as compared to the casing or liner immediately above it. 
     When drilling an open wellbore into the formation below a newly installed casing or liner, one or more pressure tests may be performed to determine the formation pressure and/or the fracture pressure, or to verify the pressure integrity of the casing or liner to ensure that this wellbore reinforcement has been properly installed. These pressure tests may be referred to as formation integrity tests, leak-off tests, negative pressure tests, or pressure integrity tests. In general, the objective of each of these tests is to determine characteristics and integrity of the wellbore immediately beneath the newly installed casing or liner. For example, a leak-off test, or LOT, is used to determine the fracture pressure of the formation while a formation integrity test, or FIT, is used to determine the ability of the formation to handle a predetermined pressure. 
     Prior to performing a pressure test, rotation of the drill string is stopped and drilling mud is circulated through the wellbore to remove formation cuttings and debris from the wellbore. Removing formation cuttings and debris helps ensure that the wellbore contains a substantially homogenous fluid. Removing formation cuttings and debris from the wellbore is also important because, once circulation of drilling fluid has stopped, the formation cuttings and debris will settle to the bottom of the wellbore. The settling formation cuttings and debris may accumulate around the drill string and inhibit movement of the drill string once drilling is restarted. Because conventional pressure measurements are taken at the surface, they require the wellbore to be filled with a homogeneous fluid in order to calculate the pressure at the bottom of the wellbore based on pressure measurements taken at the surface. 
     Once circulation of drilling mud is complete, the wellbore annulus is sealed off and drilling mud is pumped into the wellbore, either through the drill string or alternatively into the annulus of the sealed wellbore, to increase wellbore pressure. The pumping of drilling mud continues until a predetermined wellbore pressure is achieved or it become evident that the point of formation fracturing has been reached and drilling mud is being lost into the formation. Once the predetermined wellbore pressure is achieved, pumping is stopped and the wellbore pressure is monitored. Monitoring the wellbore pressure allows an operator to determine a wide range of information, including, but not limited to, determining (a) if the wellbore has pressure integrity (in the case of a formation integrity test), (b) certain the formation characteristics, such as fracture propagation pressure, (c) the fracture initiation pressure (in the case of a leak-off test), (d) if wellbore fluids are entering the wellbore, and/or (e) if drilling mud is entering the formation. 
     As previously mentioned, during conventional wellbore pressure tests the wellbore pressure is determined by measuring the pressure at the surface and calculating downhole pressure using the known density of the drilling mud. Due primarily to the time needed to remove formation cuttings and debris from the wellbore through fluid circulation wellbore pressure tests can take several hours to complete. Further, even after fluid circulation cuttings and debris removal is rarely fully effective the fluid column in the wellbore is seldom homogeneous. This introduces inaccuracies as the fluid experiences both compression due to the increased pressure at depth and expansion due to the increased temperature. Finally, it is difficult to determine if accurate reading have been obtained by a single surface measurement gauge as this device may measure incorrectly in the absence of a plurality of reference sensors. 
     Thus, there is a continuing need in the art for methods for improving wellbore pressure tests by reducing the time needed to perform the test and increasing the accuracy of the test. 
     BRIEF SUMMARY OF THE DISCLOSURE 
     A method comprises measuring a first external pressure within an annulus formed between a wellbore and a drill string disposed therein, where the first external pressure is measured by a first external pressure sensor. A fluid is pumped through the drill string into the annulus so as to move any cuttings in the annulus above the first external pressure sensor. A first internal pressure is measured within the drill string by a first internal pressure sensor. The first external pressure sensor is disposed between the first internal pressure sensor and a bottom of the wellbore. The method further includes determining a first fluid pressure gradient between the first internal pressure sensor and the first external pressure sensor and calculating a wellbore pressure at the bottom of the wellbore using the first fluid pressure gradient. A second external pressure within the annulus is measured using a second external pressure sensor and a third external pressure within the annulus is measured using a third external pressure sensor. The second external pressure sensor is disposed between the first external pressure sensor and the third external pressure sensor. The method further includes determining a second fluid pressure gradient between the first external pressure sensor, the second external pressure sensor, and the third external pressure sensor. The second fluid pressure gradient is monitored to determine the location of the cuttings in the annulus. 
     In certain embodiments, the fluid is a substantially homogeneous fluid and is disposed within the wellbore between the first internal pressure sensor and the bottom of the wellbore. In certain embodiments, the cuttings are disposed within the annulus above the first external pressure sensor. In certain embodiments, the cuttings are moved above the third external pressure sensor and the second fluid pressure gradient is monitored to determine a vertical location of the cuttings in the annulus between the first external pressure sensor and the third external pressure sensor. In certain embodiments, the method further comprises measuring an applied pressure at a location above the third external pressure sensor and determining a wellbore pressure using the applied pressure and the calculated wellbore pressure at the bottom of the wellbore. In certain embodiments, the method further comprises measuring a second internal pressure with a second internal pressure sensor, wherein the first internal pressure sensor is disposed between the second internal pressure sensor and the bottom of the wellbore, and using the second internal pressure, first internal pressure, and the first external pressure to determine the first pressure gradient. In certain embodiments, the wellbore pressure is determined as part of a formation integrity test, leak-off test, casing pressure test, or negative pressure test. 
     Also disclosed is a method comprising determining a first fluid pressure gradient between a first external pressure sensor and a first internal pressure sensor. The first external pressure sensor is disposed on a drill string so as to measure a first external pressure within an annulus between the drill string and a wellbore and the first internal pressure sensor is disposed on the drill string so as to measure a first internal pressure within the drill string. The first external pressure sensor is disposed between the first internal pressure sensor and a bottom of the wellbore. A fluid is pumped through the drill string into the annulus so as to move any cuttings in the annulus above the first external pressure sensor. A wellbore pressure at the bottom of the wellbore is calculated using the first fluid pressure gradient. A second fluid pressure gradient is calculated between the first external pressure sensor, a second external pressure sensor, and a third external pressure sensor. The second external pressure sensor and the third external pressure sensor are disposed on the drill string so as to measure pressure in the annulus. The second external pressure sensor is disposed between the first external pressure sensor and the third external pressure sensor. The second fluid pressure gradient is monitored to determine the location of the cuttings in the annulus. 
     Also disclosed is a method that comprises pumping a fluid through a drill string disposed in a wellbore and into an annulus between the drill string and the wellbore so as to move any cuttings in the annulus above a first external pressure sensor disposed on the drill string. A first external pressure is measured within the annulus with the first external pressure sensor. A wellbore pressure at a bottom of a wellbore is calculated using a first fluid pressure gradient, wherein the first fluid pressure gradient is determined using the first external pressure sensor and a first internal pressure sensor, and wherein the first external pressure sensor is disposed between the first internal pressure sensor and the bottom of the wellbore. A second fluid pressure gradient is calculated between the first external pressure sensor, a second external pressure sensor, and a third external pressure sensor, wherein the second external pressure sensor and the third external pressure sensor are disposed on the drill string so as to measure pressure in the annulus, and wherein the second external pressure sensor is disposed between the first external pressure sensor and the third external pressure sensor. The second fluid pressure gradient is monitored to determine the location of the cuttings in the annulus. 
     In certain embodiments, the fluid is a substantially homogeneous fluid and is disposed within the wellbore between the first internal pressure sensor and the bottom of the wellbore and wherein the cuttings are disposed within the annulus above the first external pressure sensor. In certain embodiments, the cuttings are moved above the third external pressure sensor and the method further comprises monitoring the second fluid pressure gradient to determine a vertical location of the cuttings in the annulus between the first external pressure sensor and the third external pressure sensor. In certain embodiments, the method further comprises measuring an applied pressure at a location above the third external pressure sensor; and determining an a wellbore pressure using the applied pressure and the calculated wellbore pressure at the bottom of the wellbore. In certain embodiments, the method further comprises measuring a second internal pressure with a second internal pressure sensor, wherein the first internal pressure sensor is disposed between the second internal pressure sensor and the bottom of the wellbore; and using the second internal pressure, first internal pressure, and the first external pressure to determine the first pressure gradient. In certain embodiments, the wellbore pressure is determined as part of a formation integrity test, leak-off test, casing pressure test, or negative pressure test. 
    
    
     
       BRIEF DESCRIPTION OF THE DRAWINGS 
       For a more detailed description of the embodiments of the present disclosure, reference will now be made to the accompanying drawings, wherein: 
         FIG. 1  is partial sectional view of a wellbore. 
         FIG. 2  is a flowchart representing a method of wellbore testing. 
         FIGS. 3A-3D  schematically illustrate circulation of a wellbore to prepare for pressure testing. 
         FIGS. 4A-4D  show a graphical representation of pressure readings during the circulation shown in  FIGS. 3A-3D . 
         FIGS. 5A-5D  schematically illustrate pressure testing a wellbore. 
         FIGS. 6A-6D  show a graphical representation of pressure readings during the circulation shown in  FIGS. 5A-5D . 
     
    
    
     DETAILED DESCRIPTION 
     It is to be understood that the following disclosure describes several exemplary embodiments for implementing different features, structures, or functions of the invention. Exemplary embodiments of components, arrangements, and configurations are described below to simplify the present disclosure; however, these exemplary embodiments are provided merely as examples and are not intended to limit the scope of the invention. Additionally, the present disclosure may repeat reference numerals and/or letters in the various exemplary embodiments and across the Figures provided herein. This repetition is for the purpose of simplicity and clarity and does not in itself dictate a relationship between the various exemplary embodiments and/or configurations discussed in the various figures. Moreover, the formation of a first feature over or on a second feature in the description that follows may include embodiments in which the first and second features are formed in direct contact, and may also include embodiments in which additional features may be formed interposing the first and second features, such that the first and second features may not be in direct contact. Finally, the exemplary embodiments presented below may be combined in any combination of ways, i.e., any element from one exemplary embodiment may be used in any other exemplary embodiment, without departing from the scope of the disclosure. 
     Additionally, certain terms are used throughout the following description and claims to refer to particular components. As one skilled in the art will appreciate, various entities may refer to the same component by different names, and as such, the naming convention for the elements described herein is not intended to limit the scope of the invention, unless otherwise specifically defined herein. Further, the naming convention used herein is not intended to distinguish between components that differ in name but not function. Additionally, in the following discussion and in the claims, the terms “including” and “comprising” are used in an open-ended fashion, and thus should be interpreted to mean “including, but not limited to.” All numerical values in this disclosure may be exact or approximate values unless otherwise specifically stated. Accordingly, various embodiments of the disclosure may deviate from the numbers, values, and ranges disclosed herein without departing from the intended scope. Furthermore, as it is used in the claims or specification, the term “or” is intended to encompass both exclusive and inclusive cases, i.e., “A or B” is intended to be synonymous with “at least one of A and B,” unless otherwise expressly specified herein. 
     Referring initially to  FIG. 1 , a wellbore  100  includes a casing string  102 . A drill string  104  is disposed within the wellbore  100  and has extended the wellbore  100  below the casing shoe  106  so that the bottom  108  of the wellbore  100  is exposed to the surrounding formation  110 . Drill string  104  includes an inner bore  112  and a plurality of drill string mounted pressure sensors  114 . Each pressure sensor  114  may include both an internal and external pressure sensor. In certain embodiments, the drill string  104  may include wired drill pipe to facilitate transmission of data from the pressure sensors  114  to the surface. 
     Once the wellbore  100  is drilled out below the casing shoe  106 , drilling fluid is circulated so that a substantially homogenous fluid  118  (the clean drilling fluid) displaces the heterogeneous fluid  116 , which includes drilling mud, formation cuttings, and other debris, at distance upward through the wellbore. As discussed above, circulating the heterogeneous fluid  116  upward through the wellbore to reduce the potential for cuttings and other debris to settle and cause the drill string to become stuck in the wellbore. The heterogeneous fluid  116  may be displaced above the first external pressure sensor  120 A, above the second external pressure sensor  122 A, above the third external pressure sensor  124 A, or at any other greater distance above the bottom  108  of the wellbore  100 . In certain embodiments, the heterogeneous fluid  116  is circulated a sufficient distance above the bottom  108  of the wellbore  108  so that the cuttings and debris will not settle around critical drill string components in the time needed to conduct a pressure test. 
     The movement of the heterogeneous fluid  116  above the bottom  108  of the wellbore  100  can be tracked by monitoring pressure measured within the annulus  126  by the first external pressure sensor  120 A, the second external pressure sensor  122 A, and the third external pressure sensor  124 A. Because the lower density homogeneous fluid  118  is being introduced from the drill string  104  at the bottom  108  of the wellbore  100 , the pressure at each of the first external pressure sensor  120 A, the second external pressure sensor  122 A, and the third external pressure sensor  124 A will remain constant until the homogeneous fluid  118  displaces the heterogeneous fluid  116  past the location of each of the individual pressure sensors. As the heterogeneous fluid  116  moves above each sensor, the pressure at that sensor will decrease. 
     With reference to  FIGS. 1 and 2 , once the heterogeneous fluid has been circulated a distance up the wellbore that will allow testing to be completed before drill string sticking becomes a concern, circulation can be stopped and a hydrostatic wellbore pressure data can be measured in step  210 . The first step  210  includes determining the hydrostatic pressure at the bottom  108  of the wellbore  100  by measuring a first external pressure and a first internal pressure. The first internal pressure is measured within the inner bore  112  by the first internal pressure sensor  122 B and a first external pressure within the annulus  126  is measured by the first external pressure sensor  120 A, which is positioned between the first internal pressure sensor  122 B and the bottom  108  of the wellbore  100 . 
     Once the first internal pressure and first external pressure have been measured, then a first fluid pressure gradient can be determined in step  220 . The vertical distance between the first external pressure sensor  120 A and the first internal pressure sensor  122 B is known. Therefore the first fluid pressure gradient can be determined by dividing the difference between the first internal pressure and the first external pressure by the distance between the first external pressure sensor  120 A and the first internal pressure sensor  122 B. In certain embodiments, additional internal and external pressure measurements can be taken to provide additional data points that can be used to determine the first fluid pressure gradient through fitting a curve or line among the several data points. In other embodiments, additional internal and external pressure measurements can be used to verify that each pressure measurement is accurate by comparing the measured pressure to the expected fluid pressure gradient. Utilizing multiple internal and external pressure measurements mitigates the reliance on a single gauge that may yield inaccurate measurements, which would be difficult to identify in the absence of verification using additional measurements. In certain embodiments, the first fluid pressure gradient can be determined between pressure measured by the first external pressure sensor  120 A and a pressure sensor at the surface. 
     Determining the first fluid pressure gradient allows for hydrostatic pressure at the bottom  108  of the wellbore  100  to be calculated in step  230 . Once the first fluid pressure gradient has been determined the hydrostatic pressure at the bottom  108  of the wellbore  100  can be calculated by extrapolating the first fluid pressure gradient from the first external pressure sensor  120 A to the bottom  108  of the wellbore  100 . Because the distance from the first external pressure sensor  120 A to the bottom  108  of the wellbore  100  is relatively short, especially in comparison to the distance from the first external pressure sensor  120 A to the surface, compression and expansion effects are negligible. 
     After the hydrostatic pressure at the bottom  108  of the wellbore  100  has been calculated, the annulus  126  can be sealed off, usually by the blowout preventer  128  at the upper end of the wellbore  100 . Additional drilling fluid can then be pumped into the drill string  104  (or down the annulus below the BOP) to gradually increase the pressure within the wellbore  100 . The first fluid pressure gradient determined under hydrostatic conditions will also apply when pumping additional fluids into the wellbore  100 . With the drill string mounted pressure sensors  114  providing near real-time pressure data, the pressure at each pressure sensor  114  can be continuously monitored throughout the pressure test so that the pressure at the bottom  108  of the wellbore  100  can be continuously calculated and monitored. 
     In the case of a formation integrity test, the pressure at the bottom  108  of the wellbore  100  is monitored until reaching a pre-selected pressure and then monitored for a period of time to ensure that no drilling fluid escapes the wellbore  100 . When doing a leak-off test the pressure at the bottom of the wellbore  100  is monitored as it increases until a deflection point is reached and the pressure begins to decrease, indicating a breakdown of the formation and loss of drilling fluid from the wellbore  100 . 
     Once the first fluid pressure gradient has been determined in step  220  and the pressure at the bottom  108  of the wellbore  100  has been calculated in step  230 , a wellbore pressure can also be determined in step  240  by measuring an applied pressure at a location above the third external pressure sensor  124 A. In certain embodiments, the applied pressure can be measured at the blowout preventer  128  or at the inlet to the inner bore  112 . The wellbore pressure can then be calculated by subtracting the applied pressure from the calculated pressure at the bottom  108  of the wellbore  100 . 
     As the cuttings and other debris contained in heterogeneous fluid  116  are denser than the homogeneous fluid  118 , the cuttings and other debris in heterogeneous fluid  116  will tend to settle toward the bottom  108  of the wellbore  100  once circulation of the drilling fluid is stopped. As previously discussed, if the cuttings and other debris are allowed to settle and build up near the bottom  108  of the wellbore  100  or around the drill string, the drill string may become stuck and be unable to rotate once the pressure testing is complete. Therefore, during pressure testing, it may be desirable to monitor the movement of the cuttings and other debris toward the bottom  108  of the wellbore  100 . 
     To monitor the movement of the cuttings and other debris, a second fluid pressure gradient can be determined in step  250 . To determine a second fluid pressure gradient, a second external pressure is measured at the second external pressure sensor  122 A and a third external pressure is measured at the third external pressure sensor  124 A. The second fluid pressure gradient can then be determined using the external pressure measured at each of the first external pressure sensor  120 A, the second external pressure sensor  122 A, and the third external pressure sensor  124 A and the known distances between the pressure sensors. As previously mentioned, the pressure at each of the external pressure sensors will decrease as the cuttings and other debris moves below the pressure sensor, which will also cause the second pressure gradient to change as the cuttings and other debris move into the previously homogeneous fluid and increase its density. This changing second fluid pressure gradient can be monitored to determine where in the annulus  126  the cuttings and other debris are located and to indicate that circulation should be started should the cuttings and other debris near the bottom  108  of the wellbore  100 . 
     Referring now to  FIGS. 3A-3D and 4A-4D , a drill string  300  is disposed within a wellbore  310 . The drill string  300  includes a lower pressure sensor  320  and an upper pressure sensor  330 . As shown in  FIG. 3A , the wellbore  310  is substantially filled with a drilling fluid containing cuttings  340 . To prepare the wellbore  310  for pressure testing, drilling is stopped and the drill string is pulled upward a short distance from the bottom of the wellbore  310 . As can be seen in  FIG. 4A , the measured pressure at lower pressure sensor  320  is higher than the measured pressure at upper pressure sensor  330 . Referring now to  FIG. 3B , clean drilling fluid  360  is pumped down into the wellbore  310  through the drill string  300  to displace the cuttings  340  upward through the wellbore  310  to that the lowermost cuttings  350  are substantially even with the lower pressure sensor  320 .  FIG. 4B  shows that pressure measurements taken in this condition are substantially equal to those taken in the condition shown in  FIG. 3A . 
     As circulation of clean drilling fluid  360  continues, the cuttings  340  move upward until the lowermost cuttings  350  are between the upper pressure sensor  330  and the lower pressure sensor  320 , as shown in  FIGS. 3C and 3D . As illustrated in  FIGS. 4C and 4D , the pressure measured by the lower pressure sensor  320  will decrease as the cuttings  340  are moved upward through the wellbore  310  and an increasing height of clean drilling fluid  360  is acting on the lower pressure sensor  320 . 
     Referring now to  FIGS. 5A-5D and 6A-6D , the movement of cuttings  340  during a wellbore pressure test is illustrated along with the effect that movement has on pressure measurements within the wellbore  310 . In  FIG. 5A , the drill string  300  is disposed within the wellbore  310  in essentially the same conditions as shown in  FIG. 3D  with the lowermost cuttings  350  at or above the upper pressure sensor  330 . To begin the wellbore pressure test ( FIG. 5B ), an annulus seal  370  is engaged to close the annulus and fluid pressure  380  is applied to the drill string  300 . As shown in  FIG. 6B , the pressure at the upper pressure sensor  330  and the lower pressure sensor  320  both increase an amount equal to the applied fluid pressure  380 . 
     As the pressure test continues the cuttings  340  move downward into the previously clean drilling fluid  360 , as shown in  FIGS. 5C and 5D . This movement increases the density of the drilling fluid in the lower portion of the wellbore  310  but decreases the density of the fluid in the upper portion of the wellbore  310 . As illustrated in  FIGS. 6C and 6D , the pressure measured by the lower pressure sensor  320  will remain constant as the cuttings  340  settle within the wellbore  310  but the pressure measured by the upper pressure sensor  330  will decrease as more of the cuttings  340  move below the upper pressure sensor  330 . 
     The embodiments described herein make reference to a vertical wellbore but it is understood that the principals and methods described herein are equally applicable to deviated and horizontal wellbores. Any references to depth or vertical depth herein are understood to mean “true vertical depth” or the depth measured in line with the gravitational force. 
     While the disclosure is susceptible to various modifications and alternative forms, specific embodiments thereof are shown by way of example in the drawings and description. It should be understood, however, that the drawings and detailed description thereto are not intended to limit the disclosure to the particular form disclosed, but on the contrary, the intention is to cover all modifications, equivalents and alternatives falling within the spirit and scope of the present disclosure.