Patent Publication Number: US-2012037361-A1

Title: Arrangement and method for detecting fluid influx and/or loss in a well bore

Description:
BACKGROUND OF THE INVENTION 
     1. Field of the Invention 
     This invention relates generally to an arrangement and method for detecting kicks (i.e., fluid influxes) and fluid losses from an oil and/or gas well. Specifically, the invention relates to an arrangement and method for accurately determining the fluid flow rate exiting a petroleum well by measuring fluid flow rate through a substantially vertical tubular, such as a bell nipple or marine riser, positioned near the top of the drill string. 
     2. Description of the Related Art 
     During the drilling of subterranean wells, a fluid (“mud”) is typically circulated through a fluid circulation system comprising a drilling rig and fluid treating equipment located substantially at or near the surface of the well. The fluid is pumped by a fluid pump through the interior passage of a drill string, through a drill bit and back to the surface through the annulus between the well bore and the drill string. 
     A primary function of the fluid is to maintain a primary barrier inside the well bore to prevent formation fluids from flowing to surface. A blow-out preventer (BOP), which has a series of valves that may be selectively opened or closed, provides a secondary barrier to prevent formation fluids from flowing uncontrolled to surface. To achieve a primary barrier inside the well bore using the fluid, the hydrostatic pressure of the fluid is maintained higher than the formation fluid pressure (“pore pressure”). Weighting agents may be added to the fluid to increase the fluid density, thereby ensuring that the hydrostatic pressure is always above the pore pressure. If, during drilling of the well bore, a zone is encountered having a higher pore pressure than the fluid pressure inside the well bore, an influx of formation fluid will be introduced into the well bore. Such occurrence is an undesirable event and is known as taking a “kick.” This same situation can occur not only during drilling, but also during completion, work-over or intervention. 
     When a kick is taken, the invading formation fluid and/or gas may “cut,” or decrease, the density of the fluid in the well bore annulus, such that an increasing amount of formation fluid enters the well bore. Under such circumstances, control of the well may be lost due to breach of the primary barrier. Such an occurrence may be noted at the drilling rig in the form of: (1) a change in pressure in the well bore annulus, (2) a change in fluid density, and/or (3) a gain in fluid volume in the fluid system tanks (“pit volume”). 
     Numerous arrangements and methods for detecting kicks (i.e., fluid influxes) and/or fluid losses while drilling wells or conducting well operations, workovers, completions, and interventions are known to those skilled in the art. Most of these arrangements and methods monitor the variation in fluid volume that is returned to the fluid/mud system tanks over time as an indicator of a kick or loss event. Using current arrangements and methods, however, this indicator is known to be inaccurate and may also be delayed, because a certain amount of volume is required for detection (i.e., typically over ten barrels). The oil and gas industry has attempted to develop improved methods of detecting kicks and losses in order to minimize their detection time as well as their fluid volume. Most of the improved methods measure the return flow rate at the return flow line and compare the measured return flow rate with the injected flow rate. Under normal circumstances the fluid flow rate into and out of the well bore should be the same (i.e., the differential flow rate should be zero). When a deviation is noted it is typically an indication of either a fluid gain or loss. The placement of flow rate meters on the return flow line from the well bore to measure the return fluid flow has been suggested but such measurements are not necessarily accurate because the return flow line is an open channel and is not always full of fluid. Therefore, the oil and gas industry has come to distrust rig kick detection systems based on this approach. 
     Another suggested approach is Managed Pressure Drilling (MPD). This method uses a closed-loop system and a flow rate meter on the return line to accurately measure the flow rate out of the well bore. The accuracy in such systems is very good, allowing the detection of a very small differential change in flow rate as well as the detection of the differential change almost immediately after the start of the kick or loss. The improved accuracy and speed of detection in MPD methods is due to the fact the well is closed and the fluid system is under pressure. The limitation posed by these systems is the amount of equipment that must be installed on a rig and kept for maintenance (e.g., to change the elements used on the rotating control heads for maintaining the well closed). This prevents the widespread use of these systems/methods, thus restricting their application to challenging wells, and only for the drilling phase. However, well control problems occur on a daily basis around the world. Such well control problems occur not just during drilling, but also during other operations. 
     Considering the aforementioned difficulties associated with the current strategies of detecting kicks (i.e., fluid influxes) and/or fluid losses while drilling wells or conducting well operations, workovers, completions, and interventions, an improved arrangement and method will provide several advantages. 
     3. Identification of Objects of the Invention 
     An object of the invention is to accomplish one or more of the following: 
     Provide an arrangement and method to improve detection of kicks and/or fluid losses from an oil and/or gas well; 
     Provide an arrangement and method for more accurately determining the flow rate of fluid flowing out of a well bore; 
     Provide an arrangement and method for measuring the flow rate of fluid flowing through a substantially vertical tubular positioned between a well blowout preventer and a return flow line; 
     Provide an arrangement and method for determining the flow rate of fluid flowing through a substantially vertical tubular while a drill string is positioned therein; 
     Provide an arrangement and method for measuring the flow rate of fluid flowing through a bell nipple; and 
     Provide an arrangement and method for measuring the flow rate of fluid flowing through a marine riser. 
     Other objects, features, and advantages of the invention will be apparent to one skilled in the art from the following specification and drawings. 
     SUMMARY OF THE INVENTION 
     The objects identified above, along with other features and advantages of the invention are incorporated in an arrangement and method for more accurately detecting kicks (i.e., fluid influxes) and/or fluid losses while drilling wells or conducting well operations, workovers, completions, and interventions. In a preferred implementation of the arrangement and method, a fluid flow measurement device is coupled to a substantially vertical tubular, such as a bell nipple or marine riser, disposed between the blowout preventer and the return flow line of a drilling system. The fluid flowing out of the well bore passes through the substantially vertical pipe prior to flowing to the surface fluid/mud tanks via the return flow line. Thus, the fluid flow rate measurement device is arranged and designed to measure the flow rate of fluid exiting the well bore. Measuring the fluid flow rate through the substantially vertical pipe facilitates the accurate measurement of the fluid flow rate, because the substantially vertical pipe is full of fluid when fluid is flowing therethrough and the flowing fluid has a hydrostatic pressure acting upon it due to the fluid above the measurement point. 
     The fluid flow measurement device of a preferred implementation is an ultrasonic flow rate meter having at least two transducers disposed on the outer surface of the substantially vertical tubular. The transducers are disposed on the substantially vertical tubular such that the ultrasonic signal, which is transmitted between the transmitter and the receiver of each transducer, passes through the annulus formed between the substantially vertical tubular and a drill string disposed therethrough. The transducers are preferably separated by a vertical distance greater than the length of a drill pipe connection, also known as a tool joint. The drill pipe connections of the drill string have a larger diameter than the surround drill pipe segments. Thus, when a drill string is disposed through the substantially vertical tubular, the annulus between the outer surface of the drill string and the inner wall of the substantially vertical tubular is reduced at the drill pipe connections. Therefore, a vertical separation between transducers of greater than the length of a drill pipe connection ensures that at least one of the transducers accurately measures the flow rate of the fluid flowing through the annulus (i.e., at least one transducer measures the annular flow rate that is not affected by a drill pipe connection). The transducers may be disposed about the substantially vertical tubular such that an ultrasonic signal is transmitted through the annulus on multiple sides of the drill string. 
     Kick or loss detection is preferably accomplished by comparing the flow rate of fluid pumped into the well bore via the drill string with the flow rate of fluid exiting the well bore through the return flow line. The flow rate of fluid pumped into the well bore is measured using another flow rate measurement device on the injection line. The flow rate of fluid exiting the well bore through the return flow line is measured by the fluid flow measurement device coupled to the substantially vertical tubular. When compared, the fluid flow into the well bore should be approximately equal to the fluid flow exiting the well bore for balanced well operations. Thus, any unexplained deviation or difference between the measured fluid flow rates is an indication that a fluid kick or fluid loss may have occurred. 
    
    
     
       BRIEF DESCRIPTION OF THE DRAWINGS 
       By way of illustration and not limitation, the invention is described in detail hereinafter on the basis of the accompanying figures, in which: 
         FIG. 1  illustrates a side view in partial cross section of a preferred implementation of the arrangement on a land rig which includes a flow rate measurement device coupled to the outer surface of a bell nipple above the blowout preventer and below the return flow line, 
         FIG. 2A  is a side view in partial cross section of the bell nipple of  FIG. 1  illustrating a drill string disposed therethrough and a flow rate measurement device coupled to an outer surface of the hell nipple, 
         FIG. 2B  is a cross section view of the bell nipple of  FIG. 2A  illustrating the drill string disposed therethrough and the flow rate measurement device coupled to an outer surface of the bell nipple, 
         FIG. 2C  is a cross section view of the bell nipple of  FIG. 2A  illustrating an alternative preferred implementation having the transducers of the flow rate measurement device disposed on the bell nipple such that an ultrasonic signal is transmitted through the annular space on two sides of the drill string, and 
         FIG. 3  illustrates a side view in partial cross section of a preferred implementation of the arrangement on an offshore rig which includes a flow rate measurement device coupled to the outer surface of a marine riser above the blowout preventer and below the return flow line. 
     
    
    
     DESCRIPTION OF THE PREFERRED IMPLEMENTATIONS OF THE INVENTION 
     A preferred implementation of the invention addresses one or more of the deficiencies of the prior art and incorporates at least one of the objects previously identified. Turning to  FIGS. 1 and 3 , a drilling system  70  is generally shown comprising a tubular drill string  30  (having, e.g., an outer diameter of 3.5 inches) suspended from a drilling rig  80 ,  90 . The drill string  30  has a lower end which extends downwardly through a vertical tubular  40  (having, e.g., an inner diameter of 8 inches), through a blowout preventer (BOP)  50  (positioned below the vertical tubular  40 ) and into borehole/well bore  14 . Borehole/well bore  14  is shown as having a casing  54  disposed below the wellhead  52 . A drill bit  34  is coupled to the lower or distal end portion of drill string  30 . A drill string driver or turning device  16 , such as a top drive system (as shown) or a rotary drive system (not shown), is operatively coupled to an upper end of the drill string  30  for turning or rotating the drill string  30  along with the drill bit  34  to drill the well bore  14 . A surface fluid/mud pump  72  pumps fluid from a surface reservoir  74  through a fluid injection line  76 , through the upper end of the drill string  30 , down the interior of drill string  30 , through the drill bit  34  and into the borehole annulus  42 . The borehole annulus  42  is created through the action of turning drill string  30  and attached drill bit  34  in borehole  14  and is defined as the space between the interior/inner wall or diameter of borehole  14  and the exterior/outer surface or diameter of the drill string  30 . An annular space  44 ,  46  also exists between the drill string  30  and each of the interior/inner walls of the BOP  50  and vertical tubular  40 . 
     Fluid pumped into the borehole annulus  42  through the drill string  30  flows upwardly through the borehole annulus  42 . The BOP  50  is in fluid communication with the borehole annulus  42  and the fluid exits the borehole annulus  42  into the annular space  44  of the BOP  50 . Substantially vertical tubular  40  has an inlet  36  coupled to blow-out preventer  50  and an outlet  38  coupled to return flow line  60 . Fluid flowing through the annular space  44  of the BOP  50  enters the annular space  46  of the substantially vertical tubular  40  through inlet  36  and exits through the outlet  38  to the return flow line  60 . The return flow line  60  is shown as a sub-horizontal tubular which provides fluid communication to mud tanks  74 . As shown in  FIGS. 1 ,  2 A, and  3 , the return flow line  60  is generally not full of fluid, and this condition causes inaccuracies in measuring the flow rate of fluid through the return flow line  60  using prior art devices and methods (not shown). On land rigs  80 , the substantially vertical tubular  40 , which is positioned above the BOP  50 , is called the bell nipple ( FIGS. 1 ,  2 A,  2 B and  2 C). On off-shore rigs  90  (e.g., floating vessels), the substantially vertical tubular  40 , which is positioned above the BOP  50 , is a marine riser ( FIG. 3 ). 
     As shown in  FIGS. 1-3 , a preferred implementation of the arrangement  10  (FIGS.  1  and  2 A- 2 C),  12  ( FIG. 3 ) and method includes a flow rate measurement device  20 , such as a flow rate meter, coupled to a section of substantially vertical tubular  40  (i.e., a bell nipple as shown in  FIG. 1  or a marine riser as shown in  FIG. 3 ), below its outlet  38  to the return flow line  60 . When the drill string  30  is disposed through the vertical tubular  40 , through the BOP  50  and into the well bore  14 , the flow rate measurement device  20  measures the flow rate of fluid being returned through the annular space  46  between the inner diameter of the vertical tubular  40  and the outer surface of the drill string  30 . When no drill string  30  is present in the vertical tubular  40 , the BOP  50  and the well bore, the flow rate measurement device  20  measures the flow rate of fluid being returned through the entire diameter of the vertical tubular  40 . The flow rate measurement device  20  of a preferred implementation of the arrangement  10 ,  12  is an ultrasonic flow rate meter because of its flexibility to measure flow rate regardless of whether a drill string  30  is present. Those skilled in the art will readily recognize that other types of flow rate meters, such as a coriolis flow rate meter, a magnetic flow rate meter, and/or a laser-based optical flow rate meter, may be equally employed to measure the flow rate of fluid flowing through the vertical tubular  40 . As is well known to those skilled in the art, an ultrasonic flow rate meter measures the velocity of the fluid flow based on several parameters including, but not limited to, the inner diameter of the tubular, the wall thickness of the tubular, its material of construction and the type of fluid flowing therethrough. As is readily known to those skilled in the art, the volumetric flow rate, Q, for the annular flow is calculated through the following equation: Q=v*π* (R o   2 -R i   2 ), where v is the velocity as determined by the flow rate measurement device  20 , R o  is the inner radius of the substantially vertical tubular  40 , and R i  is the outer radius of the drill string  30 . 
     As best shown in  FIG. 2A , the drill string  30  is comprised of drill pipe segments  28  coupled via drill pipe connections  32 . The drill pipe connections  32  have larger outer diameters than the outer diameters of the adjacent drill pipe segments  28 . Thus, when the drill string  30  is disposed within the vertical tubular  40 , an annular space  46  is created between the outer surface of the drill string  30  and the inner diameter of the vertical tubular  40 . However, the annular space  46  surrounding the drill pipe connections  32  is less than the annular space  46  surrounding the drill pipe segments  28  between drill pipe connections  32 . Because there is less annular space  46  surrounding the drill pipe connections  32 , the fluid velocity through the annulus  46  of the vertical tubular  40  must increase in the vicinity of the drill pipe connections  32  in order to maintain a constant volumetric flow rate through the vertical tubular  40 . Therefore, coupling a flow rate measurement device  20 , such as an ultrasonic rate meter, having a single transducer  22  (i.e., a transmitter and receiver pairing) to the vertical tubular  40  will not always provide an accurate measurement of fluid flow rate through the vertical tubular  40 . This is because the drill string  30 , and consequently the drill pipe connections  32 , move up and down within the vertical tubular  40  during various operations. Thus, when a drill pipe connection  32  moves into the section of the vertical tubular  40  in which the single transducer  22  is disposed, the ultrasonic flow rate meter  20  measures an increased fluid velocity due to the reduced annular space  46  between the interior/inner wall of the vertical tubular  40  and the outer surface of the drill pipe connection  32 . Because the ultrasonic flow rate meter  20  does not recognize the reduced annular space  46  caused by the drill pipe connection  32 , the ultrasonic flow rate meter  20  calculates the volumetric fluid flow rate based upon the measured, increased fluid velocity and the annular space dimensions as if the measurement was conducted between drill pipe connections  32 . 
     As best shown in  FIG. 2A , the ultrasonic flow rate meter  20  of preferred implementation  10  has two transducers  22 ,  26  (i.e., an upper transmitter/receiver pairing  22  and a lower transmitter/receiver pairing  26 ) disposed about the outer surface of vertical tubular  40 . The two of more transducers  22 ,  26  of the ultrasonic flow rate meter  20  are not disposed at the same vertical position on the outer surface of vertical tubular  40 . Instead, the plurality of transducers  22 ,  26  are separated by a vertical distance or separation  24  with respect to each other, which is designed to be at least the length/distance of a drill pipe connection  32 . This distance or separation  24  permits at least one of the transducers  22 ,  26  to measure the fluid velocity in the annular space  46  at a point between the drill pipe connections  32  as the drill string  30  moves up and down during drilling and/or other operations. Thus, at least one of the transducers  22 ,  26  measures a fluid velocity and calculates a volumetric fluid flow rate that is not affected by the reduced annular space  46  due to a drill pipe connection  32 . 
     As best shown in  FIG. 2B , the upper transducer  22  (i.e., a transmitter and receiver pairing) is disposed about the vertical tubular  40  such that the transducer transmits an ultrasonic signal  18  (i.e., shown by the broken line between transmitter and receiver) through the annular space  46  of the vertical tubular without passing through the drill string  30 . The lower transducer  26  (i.e., a transmitter and receiver pairing) is analogous to the upper transducer but is disposed a vertical distance  24  ( FIGS. 1 ,  2 A and  3 ) below the upper transducer  22  and thus can not be seen in  FIG. 2B . The upper and lower transducers  22 ,  26  may be on the same side of the drill string  30 , as shown in  FIGS. 1 ,  2 A,  2 B, and  3 , or on opposite sides of the drill string  30  ( FIG. 2C ) such that the transducers  22 ,  26  transmit an ultrasonic signal  18  through the annular space  46  on two sides of the drill string  30 . One skilled in the art will readily recognize that a plurality of transducers (not shown) may be disposed about the vertical tubular  40  such that an ultrasonic signal  18  is transmitted through the annular space  46  around the entire circumference of the drill string  30 . Again, at least two of the transducers  22 ,  26  are preferably separated by a vertical distance  24  relative to the drill string  30 . 
     As illustrated in  FIGS. 1 ,  2 A and  3 , when fluid is flowing through the vertical tubular  40  and into the return flow line  60 , the vertical tubular  40  will be full of fluid. The fluid flowing through the vertical tubular  40  creates a hydrostatic pressure that acts downwardly towards the fluid exiting the well bore  14 . The fluid also imparts some friction loss pressure when flowing. By coupling the flow rate measurement device  20  to the vertical tubular  40 , the flow rate measurement device  20  measures the fluid flowing through vertical tubular  40  under hydrostatic pressure (i.e., the hydrostatic pressure of the fluid in the vertical tubular  40  above the transducers  22 ,  26  of the flow rate measurement device  20 ). An advantage to measuring the fluid flow under hydrostatic pressure is that, as known to those skilled in the art, such an arrangement improves the accuracy of and accelerates the response time for kick or loss detection. 
     Kick or loss detection is preferably accomplished by comparing the flow rate of fluid pumped into the well bore  14  via injection line  76  and drill string  30  with the flow rate of fluid exiting from the well bore  14  through the return flow line  60 . The flow rate of fluid pumped into the well bore  14  is typically measured/determined using another (or second) flow rate measurement device  78  on the injection line  76 . Such flow rate measurement device  78  may be selected from any type known to those skilled in the art including, but not limited to, a coriolis flow rate meter, an ultrasonic flow rate meter, a magnetic flow rate meter, and/or a laser-based optical flow rate meter. Alternatively, the strokes of the surface fluid/mud pump  72  as a function of time can be measured and used to compute the flow rate of fluid pumped into the well bore  14 . As previously described, the flow rate measurement device  20  coupled to the substantially vertical tubular  40  is used to measure/determine the flow rate of fluid exiting the well bore  14 . If the well is balanced, the fluid flow into the well bore  14  should be approximately equal to the fluid flow exiting the well bore  14  (or have a difference that is approximately equal to the production rate during underbalanced drilling operations). Therefore, upon comparison, any unexplained deviation or difference between the measured fluid flow rates is an indication that a fluid kick or fluid loss may have occurred. A conventional response to any indication of a fluid kick or fluid loss is to close the BOP  50 , thereby closing the well bore annulus  42  from atmosphere. One or more of the implementations described herein permit corrective action to be taken sooner, thereby reducing the chance of a loss of well control and its potential adverse effects. 
     The Abstract of the disclosure is written solely for providing the United States Patent and Trademark Office and the public at large with a means by which to determine quickly from a cursory inspection the nature and gist of the technical disclosure, and it represents one preferred implementation and is not indicative of the nature of the invention as a whole. 
     While some implementations of the invention have been illustrated in detail, the invention is not limited to the implementations shown; modifications and adaptations of the disclosed implementations may occur to those skilled in the art. Such modifications and adaptations are in the spirit and scope of the invention as set forth in the claims hereinafter: