Patent Publication Number: US-8528660-B2

Title: System and method for safe well control operations

Description:
CROSS REFERENCE TO RELATED APPLICATION 
     This application is based on U.S. provisional patent application No. 61/311,166, filed on Mar. 5, 2010, the priority of which is claimed. 
    
    
     BACKGROUND OF THE INVENTION 
     1. Field of the Invention 
     This invention relates generally to a system and method for the drilling, completion and work-over of oil and/or gas wells. Specifically, the invention relates to the control of oil and/or gas wells during the period when the blow-out preventer (BOP) is closed, or is in the process of being closed, due to events, such as kicks, that occur during drilling, completion, or while working over the well. 
     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 (i.e., earth surface for an on-shore well and water surface for an off-shore 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 pipe. 
     A primary function of the fluid is to maintain a primary barrier inside the well bore to prevent formation fluids from entering the well bore and flowing to surface. A blow-out preventer (BOP), which has a series of valves that may be selectively 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 at a level 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 liquid 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 bore 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) again in fluid volume in the fluid system tanks (“pit volume”). When a kick is detected, or suspected to have entered the well bore, fluid circulation is conventionally halted and the well bore closed in/shut in by closing the BOP. The pressure buildup in the well bore annulus, pit gain and shut in drill pipe and casing pressures are then monitored and measured. Appropriate well-killing calculations may also be performed while the well is closed in. Before resuming operations, a known well-killing procedure may be followed to circulate the kick out of the well bore, circulate an appropriately weighed fluid (“kill fluid”) into the well bore, and ensure that well control has been safely regained. Typically, the intent of the operator while circulating a kick out of a well and circulating the kill fluid is to ensure that another kick does not enter the well. If, however, while performing these tasks another kick enters the well, the entire well bore condition again changes. The operator may subsequently lose control of the well, because the monitored and measured parameters are transient and confusing as a result of the previous kick. Furthermore, it will be more difficult to ensure that the well control procedures were successfully completed and that the operator has effectively regained control of the well bore to permit recommencement of operations. 
     One of the requirements for safely and effectively killing the well, and circulating an appropriate kill fluid, is to hold the pressure inside the well bore as constant as possible, above the formation pore pressure and below the formation fracture pressure. The first task is, therefore, to ensure accurate knowledge of the pore and fracture pressures as a function of depth, and to properly calculate the correct fluid weight to be circulated. If the pressure inside the well bore oscillates too much during the circulation of the kick out of the well bore, then there is high risk that the pressure inside the well bore will fall below the formation pressure and a secondary kick will be taken while the process of controlling the first one is ongoing. Alternatively, if the pressure inside the well bore oscillates and reaches the fracture pressure, fluid losses into the formation are induced. This causes the integrity of the well bore to be severely jeopardized and makes the necessary well control operations much more difficult. As previously stated, such scenarios should be avoided. 
     The two most common methods for circulating the kill fluid and circulating the kick out of the well bore are: the Driller&#39;s method and the Wait and Weight method. The Driller&#39;s method may be utilized when kill weight fluid is not yet available for circulation. In the Driller&#39;s method, the original fluid weight may be used to circulate the influx of formation fluids from the well bore. Thereafter, kill weight mud (“KWM”) may be circulated into the drill pipe and the well bore. Although two circulations may be required to effectuate the Driller&#39;s method, this method may be quicker than the subsequently described variation. In the Wait and Weight or “Engineer&#39;s” method, KWM is prepared and then circulated down the drill string and into the well bore to remove the influx of formation fluids from the well bore and to kill the well, in one circulation. This method may be preferable in order to maintain the lowest casing pressure while circulating the kick from the well bore, thereby minimizing the risk of damaging the casing, fracturing the formation and/or creating an underground blow-out. In either the Driller&#39;s method or the Wait and Weight method, a substantially constant pressure inside the well bore, above the pore pressure and below the fracture pressure, should be maintained. 
     The Driller&#39;s method and the Wait and Weight method are only suitable, however, for use in commonly encountered well control situations. There are several other more complex situations faced while regaining control of the well bore which require a more sophisticated approach. In situations where the drill bit is off bottom, there is no drill string inside the well bore, or the drill string is parted, more complex methods are needed, such as volumetric, dynamic volumetric, or lube and bleed methods, to ensure that control of the well is restored. In some cases, there is no margin to allow circulation of the influx without fracturing the formation. In such cases, the alternative is to bullhead the influx back into the formation and not to circulate the influx out of the well bore. These complex methods are more difficult to implement because several variables must be controlled, and this complexity is often more than the rig crew can handle. Thus, well control experts are frequently moved to the rig site to assist with well control, if these more complex well control methods are employed. 
     In the conventional drilling of a well, the blow-out preventer (BOP) remains open and the return of the fluids from the well is directed through a fluid return line to a shale shaker and fluid system tanks on the surface. Thus, the well is drilled while being open to the atmosphere and without the possibility of applying pressure at surface. If an indication of an influx is detected at anytime, the BOP is closed and a well control procedure is initiated. When a fluid influx occurs it is a sign that the pressure inside the well bore is lower than the formation pressure, and that the fluid weight should be increased to restore a balanced condition. As previously described, there are many different ways of controlling the well after the detection of a fluid influx. The preferred way in which a well is controlled is dependent on a number of factors including, but not limited to, the configuration of the well, the operational condition of the well at the time the detected influx, whether the drill bit is on bottom or off bottom, whether the drill string is parted, and/or whether the drill string is completely out of the well. The Driller&#39;s method and the Wait and Weight method, described above, are two of the most popular ways to control a well after influx detection when the drill bit is on bottom, however, other methods and variations thereof are implemented depending on the particular drilling company. When the BOP is closed, the return of the fluid is diverted to the rig well control choke manifold through a choke line, wherein one or more adjustable chokes control the pressure (i.e., backpressure) in the choke line and in the annulus. 
     Conventional well control procedure involves several steps, which are well known to those skilled in the art: 
     First, the well is shut in by closing the BOP in order to measure the pressures in the annulus and inside the drill string, and thereby provide an indication of the amount of additional pressure required to rebalance the well; 
     Next, the fluid influx is circulated out of the well while controlling the well pressure at the surface appropriately to prevent a second influx from entering the well bore (as previously stated, in some cases there is no margin to allow circulation of the influx without fracturing the formation, which leads to the decision to bullhead the influx back into the formation instead of circulating it out of the well bore); 
     Next, a heavier fluid is circulated through the well to restore the hydrostatically overbalanced condition, which is a required condition for many oil and/or gas well drilling operations; 
     Finally, confirmation is made that the well is hydrostatically overbalanced by checking the pressures in the annulus and inside the drill string so that the BOP can be reopened to resume operations. 
     During execution of the conventional well control procedure, the steps are conducted while relying on pressure readings as measured in the injection line, called standpipe pressure and as measured in the choke line, called casing pressure, and in a few cases, on the volume of fluid in the pits. Relying solely on pressure readings, however, does not allow the driller to completely understand downhole events, such as ascertaining the hydrostatically underbalanced condition based on the time the influx was taken, verifying that an influx indeed entered the well bore or ensuring that the well is under control. Furthermore, using the pit volume as indicator of well condition during a well control method is far from accurate. 
     In addition to well control, the BOP may be closed for other reasons, such as to conduct a leak-off test in order to determine the fracture pressure of the formation. Current systems and methods for determining formation fracture pressure and formation pore pressure, however, are inaccurate. For example, the pore pressure derived from stabilized surface standpipe and casing pressure readings measured after the BOP has been closed is often far from accurate, and in many cases, there is no influx into the well bore. The sole reliance on pressure readings and their misinterpretation leads to this result. Moreover, the use of inaccurately measured fracture and pore pressures can have serious consequences for the economics of the well. For instance, the pore pressure is used to define the new mud/fluid weight required to be circulated through the well after a kick is detected in order to return the well to a hydrostatically overbalanced condition. Thus, if the determined pore pressure is inaccurate due to a lighter fluid presence in the well bore, and not the result of a hydrostatically or dynamically underbalanced situation, the typical procedure is to needlessly introduce heavier weight fluid into the well bore. 
     As stated, the misinterpretation of non-kick events, based solely on pressure readings or pit volume measurements, can lead to false alarms of kicks. An action that may be taken in response to these false alarms is the circulation of fluid with an unnecessary increase in fluid weight, which can cause subsequent operational problems, such as a loss of circulation, a stuck pipe and/or a low rate of well bore penetration. For instance, the fluid weight used to kill the well is selected to be much higher than needed, thereby causing severe problems when operations are resumed. In certain situations, this results in the well being prematurely abandoned. Even if the well is not abandoned, the huge amount of resources wasted by the lack of accuracy and controllability of current well control methods is costly. 
     Furthermore, the misinterpretation of downhole events can, in many cases, lead to the taking of secondary influxes while attempting to control the first kick. This can and often does lead to well blow-outs. For example, there were 28 out-of-control blow-outs alone in the United States in 2008. Brian Kraus, D RILLING  C ONTRACTOR , July/August 2009, at 100-01. Most of these blow-outs caused property damage, some caused environmental damage, and at least one blow-out caused a busy highway to be diverted because the fire at the drilling site was too close. Another reason that many kicks can get out of control and turn into devastating blow-outs is the lack of experience and knowledge of the personnel at the rig site concerning such events. In many instances, the on-site personnel are unable to interpret the fluid influx situation, perform the necessary calculations, and/or properly implement the required well control procedures. 
     Improving the safety and controllability of well control operations after the BOP has been closed is a major concern on the majority of worldwide drilling rigs. In an attempt to improve well control procedures and the overall safety of conventional operations, several systems and methods have recently been developed which focus on improved kick detection, while others concentrate on controlling pressures more accurately during circulation of the kick and displacement of the kill mud. Most of these systems and methods, however, rely solely on pressure monitoring and measurement to regain control of the well after the BOP has been closed. While pressure measurements can, in some limited cases, provide a good indication of the events inside the well bore with the BOP closed, pressure measurements alone do not provide a full and complete understanding of what events are occurring downhole. Likewise, pressure measurements alone do not ensure that false indications of kicks are prevented or permit the accurate assessment of fracture and pore pressures. Considering the problems associated with current strategies of well control when the BOP is closed, an improved well control system and method provides several advantages. This application is based on U.S. provisional patent application No. 61/311,166, filed on Mar. 5, 2010, which is incorporated herein by reference. 
     3. Identification of Objects of the Invention 
     An object of the invention is to accomplish one or more of the following: 
     Provide a system and method to permit the safe cessation of drilling operations in response to an indicated or suspected onset of a kick event; 
     Provide a system and method for controlling oil and/or gas wells after closing the blow-out preventer; 
     Provide a system and method for more accurately determining the fracture and pore pressures of the formation; 
     Provide a system and method for confirming if the fluid weight is insufficient to hydrostatically balance exposed formations, and if confirmed, determining an accurate value for the fluid weight increase required to restore hydrostatic balance or overbalance; 
     Provide a system and method for controlling the pressure at any specific, selected depth inside the well bore between specified limits, such as between the formation fracture pressure and the formation pore pressure; 
     Provide a system and method for maintaining control of oil and/or gas wells such that drilling and other operations on these wells may be conducted in sensitive formations; 
     Provide a system and method which reduces the risk of well blow-outs, which could result in life and/or properties losses; 
     Provide a system and method for enhancing hands-on training and competence assessment using the well control equipment of the rig; 
     Provide a system and method for controlling an oil and/or gas well such that experts not located at the rig site may be involved earlier in well control procedures; and 
     Provide a system and method for the collection, interpretation and display of well control-related data for timely and effective participation in well control procedures by experts located remotely from the rig. 
     Other objects, features, and advantages of the invention will be apparent from the following specification and drawings to one skilled in the art. 
     SUMMARY OF THE INVENTION 
     One or more of the objects identified above, along with other features and advantages of the invention are incorporated in a system and method for monitoring and controlling an oil and/or gas well just prior to and/or after closure of a conventional blow-out preventer (BOP) associated with the well. In normal operations in which the BOP is closed, or in operations in which the BOP is closed in response to any suspicion, sign or indication of a fluid influx, a preferred implementation of the system and method of the invention (1) measures and monitors both the pressures and flow rates in and out of the well bore from the time the BOP is closed and operation is interrupted until the BOP is reopened to resume the operations, (2) measures and monitors both the pressure and flow rates in and out of the well so as to provide a more accurate determination of the pore and fracture pressures, which is used to safely regain well control before resuming operations, and/or (3) uses the measured pressure and flow rate data to perform well control operations with greater accuracy, controllability and confidence. 
     In a preferred implementation of the invention, a fluid flow rate measurement device, such as a fluid volume or mass flow rate meter, is disposed within the choke line between the rig choke manifold and the mud gas separator to measure and monitor the flow rate of fluid out of the well bore through the choke line during the period when the conventional BOP is closed for any specific operation or in response to any sign or indication of a fluid influx event. A fluid flow measurement device is also disposed within the fluid injection line, to measure and monitor flow rate of fluid into the well bore at all times. The standpipe and casing pressures are also measured and monitored by measuring and monitoring the pressures within the fluid injection line and the choke line, respectively, using pressure measurement devices. All relevant data are preferably acquired and transmitted to a central control unit before, during, and after the conventional BOP has been closed for any specific operation or in response to a suspected fluid influx event. This data is preferably stored at the rig site but is available in real time to experts located away from the well. Thus, relevant well control data can be made available to well control experts during well control events prior to their arrival on site. 
     The measured fluid flow rates and fluid pressures permit the suspected fluid influx event to be confirmed and the pore and fracture pressures of the formation to be determined with greater accuracy, as further described herein. Based on the accurately determined pore and fracture pressures, the central control unit controls a flow control device disposed in the choke line to apply backpressure on the well so as to maintain the pressure inside the well bore between specified or conditional limits including, but not limited to, the pore pressure and the fracture pressure during the entire well control procedure. Confirming the suspected fluid influx and determining an accurate pore pressure also permit the correct fluid weight to be determined so as to restore the overbalanced condition for continued operation. Furthermore, based on the measured flow rates and/or pressures, one or more of the standpipe pressure, casing pressure, and the pressure at a given point inside the well bore may be controlled manually or automatically to facilitate well control operations. Such well control operations may include circulating the fluid influx out of the well bore and/or injecting a heavier fluid into the well bore, thereby displacing lighter fluid from the well bore, or bullheading the fluid influx back into the formation. The system also facilitates hands-on training for the rig crew as well as competence assessments of the rig crew to be performed using the actual rig well control equipment. 
    
    
     
       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  is a schematic view of a preferred implementation of the system in which fluid flow rate measurement devices are disposed in a fluid injection line and in a choke line downstream of a flow control device to measure fluid flow rate into and out of the well bore while a conventional blow-out preventer is closed; 
         FIG. 2  is a schematic view of an alternative preferred implementation of the system shown in  FIG. 1  in which the fluid flow rate measurement device disposed in the choke line is positioned upstream of the flow control device to measure fluid flow rate out of the well bore while the conventional blow-out preventer is closed; 
         FIG. 3  is a schematic view of an alternative preferred implementation of the system shown in  FIG. 1  in which flow rate measurement devices are disposed in the choke line both upstream and downstream of the flow control device to measure flow rate out of the well bore and pressure measurement devices are disposed in the choke line both upstream and downstream of the flow control device to measure pressure in the choke line; 
         FIG. 4  is a schematic view of an alternative preferred implementation of the system shown in  FIG. 1  in which fluid flow rate and pressure measurement devices are disposed in each of the kill line and the fluid injection line (and in the choke line) to measure fluid flow rate and pressure into (and out of) the well bore while the conventional blow-out preventer is closed; 
         FIG. 5  is an illustration showing that measured and/or calculated data and commands may be transmitted between the central control unit of the rig and remote user interface devices; 
         FIG. 6  is a flowchart showing the general procedure for calculating the hydrostatic pressure of well fluid at a specified well depth; and 
         FIG. 7  is a flowchart showing the general procedure for calculating the friction loss/pressure of fluid circulating through the well bore annulus. 
     
    
    
     DESCRIPTION OF THE PREFERRED IMPLEMENTATIONS OF THE INVENTION 
     A preferred implementation of the invention alleviates one or more of the deficiencies of the prior art and incorporates at least one of the objects previously identified. As shown in  FIG. 1 , a preferred implementation of the drilling system  10  includes a tubular drill string  20  suspended from a drilling rig  90 . The drill string  20  has a lower end  22  which extends downwardly through a BOP stack  30  and into borehole/well bore  12 . A drill bit  26  is attached to the lower end  22  of drill string  20 . A drill string driver or turning device  38 , comprising either a rotary drive system (not shown) or a top drive system  38 , is operatively coupled to an upper end  24  of the drill string  20  for turning or rotating the drill string  20  along with drill bit  26  in the borehole  12 . A conventional surface fluid/mud pump  40  pumps fluid from a surface fluid reservoir  42  through a fluid injection line  48 , through the upper end  24  of drill string  20 , down the interior of drill string  20 , through drill bit  26  and into a borehole annulus  18 . The borehole annulus  18  is created through the action of turning drill string  20  and attached drill bit  26  in borehole  12  and is defined as the annular space between the interior/inner wall or diameter of the borehole  12  and the exterior/outer surface or diameter of the drill string  20 . 
     A conventional BOP stack  30  is coupled to well casing  16  via a wellhead connector  28 . Typically, the BOP stack  30  includes one or more pipe rams, one or more shear rams, and one or more annular BOPs  32 . When drilling is stopped (i.e., the drill string driver  38  is no longer turning the drill string  20  and drill bit  26 ), the one or more conventional annular BOPs  32  can be closed to effectively close the borehole annulus  18 /wellbore  12  from the atmosphere. A kill line  54  couples between the fluid injection line  48  via a standpipe manifold  84  and the conventional BOP stack  30  via kill line valve  34 . The kill line  54  permits fluid communication between the conventional surface fluid/mud pump  40  and the well bore annulus  18  when kill line valve  34  and valving in the standpipe manifold  84  are opened. Thus, while the BOP  32  is closed, conventional surface fluid/mud pump  40  may be used to pump fluid from reservoir  42  into the borehole annulus  18  via fluid injection line  48 , standpipe manifold  84 , kill line  54 , kill line valve  34 , and BOP stack  30 . Alternatively, while the BOP  32  is closed, the conventional surface fluid/mud pump  40  may be used to pump fluid from reservoir  42  into the borehole annulus  18  via the fluid injection line  48 , standpipe manifold  84 , drill string  20  and drill bit  26 . 
     A choke line  56  couples between the conventional BOP stack  30  via choke line valve  36  and the surface fluid reservoir  42  via rig well control choke manifold  86 . The rig well control choke manifold  86  includes a flow control device  70 , such as a choke, disposed in the choke line  56 . The flow control device  70  controls flow rate through the choke line  56  thereby controlling pressure upstream of the flow control device  70  and thus, backpressure to the well bore annulus  18  while the BOP  32  is closed. A mud-gas separator  46  and a shale shaker  44  are also preferably fluidly coupled to the choke line  56  and are positioned between the flow control device  70  and surface fluid reservoir  42 . Thus, when choke line valve  36  and flow control device  70  are opened after the BOP  32  is closed, fluid from the borehole annulus  18  is permitted to flow up through BOP stack  30 , through choke line valve  36 , through choke line  56 , through rig well control choke manifold  86 , through mud-gas separator  46 , through shale shaker  44  and into surface fluid reservoir  42 . 
     Upon detection of a fluid influx, drilling is ceased (i.e., drill string driver  38  stops rotating the drill string  20  and drill bit  26 ) and the one or more conventional BOPs  32  are closed (i.e., the borehole  12  and borehole annulus  18  are closed to atmosphere). Depending on the specific well control procedure adopted by the drilling company and the well bore geometry/configuration, fluid may be pumped into the well bore  12  solely through the drill string  20 , solely through the kill line  54 , or through both the drill string  20  and the kill line  54 . On some rigs with appropriate lines and valving (not shown), fluid may be injected into the annulus  18  using the choke line  56 . 
     If fluid is to be pumped solely through kill line  54 , then the kill line valve  34  is opened and valving in the standpipe manifold  84  is configured to fluidly couple the fluid injection line  48  and the kill line  54 , thereby permitting pump  40  to pump fluid directly into the well bore annulus  18 . The valving in the standpipe manifold  84  is further configured to stop flow between the fluid injection line  48  and the drill string  20 . In this configuration, the fluid injection line  48 , the standpipe manifold  84 , the kill line  54 , the BOP stack  30 , the well bore annulus  18 , and the choke line  56  define a fluid pathway through the borehole  12 . If fluid is to be pumped solely through the drill string  20 , then the kill line valve  34  is closed and the valving in the standpipe manifold  84  is configured to permit flow between the fluid injection line  48  and the upper end  24  of the drill string  20  and to stop flow into the kill line  54 . In this configuration, the standpipe manifold  84 , the fluid injection line  48 , the drill string  20 , the well bore annulus  18 , and the choke line  56  define a fluid pathway through the borehole  12 . 
     If both the kill line  54  and the drill string  20  are to be used to pump fluid into the well bore annulus  18 , then the kill line valve  34  is opened and the valving in the standpipe manifold  84  is configured to permit fluid flow from the fluid injection line  48  into both the kill line  54  and the upper end  24  of the drill string  20 . 
     Typically, after an influx is detected, the BOP  32  is closed and the standpipe and casing pressures are measured to confirm and assess the severity of the influx and to determine the increase in fluid weight needed for circulation through the well bore  12 . A greater weight fluid is pumped through the drill string  20  and/or kill line  54  in order to increase the fluid weight within the borehole annulus  18 . The increased weight of the fluid increases the static pressure exerted by the fluid within the well bore  12 , which prevents additional influx from entering into the well bore annulus  18  from the formation  14 . 
     In order to circulate heavier fluid through the well bore  12  and any fluid influx out of the well bore  12  while the conventional BOP  32  is closed, choke line valve  36  is opened to permit such fluid to flow under pressure up from the borehole annulus  18  through the choke line valve  36 , into choke line  56 , through flow control device  70  and back to the surface fluid reservoir  42 . The flow control device  70  controls the fluid flow rate therethrough, and thus backpressure on the well bore  12  and well bore annulus  18 , by preferably controlling or adjusting the size of an orifice (not shown) through which fluid is permitted to flow through choke line  56 . A larger-sized orifice equates to a greater through flow and a decreased backpressure while a smaller-sized orifice equates to a lesser through flow and a greater backpressure. The use of flow control devices to restrict flow through a pipe or flow line is well known to those skilled in the art. Such flow control devices include, but are not limited to, chokes, size-adjustable orifices, and various valves. 
     A central control unit  80  is preferably arranged and designed to receive measurement signals from a number of measurement devices, to use the received signals to generate control signals to control the flow control device  70  and flow therethrough, and to transmit these control signals to the flow control device  70 , thereby controlling the flow through choke line  56 . Central control unit  80  may be any type of computing device preferably having a user interface and software  81  installed therein, such as a computer, that is capable of but not limited to, performing one or more of the following tasks: receiving signals from a variety of measurement devices, converting the received signals to a form exploitable for computing and/or monitoring, using the converted signals for computing and/or monitoring desired parameters, generating signals representative of computed parameters, and transmitting generated signals. With respect to the flow control device  70 , the central control unit  80  is preferably arranged and designed to transmit generated control signals wirelessly or via a wired link (shown by the dotted lines on  FIGS. 1-4 ) to the flow control device  70 . The control signals received by the flow control device  70  from the central control unit  80  cause the orifice of the flow control device  70  to either fully open, fully close, or to open or close to some position therein between. While the flow control device  70  may be controlled automatically by the central control unit  80  as described above, the flow control device  70  may also be manually controlled by an operator to adjust the fluid flow ate or pressure through the flow control device  70  at the discretion of the operator. 
     As shown in  FIG. 1 , an outlet fluid flow rate measurement device  50 , such as a volume or mass flow rate meter, is preferably used to measure the fluid flow rate out of the well bore  12  while the conventional blow-out preventer  32  is closed. Such fluid flow rate measurement device  50  is preferably a coriolis flow rate meter, an ultrasonic flow rate meter, a magnetic flow rate meter or a laser-based optical flow rate meter, but may be any suitable type known to those skilled in the art. The outlet fluid flow rate measurement device  50  is arranged and designed to generate a signal F out (t), which is representative of actual flow rate out of the well bore  12  through the choke line  56  as a function of time (t). The outlet fluid flow rate measurement device  50  transmits the signal F out (t), preferably in real time, to the central control unit  80 , which receives and processes the signal. The outlet fluid flow rate measurement device  50  is preferably disposed in the choke line  56  between the flow control device  70  and the rig mud gas separator  46 . However, as shown in  FIG. 2 , the outlet fluid flow rate measurement device  50  may alternatively be disposed in the choke line  56  upstream of the flow control device  70  (i.e., between the well bore annulus  18  and the flow control device  70 ). 
     In an alternative preferred implementation, shown in  FIG. 3 , the outlet fluid flow rate measurement device  50  is disposed in the choke line  56  downstream of the flow control device  70  (i.e., between the flow control device  70  and the mud gas separator  46 ) and a second outlet fluid flow rate measurement device  58  is disposed in the choke line  56  upstream of the flow control device  70 . The outlet fluid flow rate measurement devices  50 ,  58  are similarly arranged to generate a signal F out (t) and a signal F out2 (t), respectively, which are representative of actual flow rates out of the well bore  12  through the choke line  56  at the respective measurement device  50 ,  58  as a function of time (t). The outlet fluid flow rate measurement devices  50 ,  58  transmit their respective signal F out (t) and F out2 (t), preferably in real time, to the central control unit  80 , which receives and processes the signal. The fluid upstream of the flow control device  70  may experience a higher pressure than the fluid downstream of the flow control device  70 . Therefore, the use of first  50  and second  58  outlet fluid flow rate measurement devices provides an analysis of fluid compressibility and a better understanding of fluid volume expansion as a function of pressure, both of which permit a more accurate measurement of fluid flow rate out of the bore hole  12 . The effects of turbulence can also be determined and thus controlled with the use of two outlet flow rate measurement devices  50 ,  58  arranged in series. 
     Returning to  FIG. 1 , an inlet fluid flow rate measurement device  52 , such as a volume or mass flow rate meter is preferably used to measure the fluid flow rate into the well bore  12  while the conventional blow-out preventer  32  is closed. The inlet fluid flow rate measurement device  52  is preferably a coriolis flow rate meter, an ultrasonic flow rate meter, a magnetic flow rate meter or a laser-based optical flow rate meter, but may be any suitable type known to those skilled in the art. Alternatively, even a simple device to measure the strokes of the conventional surface fluid/mud pump  40  as a function of time can serve as an inlet fluid flow rate measurement device. The inlet fluid flow rate measurement device  52  is arranged and designed to generate a signal F in (t), which is representative of actual fluid flow rate through the fluid injection line  48  (i.e., an inlet line coupled between pump  40  and drill string  20 ) as a function of time (t). The inlet fluid flow rate measurement device  52  transmits the signal F in (t) in real time to the central control unit  80 , which receives and processes the signal. The inlet fluid flow rate measurement device  52  is preferably disposed in the fluid injection line  48  between the conventional surface fluid/mud pump  40  and the standpipe manifold  84 , such that the inlet fluid flow rate measurement device  52  measures fluid flow rate into the borehole  12  regardless of whether fluid flow is through the drill string  20  or through the kill line  54 . 
     Alternatively, as shown in  FIG. 4 , the inlet fluid flow rate measurement device  52  is disposed in the fluid injection line  48  between the conventional surface fluid/mud pump  40  and the standpipe manifold  84  and a second inlet fluid flow rate measurement device  60  is disposed in the kill line  54 . The inlet fluid flow rate measurement device  52  is arranged and designed to generate a signal F in (t), which is representative of actual flow rate into the well bore  12  through the injection line  48  as a function of time (t). The second inlet fluid flow rate measurement device  60  is arranged and designed to generate a signal F in2 (t), which is representative of actual flow rate into the well bore  12  through the kill line  54  (i.e., an inlet line coupled between standpipe manifold  84  and well bore annulus  18 ) as a function of time (t). The inlet fluid flow rate measurement devices  52 ,  60  transmit their respective signal F in (t) and F in2 (t), preferably in real time, to the central control unit  80 , which receives and processes the signal. Based on the signals received, the central control unit  80  calculates the total flow rate of fluid into the well bore  12  regardless of whether the fluid flow is through the drill string  20  alone, the kill line  54  alone, or a combination of both. 
     As previously stated, the inlet  52 ,  60  and outlet  50 ,  58  flow rate measurement devices preferably send flow rate signals in real time to the central control unit  80 , thereby permitting the fluid flow rate into and out of the well bore  12  to be continuously monitored via the central control unit  80  while the conventional BOP  32  is closed. Fluid flow from the borehole  12  through the choke line  56  is controlled manually, or automatically by the central control unit  80 , via flow control device  70 . Fluid flow into the well bore annulus  18  via the fluid injection line  48  and/or the kill line  54  may also be controlled by the central control unit  80  via manipulation of the valving in the standpipe manifold  84  to select a particular fluid flow pathway, to reduce flow through a particular fluid flow pathway, or to stop flow through a particular line. Alternatively, the central control unit  80  may automatically control, or an operator may manually control, the fluid flow into the well bore annulus  18  by increasing, decreasing, or stopping the operation of conventional surface fluid/mud pump  40 . 
     As shown in  FIG. 1 , an inlet pressure measurement device  62 , such as a pressure sensor, is disposed in the fluid injection line  48  in the proximity of the standpipe manifold  84 . However, the inlet pressure sensor  62  could alternatively be disposed elsewhere in the fluid injection line  48 , but preferably in close proximity to the inlet flow rate measurement device  52 . The inlet pressure measurement device  62  is arranged and designed to generate signal P in (t), which is representative of the pressure in the fluid injection line  48  (i.e., the standpipe pressure) as a function of time (t). The inlet pressure measurement device  62  transmits signal P in (t), preferably in real time, to the central control unit  80 , which receives and processes the signal. As shown in  FIG. 4 , the inlet pressure measurement device  62  is disposed in the fluid injection line  48  as described above, however, a second inlet pressure measurement device  66  is associated with the second inlet flow rate measurement device  60  positioned in the kill line  54 . Thus, an inlet pressure measurement device is preferably associated with each of a plurality of inlet flow rate measurement devices. The second inlet pressure measurement device  66  is arranged and designed to generate a signal P in2 (t), which is representative of the pressure in the kill line  54  as a function of time (t). The inlet pressure measurement devices  62 ,  66  transmit their respective signals P in (t) and P in2 (t), preferably in real time, to the central control unit  80 , which receives and processes the signals. 
     Returning to  FIG. 1 , an outlet pressure measurement device  64 , such as a pressure sensor, is disposed in the choke line  56  preferably in proximity to the rig well control choke manifold  86  and upstream of the flow control device  70 . The outlet pressure measurement device  64  is arranged and designed to generate a signal P out (t), which is representative of the pressure in the choke line  56  as a function of time (t). When the outlet pressure sensor  64  is disposed upstream of the flow control device  70 , the pressure sensor measures pressure representative of the casing pressure (or the choke manifold pressure on floating rigs). The outlet pressure measurement device  64  transmits the signal P out (t) in real time to the central control unit  80 , which receives and processes the signal. 
     In an alternative implementation, as shown in  FIG. 3 , the outlet pressure sensor  64  is disposed in the proximity of the rig well control choke manifold  86  as described above and a second outlet pressure sensor  68  is disposed downstream of the flow control device  70  in closer proximity to the outlet flow rate measurement device  50 . The outlet pressure measurement device  64  is arranged and designed to generate a signal P out (t), which is representative of the pressure in the choke line  56  (i.e., the casing pressure) upstream of the flow control device  70  as a function of time (t). The second outlet pressure sensor  68  is arranged and designed to generate a signal P out2 (t), which is representative of the pressure in the choke line  56  downstream of the flow control device  70 . The outlet pressure measurement devices  64 ,  68  transmit their respective signals P out (t) and P out2 (t), preferably in real time, to the central control unit  80 , which receives and processes the signals. 
     Using this system, the operator preferably monitors the flow rates in addition to the pressure measurements to confirm that the pressure inside the well bore  12  is maintained between acceptable high and low pressure limits, such as between the pore and fracture pressures of formation  14 . This method significantly increases the well control accuracy when compared to methods using a conventional system, in which the operator monitors only the pressure measurements. In addition to confirming that the pressure inside the well bore  12  is between specific limits, the system disclosed herein also controls the pressure to be between such specific limits. This, too, contributes to an increased well control accuracy. 
     As shown in  FIGS. 1-4 , an inlet temperature measurement device  76  is disposed in the fluid injection line  48 , preferably upstream of the standpipe manifold  84 , and an outlet temperature measurement device  78  is disposed in the choke line  56 , preferably downstream of the rig well control choke manifold  86 , to generate signals T in (t) and T out (t), respectively. The signals, T in (t) and T out (t), from these optional temperature measurement devices  76 ,  78  are transmitted to the central control unit  80 , which is arranged and designed to receive them. The temperature measurement devices  76 ,  78  may be any device known to those of skill in the art to measure temperature including, but not limited to, thermometers and thermocouples. As is well known in the art, such temperature data may be used to adjust the calculation of fluid properties that are a function of pressure and temperature, such as density and other rheological properties. The fluid property calculations are preferably performed in response to any measured, real time temperature variations of the fluid, thereby improving the accuracy of the overall system  10 . 
     The central control unit  80  is arranged and designed to receive signals generated by the fluid flow rate measurement devices  50 ,  52 ,  58 ,  60 , pressure measurement devices  62 ,  64 ,  66 ,  68 , and the temperature measurement devices  76 ,  78 . As shown in  FIG. 1 , the central control unit  80  receives these signals via wired links (shown by dotted lines) coupled between the respective measurement devices  50 ,  52 ,  62 ,  64 ,  76 ,  78  and the central control unit  80 .  FIG. 3  additionally shows that the central control unit  80  receives signals generated by the fluid flow rate measurement device  58  and the pressure measurement device  68 . Likewise,  FIG. 4  additionally shows that the central control unit  80  receives signals generated by the fluid flow rate measurement device  60  and the pressure measurement device  66 . Alternatively, each of the measurement devices may wireless transmit generated signals in any manner known to those skilled in the art, such as by cellular, infrared, or acoustic transmission. In such wireless implementation, the central control unit  80  is arranged and designed to receive and interpret such wireless transmissions. 
     As generally shown in  FIG. 5 , rig data from the central control unit  80  including, but not limited to, received signals (e.g., flow rate, pressure and temperature measurements), computed parameters (e.g., fracture and pore pressures), control signals (e.g., to control the flow through choke line  56  via flow control device  70 ), etc., may itself be transmitted remotely by establishing a communication link, e.g., via satellite  97 , wired connection, and/or wireless connection, etc., between the central control unit  80  of rig  90  and a remote unit, such as another computer  91 ,  99 , storage device  93  (e.g., a server), and/or to a mobile device  95  (e.g., a smart phone). In this way, rig data may be accessed in real time by personnel located remotely from the rig  90 . This permits well control experts to interact with and/or guide the rig crew stationed on-site both before and after the conventional BOP  32  has been closed due to detection of the fluid influx event, thereby assisting with the interpretation of the data and directing the best way to maintain or regain control of the well  12 . Those skilled in the art will readily recognize that well control experts, while monitoring and/or guiding on-site personnel in the correct well control procedures, may transmit commands (e.g., control signals) to the central control unit  80  and/or to other system components (e.g., flow control device  70 , pump  40 , etc.), which are responsive to such commands, to regain control of the well. Such remotely transmitted commands may be in conjunction with or may override the actions of the on-site personnel in the well control operations. In an alternative implementation, the flow rate, pressure and temperature signals transmitted by the various measurement devices  50 ,  52 ,  58 ,  60 ,  62 ,  64 ,  66 ,  68 ,  76 ,  78  may be transmitted directly to a remotely located computer  91 ,  93 ,  99  or to mobile devices  95 , such as smart phones, thereby bypassing any central control unit  80 . In such implementation, the remotely located well control experts send commands directly to the flow control device  70 , pump  40 , and other equipment (e.g., choke line valve  36 , kill line valve  34 , etc.) to control the well. 
     As described, the central control unit  80  is arranged and designed to receive measured signals, including signals T in (t), T out (t), P in (t), P out (t), F in (t), and F out (t), and as applicable, signals P in2 (t), P out2 (t), F in2 (t), and F out2 (t). Additional parameters, including but not limited to, well bore depth, bit depth (if drilling) or string configuration (if conducting a completion, work-over or intervention), mud properties (i.e., density and rheology) and/or well bore geometry (inclination and direction) are also preferably measured and received by, or inputted by personnel into, the central control unit  80 , which uses the data via software  81  (discussed hereinafter) to completely and accurately interpret the state of the well  12  and to assess of the best course of action to regain control of the well  12  before resuming operations. Alternatively, one or more of these parameters may be calculated by software  81  using any data that is available to the central control unit  80 . 
     The central control unit  80  determines, preferably in real time, the annulus pressure at any desired, specific depth within the well bore  12 . Using at least received signals P out (t) and F out (t), the central control unit  80  generates signal P ann (t), which is representative of pressure at a specified depth inside the well bore annulus  18  as a function of time (t). Software  81 , installed in the central control unit  80 , is used by the central control unit  80  to compute the annulus pressure signal, P ann (t), as a function of time (t). The annulus pressure signal, P ann (t), is determined by adding the hydrostatic pressure of the fluid/mud within the well bore annulus  18 , the friction pressure generated in the well bore annulus  18  and choke line  56  by any fluid in circulation (i.e., a function of signal F out (t)), and the outlet pressure, P out (t), as preferably measured by the outlet pressure measurement device  64 . 
     The software  81  calculates the hydrostatic pressure based on a number of parameters including, but not limited to, the density of the fluid in the well bore  12  and the depth at which the hydrostatic pressure is to be determined.  FIG. 6  provides a simple flowchart showing how the hydrostatic pressure may be calculated. Software  81  also calculates the friction loss in the annulus  18  generated by any circulating fluid based on a number of parameters including, but not limited to, the velocity of the fluid flow (i.e., a function of signal F out (t)), density and rheological parameters of the fluid flow, and the geometry of the annulus  18  and choke line  56 .  FIG. 7  provides a simple flowchart showing how the annular friction loss/pressure may be calculated. Software  81  also includes the necessary correlations to adjust the calculation of fluid properties in response to any temperature variations of the fluid, as measured and transmitted, preferably in real time, by the temperature measurement devices  76 ,  78  to the central control unit  80 . Other parameters, including but not limited to, the flow rate F in (t)/F in2 (t) into the well bore  12 , the inlet pressure P in (t)/P in2 (t), the depth of the well bore  12 , and the density of the fluid/mud pumped into the well bore  12  may also be employed by software  81  in computing the signal P ann (t). 
     Software  81  preferably calculates the hydrostatic pressure and friction losses based on hydraulic equations developed over the past several decades, which are well known to those skilled in the art. Examples of such hydraulic equations traditionally used in oil and gas operations to determine the pressure at any depth in the well bore  12  may be found in, for example, A DAM  T. B OURGOYNE, ET AL ., A PPLIED  D RILLING  E NGINEERING  113-189 (SPE Textbook Series 1986), which is incorporated herein by reference. 
     The following is an example of how the annulus pressure at a specified well depth may be calculated by software  81  using well known hydraulic equations and typically available rig data. This example is provided by way of illustration only and is not intended to limit the scope of the system or method of the invention in any way. 
     Example 
     The annulus pressure at a well bore depth of 10,000 feet in the well bore annulus between a 3 inch ID pipe and 5 inch ID pipe is to be determined. A Newtonian fluid having a density of 9.0 pounds per gallon is being circulated through the well bore at a flow rate of 100 gallons per minute. The backpressure being applied to the well bore annulus is 200 psi, as measured by the outlet pressure measurement device. The Θ 300  rheological parameter of the fluid is 30 (i.e., μ=30 cp; the viscosity in centipoise). As previously discussed, the annulus pressure is determined by adding the hydrostatic pressure of the fluid/mud within the well bore annulus, the friction loss/pressure generated in the well bore annulus, and choke line if applicable, by any fluid in circulation, and the outlet pressure (i.e., backpressure applied to the well bore). The hydrostatic component of the annulus pressure is determined as the product of the equation, 0.052*(depth)*(density), which based on the above data, equals 4,680 psi. The friction loss component of the annulus pressure requires the determination of the fluid mean velocity, the turbulence criteria, and the frictional pressure loss per foot. Based on the above data, the fluid mean velocity in the annulus equals 2.55, which is the product of the equation, [(flow rate)]/[2.448*(d 2   2 −d 1   2 )], where d 2  is the inner diameter and d 1  is the outer diameter. The turbulence criteria is determined from the Reynolds number, N Re , which for flow through an annulus is the product of the equation, [757*density*fluid mean velocity*(d 2 −d 1 )]/[μ]. Based on the above data, the Reynolds number is 1,158, which is representative of laminar flow (i.e., N Re  less than 2,100). The frictional loss per foot is determined using the laminar flow equation, dP/dL=[μ*(fluid mean velocity)]/[1000*(d 2 −d 1 ) 2 ]. Thus, the laminar flow frictional loss per foot, dP/dL, is equal to 0.019 psi/ft. The total laminar flow frictional loss for the 10,000 foot well depth is simply the product of 0.019 psi/ft*10,000 ft, or 191.25 psi. Finally, the backpressure being applied to the well bore annulus is 200 psi, as directly measured by the outlet pressure measurement device. The annulus pressure is determined by summing the hydrostatic component, the frictional loss component and the backpressure component, i.e., 4,680+191+200. Thus, based on the given data, the annulus pressure at a well depth of 10,000 feet is equal to 5,071 psi. 
     The formation fracture pressure and the formation pore pressure may be pre-determined or estimated boundary values that are manual inputs to the software  81  of the central control unit  80 . More preferably, the central control unit  80  uses the flow rate, pressure, and temperature signals received from the respective measurement devices to determine an accurate pore pressure and fracture pressure of the formation  14 . The formation pore pressure is determined after a fluid influx from the formation  14  into the well bore annulus  18  is detected/suspected and after the conventional BOP  32  is closed. As hereinafter described in greater detail, the pore pressure is determined by reducing in stages the backpressure, initially applied to stop the influx after the BOP  32  is closed, until an influx is detected by monitoring flow rates into and out of the well bore  12 . 
     The fracture pressure of the formation  14  is preferably determined through a “leak-off test” before starting operations or at any time after an operation is started. While drilling, a “leak-off test” is performed for purposes of determining the fracture initiation pressure for the next segment of the well bore  12  to be drilled. In a typical “leak-off test,” the well bore annulus  18  is sealed off or closed from atmosphere by closing a conventional BOP  32  and by fully closing the choke  70  disposed in the rig well control choke manifold  86 . Fluid/mud is introduced into the borehole  12  at a relatively slow and constant volumetric rate through the fluid injection line  48  and the central passageway of the drill string  20  so that the fluid/mud exits the drill string  20  through the drill bit  26  and enters the well bore annulus  18 , which is sealed off by the closed choke  70  at the surface. As this flow into the well bore  12  continues, the pressure in the annulus  18  increases linearly until such time that the formation  14  starts to absorb fluid. At this point, a change in the slope of the pressure curve versus volume injected occurs. Many drilling companies consider this point to represent the leak-off or fracture pressure of the open hole section  12 . While a determination of the fracture pressure would appear straight forward, there are several additional methods of conducting a leak-off test, and a standard method may not be used even within the same drilling company. This variation in procedures and ways of interpreting when the fluid starts to leak to the formation  14  is one of the causes of well problems and non-productive time, each resulting in a significant waste of resources. 
     Using system  10  with the BOP  32  closed, the leak-off test is preferably conducted using a constant injection flow rate through the drill string  20  with the return flow up the well annulus  18  and through the choke line  56  with the choke  70  fully open. The casing pressure (i.e., the backpressure applied to the borehole annulus  18 ) is increased slowly and in stages (e.g., incrementally) by closing the choke  70  accordingly while monitoring the fluid flow rate out of the well annulus  18  via at least one of outlet fluid flow rate measurement devices  50 ,  58 . The casing pressure is increased slowly, because a more accurate determination of the fracture pressure is obtained when smaller step changes in casing pressure are made during the leak-off test. With the increase in pressure, the flow rate out of the well annulus  18  is initially reduced due to the compressibility of the system. However, if there are no fluid losses to the formation  14 , then after the system reaches steady state, the fluid flow rate out of the well bore annulus  18  through the choke line  56  will equilibrate to the fluid flow rate into the well bore annulus  18  through the drill string  20  (or kill line  54 ). An additional increase in casing pressure is effected by closing the choke  70  slightly while monitoring fluid flow rate into and out of the well bore  12 . 
     As described above, the software  81  of the central control unit  80  calculates the annulus pressure signal, P ann (t), at a specified well depth as a function of time (t). The formation fracture pressure is simply the annulus pressure, P ann (t), at the depth of the fluid loss at a time, t frac , when the flow rate out of the well bore annulus  18  first starts/begins to no longer equal or approximate the flow rate into the well bore  12 , thereby maintaining a steady state loss of fluid into the well bore  12  (i.e., when flow rate into the well bore  12 , as represented by signal F in (t), first becomes consistently greater than flow rate out of the well bore  12 , as represented by signal F out (t)). Thus, the formation fracture pressure, like the annulus pressure, is a function of the hydrostatic pressure, the casing pressure being applied as preferably measured by the outlet pressure measurement device  64  (i.e., signal P out (t)) and the friction loss in the well bore annulus  18  and choke line  56  generated by the circulating fluid (i.e., a function of signal F out (t)), as preferably estimated by the hydraulic model incorporated into software  81 . Because the fluid flow rate used in the leak-off test is low, the corresponding friction loss in the annulus  18  and choke line  56  generated by the circulating fluid is also low, thereby reducing estimation uncertainty and increasing the accuracy of the formation fracture pressure determination. 
     A preferred implementation of the method of the invention provides for safe well control while the conventional BOP  32  is closed in response to a detected or suspected kick (i.e., fluid influx). During normal drilling operations, a drill string turning device  38 , turns an upper end  24  of a drill string  20  in a borehole  12 . The drill string  20  has a drill bit  26  at a lower end  22  which contacts the bottom of the borehole  12 . As the drill string  20  is turned, the drill bit  26  penetrates the subterranean formation  14  thereby increasing the depth of the borehole  12  and creating a well bore annulus  18  between an outer diameter of the drill string  20  and an inner diameter of the borehole  12 . While drilling, a fluid or mud is pumped from a surface fluid reservoir  42  by a conventional surface fluid/mud pump  40  through a fluid injection line  48 , through a central passageway of the drill string  20 , out nozzles in the drill bit  26  and into the well bore annulus  18 . Continued injection of the fluid into the well bore annulus  18  causes the fluid to pick up cuttings from the penetration of the subterranean formation  14  by the drill bit  26  and move them up the well bore annulus  18  and through a fluid return line (not shown). The fluid return line carries the fluid/mud with cuttings to a shale shaker  44  to remove the cuttings from the fluid/mud. The cleaned fluid/mud is then returned to the surface fluid reservoir  42  for reuse. 
     As the drill bit  26  penetrates into deeper subterranean formation zones, the formation pressure may increase or decrease. A zone in the subterranean formation  14  may be encountered in which the formation pressure is greater than the hydrostatic and/or dynamic pressure provided by the fluid/mud in the well bore annulus  18 . In such case, a kick or fluid influx may occur. 
     Upon detection or suspicion of a fluid influx, a preferred well control procedure is to stop drilling (i.e., stop the rotation/turning of the drill string  20 /drill bit  26  and stop the circulation of fluid by ceasing the operation of fluid pump  40  and closing the flow control device  70  to permit no fluid flow therethrough), close the conventional BOP  32 , and allow the standpipe and casing pressures at the surface to stabilize. After stabilizing the well bore pressure, the preferred next steps are to ascertain the hydrostatic condition of the well bore  12 , confirm the suspected fluid influx (i.e., confirm that the well bore  12  is in a condition in which existing mud hydrostatic pressure is less than the pressure in an exposed, producing formation), determine the formation pore pressure, and determine the correct fluid/mud weight that should be circulated through the well bore  12  to regain control of the well, with all steps preferably performed using central control unit  80  and software  81 . 
     Since software  81  is preferably employed to control choke  70  to maintain the pressure in choke line  56  at specific, selected values, a preferred method of ascertaining the hydrostatic condition of the well bore  12  involves operating fluid pump  40  to circulate fluid at a constant flow rate. This action is followed by reducing the casing pressure in small step changes (i.e., incrementally) by opening the choke  70  in corresponding step changes while monitoring the flow rate of fluid out of the well bore  12  through the choke line  56  (as well as the flow rate into the well bore  12 , which is preferably constant). Opening the choke  70  reduces the backpressure applied to the borehole annulus  18 . In contrast to the leak-off test procedure previously described, the flow rate of fluid out of the well bore  12  will increase after the casing pressure is reduced. Further, if the well is dynamically overbalanced, the flow rate of fluid out of the well bore  12  soon equilibrate to the flow rate of fluid into the well bore  12 . Subsequent reductions in the casing pressure (i.e., a greater fluid flow rate through flow control device  70 ) eventually induce the well  12  into becoming dynamically underbalanced (i.e., flow rate into the well bore represented by signal F in (t) becoming smaller or less than flow rate out of the well bore  12  represented by signal F out (t)). The underbalanced condition is confirmed by the flow rate out of the well bore  12  (i.e., represented by signal F out (t)) remaining consistently higher or greater than the flow rate into the well bore  12  (i.e., represented by signal F in (t)) after steady state is achieved following the previous reduction in casing pressure. As further confirmation, the casing pressure may be immediately increased to the previous higher value, by reducing fluid flow rate through flow control device  70 , such that the flow rate F in (t) or F in (t) into the well bore  12  substantially equals the flow rate F out (t) out of the well bore  12 . The formation pore pressure is simply the annulus pressure, P ann (t), at the depth of the fluid influx at a time, t pore , when the flow rate out of the well bore annulus  18  first starts/begins to no longer equal or approximate the flow rate into the well bore  12 , thereby maintaining a steady state gain of fluid into the well bore  12  (i.e., when flow rate into the well bore  12 , as represented by signal F in (t), first becomes consistently less than flow rate out of the well bore  12 , as represented by signal F out (t)). As described above, the software  81  of the central control unit  80  generates the annulus pressure signal, P ann (t), at a specified well depth as a function of time (t). Thus, the formation pore pressure, like the annulus pressure, is a function of the hydrostatic pressure, the casing pressure being applied as preferably measured by the outlet pressure measurement device  64  (i.e., signal P out (t)) and the friction loss in the well bore annulus  18  and choke line  56  generated by the circulating fluid (i.e., a function of signal F out (t)), as preferably estimated by the hydraulic model incorporated into software  81 . 
     If the casing pressure cannot be reduced sufficiently to create a dynamically underbalanced condition by fully opening the choke  70 , then the fluid/mud pump  40  is adjusted to reduce the flow rate of fluid pumped into the well bore  12 . The fluid flow rate out of the well  12  is subsequently monitored as described above. If the fluid pump  40  is off and the well  12  is not hydrostatically underbalanced, it is an indication that a false kick alarm, or a very small pocket of pressurized fluid fully depleted by the influx that entered the well bore, triggered the BOP  32  closed by the rig crew. Thus, there may be no need to increase the weight of the fluid inside the well bore  12  before resuming operations. 
     After the conventional BOP  32  is closed in response to a detected fluid influx, the hydrostatic condition of the well has been confirmed to be underbalanced, and the pore pressure of the formation  14  is determined, fluid is pumped into the well bore annulus  18  via the drill string  20  and/or the kill line  54  to circulate the fluid influx out of the well bore  12  through the choke line  56 . However, depending on the condition of the well at the time BOP  32  is finally closed by the rig crew, circulation of the influx out of the well bore  12  may be performed before confirming the hydrostatic condition of the well  12  to be underbalanced and/or before the pore pressure of the formation  14  is determined. The fluid pumped into the well bore annulus  18  and the formation fluid (i.e., influx fluid) entering, or that has entered, the well bore annulus  18  from the formation  14  flow through the choke line  56  to the separator  46  and then to surface fluid reservoir  42 . An increasingly heavier weight fluid/mud may be circulated through the well bore  12  until the formation pressure is equalized by the hydrostatic pressure of the fluid/mud. Preferably, however, the circulation of the heavier fluid is done after the well is confirmed to be hydrostatically underbalanced and the formation pore pressure is determined, as described above. In this way, the correct weight of the heavier fluid weight may be readily determined, e.g., by software  81 , as a weight that will provide a hydrostatic fluid pressure greater than the previously determined pore pressure. The correct weight of the heavier fluid weight is then circulated through the well  12  to hydrostatically balance the well  12  to a well bore/annulus pressure greater than the previously determined pore pressure but less than the previously determined fracture pressure. 
     Circulation of the fluid/mud through well bore  12  is indirectly and preferably controlled by the flow control device  70  disposed in the choke line  56  and/or by the pumping action of pump  40 . The central control unit  80  controls the flow control device  70  to increase or decrease the flow rate through the choke line  56 , thereby decreasing or increasing, respectively, the backpressure on the well bore annulus  18 . Alternatively, the flow control device  70  may be controlled manually by the operator to increase or decrease the flow rate through the choke line  56 , thereby controlling the backpressure applied to the well bore annulus  18 . As previously stated, the signal P out (t) is representative of pressure within the choke line  56 , and particularly, the outlet pressure applied to the well bore  12  (i.e., backpressure or casing pressure), when the outlet pressure measurement device  64  is disposed upstream of the flow control device  70 . 
     Alternatively, the central control unit  80  may control the speed or pumping capacity of the pump  40  to either increase or decrease the flow rate of fluid/mud pumped into the well bore  12 . In this way, the pump  40  controls the pressure at which the fluid/mud is delivered to the well bore  12 . As previously stated, the signal P in (t) is representative of the pressure (i.e., standpipe pressure) of the fluid pumped into the well bore  12  through the fluid injection line  48 , and particularly, the inlet pressures applied to the well bore  12  through the drill string  20 . Likewise, the signal P in2 (t) is representative of the pressure (i.e., standpipe pressure) of the fluid pumped into the well bore  12  through the kill line  54 , and particularly the inlet pressure applied to the well bore  12  through the kill line  54 . 
     Based upon the pore pressure and fracture pressure (or other specified upper and lower pressure limits), and preferably while measuring and/or calculating pressures, flow rates, and temperatures into and out of the well bore  12  as well as other well parameters, including signal P ann (t), the software  81  of central control unit  80  generates a signal, FC(t), which is transmitted preferably in real time to the flow control device  70 . The flow control device  70  is arranged and designed to receive the signal FC(t) and to adjust the fluid flow through the flow control device  70  according to the signal. For instance, a signal FC(t) increasing the choke line flow rate will reduce the backpressure applied to the well  12  and thus decrease the pressure in the annulus  18 . Conversely, a signal FC(t) decreasing the choke line flow rate will increase the backpressure applied to the well  12  and thus increase the pressure in the annulus  18 . Thus, adjusting the fluid flow through the flow control device  70  adjusts the backpressure applied to the well  12  so as to maintain the pressure in the well bore  12 , as determined preferably in real time by generated signal P ann (t), between the previously determined (or pre-determined/set point) fracture and pore pressures of the formation  14 . Signal FC(t) is representative of either the choke line flow rate or pressure required to maintain the well annulus pressure below the formation fracture pressure and above the formation pore pressure, as a function of time. Whether the signal FC(t) is representative of choke line flow rate or choke line pressure depends on whether flow rate or pressure is the basis of the well control procedure. 
     The logic used to determine the signal, FC(t), is based on conventional well control theory, e.g., as referenced in D AVID  W ATSON ET AL ., A DVANCED  W ELL  C ONTROL  (SPE Textbook Series, 1986) and incorporated herein by reference. An example of this logic is to maintain the surface casing pressure, P out (t), constant while changing the speed of pump  40 . Another example of this logic involves maintaining the standpipe pressure, P in (t), constant while circulating out the influx fluid. 
     Alternatively, signal, FC(t), may involve hydraulics calculations performed by software  81  of the central control unit  80  concurrent with, and utilizing real-time measurements from the various measurement devices referenced previously, including but not limited to, outlet pressure measurement device (choke pressure gauge)  64 , outlet flow rate measurement device (choke line pressure gauge)  50 ,  58 , inlet pressure measurement device (standpipe pressure gauge)  62 , inlet flow rate measurement device  52 , etc. An example of such hydraulics calculation usage employs the hydraulics model calibrated during drilling operations just prior to a fluid influx into the well bore  12 . Using such hydraulics model, the software  81  calculates the pressure at a specific point in the annulus  18 , P ann (t), (e.g., at the “weak point” below the casing shoe) using hydraulics modeling of friction losses in the drill string  20 , through the nozzles of the drill bit  26 , and between the drill bit  26  and the specific point in the annulus  18 . This calculated annular pressure, P ann (t), which predictably decreases during a conventional kill operation, provides feedback/input to software  81 , which may then be used (e.g., compared to a desired, specific value or to upper/lower limits, such as for fracture/pore pressure) in generating signal FC(t) to automatically control flow control device  70  to apply more or less backpressure to the well  12 , as previously disclosed. Using this method, signal P ann (t) is maintained between specific limits, e.g., between the fracture and pore pressures, or driven toward a desired, specific value for any given time, t. A settling time between flow control device  70  adjustments may be programmed into the software  81 , or otherwise instituted, in order to permit pressure in the annulus  18  to reach steady state. 
     In a preferred implementation, the central control unit  80  controls, and preferably maintains a substantially constant value for, the annulus pressure P ann (t) at a particular well bore depth by driving the annulus pressure signal P ann (t) toward a desired value between the fracture pressure and the pore pressure to avoid fracturing the formation (i.e., when the well bore pressure is above the fracture pressure) or causing a secondary influx (i.e., when the well bore pressure is below the pore pressure). The annulus pressure signal P ann (t) is driven toward the desired value through control of flow control device  70  via signal FC(t), as previously disclosed. Signal FC(t) is generated such that the difference between annulus pressure signal P ann (t) at any time (t) and the desired, specified annulus pressure is driven toward zero or near zero. Therefore, while the conventional BOP  32  is closed and the fluid influx is being circulated out of the well bore, the central control unit  80  in combination with the flow control device  70  controls the well  12  and maintains the pressure inside the well bore annulus  18  below the formation fracture pressure but above the formation pore pressure. Alternatively, the operator, while viewing the flow rate and pressure data received from the various measurement devices via the central control unit  80 , may control the choke  70  manually to ensure that the generated signal P ann (t), representative of pressure at a certain depth inside the well bore annulus  18  as a function of time (t), is maintained between the fracture and pore pressures of the formation  14 . 
     Thus, in a preferred implementation of the method of the invention, the well  12  is safely controlled after the conventional BOP  32  is closed in response to a suspected fluid influx event by ascertaining the hydrostatic condition of the well bore  12 , confirming the suspected fluid influx, determining the pore and fracture pressures of the formation  14 , determining the correct fluid/mud weight that should be circulated through the well bore  12 , circulating the fluid influx out of the well through the choke line  56 , and circulating the heavier fluid into the well  12  and annulus  18  while monitoring all measured parameters and controlling the choke line choke  70  to maintain the annulus pressure between the fracture pressure and the pore pressure of the formation  14 . 
     While the system  10  and method are described herein as being used in real time during actual oil and/or gas operations, the system  10  and method may also be employed off-line to provide a safe opportunity for crews to manually perform the same operational well control sequences, thereby confirming crew competency or providing highly relevant remedial well control training. Thus, the system  10  is used to train the rig personnel/crew in understanding the proper procedures to be implemented in response to well control events, such as when the conventional BOP  32  is closed upon detection of a fluid influx event. In the off-line mode and at unannounced times when well and drilling conditions permit interruption of operations without undue risk, well control experts may send commands (e.g., control signals) and/or data to the central control unit  80  to implement off-line well control event training scenarios/models that utilize actual well and drilling equipment conditions as the basis for the training exercise. In this way, remotely located well control experts may test and train rig crews in the performance of well control techniques in response to simulated rig operations occurring before, during, and after a well control event, such as a fluid influx. In addition to establishing the conditions relevant to the training objectives in a realistic, but controlled, manner, the system will record, in real time, the actual valve actuations, pump operations, pressure adjustments, etc. that reflect the competency of the crew in relation to well control performance objectives. As generally shown in  FIG. 5  and as discussed previously, rig data/parameters received by and/or calculated by the central control unit  80  may be transmitted to remote units (e.g., remote computers, mobile devices, etc.) for observation and/or review by well control experts conducting such training exercises, or monitored and assessed directly on the rig  90  by the rig crew supervisors. Review and replay of the response sequences provides heretofore unobtainable data to confirm crew competencies and/or deficiencies while using actual rig equipment under field operational, rather than test, conditions. An advantage to such testing and training is that the rig crew responds to simulated well control events using the same system  10  and method described herein, which are the same system  10  and method that would be preferably used during normal operation or during an actual well control event. Thus, the use of the same system  10  and method that is actually used on the rig  90  for testing and training provides an invaluable opportunity for rig crew training and competency assessments. 
     The Abstract of the disclosure is written solely for providing the U.S. 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 herein: