Abstract:
A drilling control system monitors and compares drilling and completion operation sensor values and autonomously acts in response to conditions such as a kick or surge. Sensors in various combinations may monitor return fluid flow rate, fluid inflow rate, wellhead bore pressure, temperature of returning fluid, torque, rate of penetration and string weight change. The control system has corresponding control logic to monitor, warn and act based on the sensor inputs. The actions may include the warning of support personnel, closing an annular blowout preventer, shearing drill pipe using a ram shear, pumping heavier fluid down choke and kill lines, disconnecting the riser or various other actions.

Description:
CROSS-REFERENCE TO RELATED APPLICATION 
     This application claims the benefit of U.S. Provisional Application No. 61/479,203 filed on Apr. 26, 2011. 
    
    
     FIELD OF THE INVENTION 
     This disclosure relates in general to offshore well drilling and in particular to an automated method for controlling a subsea well during drilling procedures. 
     BACKGROUND OF THE INVENTION 
     The future of oil and gas exploration lies in deep waters and greater depth under the seabed. This renders the subsea equipment to increasingly harsh conditions such as higher pressures and increased temperatures. These harsher conditions can cause an increase in the number of kicks and hence decrease the efficiency and safety of a given operation. This calls for designing a subsea automatic control system for this widened high pressure and high temperature envelope. A control system which is capable of monitoring and logically controlling the equipment and tools can lead to a more reliable, safer, and more efficient subsea operation. 
     An improved control system that provides a more reliable, safer, and more efficient subsea drilling operation is sought. 
     SUMMARY 
     The drilling system of this invention has features to automatically detect and control a kick or surge without requiring decisions to be made by operating personnel. The invention consists of sensors and an automatic control system that monitors and performs actions autonomously based on the sensor inputs. In a given embodiment there may exist a multitude of sensor combinations depending on the needs of the particular drilling operation. For example, in one embodiment there may exist a sensor to monitor return flow rate. The signals from the return flow rate sensor may be transmitted conventionally, such as through wires and fiber optic sensors that may be part of the umbilical leading to the platform. Ideally, the return flow rate sensor will indicate the flow rate at all times that exist within the wellhead assembly. An increase in flow rate sensed by the return flow rate sensor may indicate a kick. Additional sensor inputs such as inflow rate, temperature, wellhead bore pressure, string weight change, rate of penetration, torque, and various other sensors may all be monitored for additional indications of a kick or surge condition. Certain sets of sensor conditions may cause the control system to perform autonomous actions to lessen or stop the kick. For example, an indicated kick condition may cause the control system to alert operation personnel and subsequently initiate emergency procedures. These procedures may include an emergency disconnect sequence or the initiation of a wellbore shut-in sequence. 
     The foregoing and other objects and advantages of the present invention will be apparent to those skilled in the art, in view of the following detailed description of the present invention, taken in conjunction with the appended claims and the accompanying drawings. 
    
    
     
       BRIEF DESCRIPTION OF THE DRAWINGS 
         FIG. 1  is a schematic view illustrating a well drilling control system in accordance with this disclosure. 
         FIG. 2  is a schematic flow chart identifying steps employed by the control system of  FIG. 1 . 
     
    
    
     DETAILED DESCRIPTION OF THE INVENTION 
       FIG. 1  illustrates a subsea well being drilled or completed. The well has been at least partially drilled, and has a subsea wellhead assembly  11  installed at sea floor  13 . At least one string of casing (not shown) will be suspended in the well and supported by wellhead assembly  11 . The well may have an open hole portion not yet cased, or it could be completely cased, but the completion of the well not yet finished. 
     A hydraulically actuated connector  15  releasably secures a blowout preventer (BOP) stack  17  to the wellhead housing assembly  11 . BOP stack  17  has several ram preventers  19 , some of which are pipe rams and at least one of which is a blind ram. The pipe rams have cavities sized to close around and seal against pipe extending downward through wellhead housing  11 . The blind rams are capable of shearing the pipe and affecting a full closure. Each of the rams  19  has a port  21  located below the closure element for pumping fluid into or out of the well while the ram  19  is closed. The fluid flow is via choke and kill lines (not shown). 
     A hydraulically actuated connector  23  connects a lower riser marine package (LMRP)  25  to the upper end of BOP stack  17 . Some of the elements of LMRP  25  include one or more annular BOP&#39;s  27  (two shown). Each annular BOP  27  has an elastomeric element that will close around pipes of any size. Also, BOP  27  can make full closure without a pipe extending through it. Each annular BOP  27  has a port  29  located below the elastomeric element for pumping fluid into or out of the well below the elastomeric element while BOP  27  is closed. The fluid flow through port  29  is handled by choke and kill lines. Annular BOP&#39;s  27  alternately could be a part of BOP stack  17 , rather than being connected to BOP stack  17  with a hydraulically actuated connector  23 . 
     LMRP  25  includes a flex joint  31  capable of pivotal movement relative to the common axis of LMRP  25  and BOP stack  17 . A hydraulically actuated riser connector  33  is mounted above flex joint  31  for connecting to the lower end of a string of riser  35 . Riser  35  is made up of joints of pipe  36  secured together. Auxiliary conduits  37  are spaced circumferentially around central pipe  36  of riser  35 . Auxiliary conduits  37  are of smaller diameter than central pipe  36  of riser  35  and serve to communicate fluids. Some of the auxiliary conduits  37  serve as choke and kill lines. Others provide hydraulic fluid pressure. Flow ports  38  at the upper end of LMRP  25  connect certain ones of the auxiliary conduits  37  to the various actuators. When riser connector  33  disconnects from central riser pipe  36  and riser  35  is lifted, flow ports  38  will also be disconnect from the auxiliary conduits  37 . At the upper end of riser  35 , auxiliary conduits  37  are connected to hoses (not shown) that extend to various equipment on a floating drilling vessel or platform  40 . 
     Electrical and optionally fiber optic lines extend downward within an umbilical to LMRP  25 . The electrical, hydraulic, and fiber optic control lines lead to one or more control modules (not shown) mounted to LMRP  25 . The control module controls the various actuators of BOP stack  17  and LMRP  25 . 
     Riser  35  is supported in tension from platform  40  by hydraulic tensioners (not shown). The tensioners allow platform  40  to move a limited distance relative to riser  35  in response to waves, wind and current. Platform  40  has equipment at its upper end for delivering upwardly flowing fluid from central riser pipe  36 . This equipment may include a flow diverter  39 , which has an outlet  41  leading away from central riser pipe  39  to platform  40 . Diverter  39  may be mounted to platform  40  for movement with platform  40 . A telescoping joint (not shown) may be located between diverter  39  and riser  35  to accommodate this movement. Diverter  39  has a hydraulically actuated seal  43  that when closed, forces all of the upward flowing fluid in central riser pipe  36  out outlet  41 . 
     Platform  40  has a rig floor  45  with a rotary table  47  through which pipe is lowered into riser  35  and into the well. In this example, the pipe is illustrated as a string of drill pipe  49 , but it could alternately comprise other well pipe, such as liner pipe or casing. Drill pipe  49  is shown connected to a top drive  51 , which supports the weight of drill pipe  49  as well as supplies torque. Top drive  51  is lifted by a set of blocks (not shown), and moves up and down a derrick while in engagement with a torque transfer rail. Alternately, drill pipe  49  could be supported by the blocks and rotated by rotary table  47  via slips (not shown) that wedge drill pipe  49  into rotating engagement with rotary table  47 . 
     Mud pumps  53  (only one illustrated) mounted on platform  40  pump fluids down drill pipe  49 . During drilling, the fluid will normally be drilling mud. Mud pumps  53  are connected to a line leading to a mud hose  55  that extends up the derrick and into the upper end of top drive  51 . Mud pumps  53  draw the mud from mud tanks  57  (only one illustrated) via intake lines  59 . Riser outlet  41  is connected via a hose (not shown) to mud tanks  57 . Cuttings from the earth boring occurring are separated from the drilling mud by shale shakers (not shown) before reaching mud pump intake lines  59 . 
     A kick, defined as an unscheduled entry of formation fluids into the wellbore, may occur while drilling or while completing a well. Basically, the kick occurs when an earth formation has a higher pressure than the hydrostatic pressure of the fluid in the well. If the well has an uncased or open hole portion, the hydrostatic pressure acting on the earth formation is that of the drilling mud. Operating personnel control the weight of the drilling mud so that it will provide enough hydrostatic pressure to avoid a kick. However, if the mud weight is excessive, it can flow into the earth formation, damaging the formation and causing lost circulation. Consequently, operating personnel balance the weight so as to provide sufficient weight to prevent a kick but avoid fluid loss. 
     A kick may occur while drilling, while tripping the drill pipe  49  out of the well or running the drill pipe  49  into the well. A kick may also occur while lowering logging instruments on wire line into the well to measure the earth formation. A kick may occur even after the well has been cased, such as by a leak through or around the casing or between a liner top and casing. In that instance, the fluid in the well may be water, instead of drilling mud. If not mitigated, a kick can result in high pressure hydrocarbon flowing to the surface; possibly pushing the drilling mud and any pipe in the well upward. The hydrocarbon may be gas, which can inadvertently be ignited. 
     Normally, kicks are controlled by personnel at platform  40  detecting the kick in advance and taking remedial action. A variety of techniques are used by personnel based on experience to detect a kick. Also, a variety of remedial actions are taken. For example, detecting that more drilling mud is returning than being pumped in may indicate a kick. The remedial action may include closing the annular BOP  27  and pumping heavier fluid down the choke and kill lines to port  21 , which directs the heavier fluid into the well. If drilling mud continues to flow up riser  35  and out outlet  41 , the operating personnel may close diverter  39  and direct the flow to a remote flare line. If remedial actions are not working, the operating personnel can close rams  19  and shear drill pipe  49 , then disconnect riser  35 , such as at connector  23  or connector  33 . Platform  40  can then be moved, bringing riser  35  along with it. The detection and remedial steps require decisions to be made by operating personnel on platform  40 . 
     The drilling system shown in  FIG. 1  has features to automatically detect and control a kick without requiring decisions to be made by operating personnel. The drilling system of  FIG. 1  has many sensors, of which only a few are illustrated. The sensors are intended to provide an early detection of a kick, and more or fewer may be used. Some of the sensors may be helpful only during drilling, but not while tripping the drill pipe or performing other operations, such as cementing. 
     A return flow rate sensor  67  will sense the flow rate of the drilling mud returning, or the flow rate of any upward flowing fluid. Return flow rate sensor  67  may be located in outlet  41  as shown or in BOP stack connector  15 . An inflow sensor  69  may be located at the outlet of mud pumps  53  to determine the flow rate of fluid being pumped into the well. If the return flow rate sensed by sensor  67  is greater than the inflow rate sensed by sensor  69 , an indication exists that a kick is occurring. If the return flow rate is less than the inflow rate, an indication exists that fluid losses into the earth formation are occurring. Differences in flow rates between sensors  67 ,  69  can occur because of other factors, however. For example, some lost circulation may be occurring in one earth formation at the same time a kick from another formation is occurring. 
     A wellhead bore pressure sensor  61  will preferably be located just above wellhead assembly  11  within BOP stack  17  below the lowest ram  19 . The signals from wellhead bore pressure sensor  61  are transmitted conventionally, such as through wires and fiber optic sensors that may be part of the umbilical leading to platform  40 . Wellhead bore pressure sensor  61  will indicate the pressure at all times that exist within wellhead assembly  11 . While circulating drilling mud down through drill pipe  49 , the pressure sensed will be the pressure of the returning drilling mud outside of drill pipe  49  at that point. That pressure depends on the hydrostatic pressure of the drilling mud above sensor  61 , which is proportional to the sea depth. If drilling mud is not being circulated, the pressure sensed will be the hydrostatic pressure of the fluid in riser central pipe  36 . An increase in pressure sensed by sensor  61  may indicate a kick. However, a kick might be occurring even though sensor  61  is sensing only a normal range of pressure. For example, gas migration up riser  35  would lighten the column of drilling mud above sensor  61 , causing it to either not show an increase in pressure or show a drop in pressure. Also, the pressure monitored by sensor  61  is affected by the pressure of mud pumps  53 . Nevertheless, when coupled with other parameters being sensed, sensor  61  provides valuable information that may indicate a kick. 
     Preferably one or more temperature sensors  65  is employed to sense a temperature of the upward flowing fluid. Temperature sensor  65  is also preferably in wellhead connector  15  for sensing the temperature of fluid in the bore of wellhead assembly  11 . The temperature may change if a kick is occurring. When combined with other data concerning the upward flowing fluid in riser  35 , an indication of a kick may be determined with accuracy. 
     A string weight sensor  71  is mounted to top drive  51 , or to the blocks, for sensing the weight of the pipe string being supported by the derrick. During drilling, the weight of drill pipe  49  sensed depends on how much weight of the drill pipe  49  is applied to the drill bit. If the operating personnel applies more brake, the weight sensed will increase since less weight is being transferred to the bit. If the operating personnel releases some of the brake, more weight is applied to the bit, and sensor  71  senses less weight. If a kick of sufficient magnitude occurs to begin pushing up drill pipe  49 , the weight sensed will decrease. 
     Linking the signal from string weight sensor  71  to a rate of penetration (ROP) sensor  73  will assist in determining whether less weight being sensed is due to more brake being applied or to a kick. ROP sensor  73  measures how fast drill pipe  49  is moving downward, thus is an indication of the amount of brake being applied. ROP sensor  73  also will determine when a very soft formation is being drilled into, suggesting that lost circulation might be occurring. 
     In addition a torque sensor  75  provides useful information concerning kicks. Torque sensor  75  is mounted at or near top drive and senses the amount of torque being imposed during drilling. If a kick is tending to lift drill pipe  49 , the torque would drop. Torque also decreases for other reasons, such as reducing the weight deliberately on the bit or encountering a soft formation. When coupled with the other data, torque sensed by torque sensor  75  during drilling can assist in an accurate prediction of the early occurrence of a kick. 
     A BOP control system  77  on platform  40  receives signals from sensors  61 , 65 , 67 , 69 ,  71 ,  73  and  75  and possibly others. BOP control system  77  processes these signals to detect whether a kick is occurring and issues control signals in response. Also, drill pipe  49  may have downhole sensing devices that determine conditions such as weight on the bit, torque on the bit, pressure of the drilling mud at the bit and the temperature of the drilling mud at the bit. Signals from these sensors may be transmitted up the well via mud pulse or other known techniques. These signals may also be fed to BOP control system  77 . 
     Referring to  FIG. 2 , data from the various sensors is supplied to a processor of BOP control system  77 . Step  79  indicates that the processor determines if any of the sensors  69 ,  67 ,  65 ,  61 ,  71 ,  73  and  75  are outside of a normal preset range. If so, in step  81  it will then compare the out-of-range sensor with the data received from other sensors. For example, if the out-flow rate of sensor  67  exceeded the inflow rate of sensor  69  beyond an acceptable range, control system  77  will look at the data from the other sensors to determine if an explanation exists, pursuant to step  83 . Perhaps, the other sensors will confirm that a problem exists or provide data that indicates a reasonable explanation. If the explanation is reasonable, control system  77  might take no action, depending upon how it is programmed. 
     If the various comparisons indicate a kick is occurring, control system  77  may be programmed to initially provide a visual and optionally audible warning to operating personnel, as indicated by step  85 . Operating personnel may then attempt to remedy the problem, such as by closing the annular BOP  27 . Control system  77 , however, will continue to monitor the data sent by the sensors, as indicated by step  87 . If it determines after a selected time interval that the kick condition still exists, it will move to a second warning or another step. The other step may be a first step in initiating an emergency disconnect sequence. That step depends upon the programming of control system  77 . It could be closing the annular BOP  27  per step  89 , if such hasn&#39;t already been done by the operating personnel. Control system  89  would also send a warning to the operating personnel that it has closed the annular BOP  27 . That warning would enable the operating personnel to begin pumping drilling mud down the choke and kills lines into the well, preferably with a heavier drilling mud. 
     Regardless of what steps the operating personnel take, if any, control system  77  will continue to monitor the sensors, process the data and determine whether the dangerous condition still exists, as indicated in step  91 . If after a selected interval, the dangerous condition is not abating, control system  77  will take another step  93  toward an emergency disconnect. Step  93  could be to close rams  19  and shear drill pipe  49 , or it could be an interim step. Control system  77  would provide a warning to operating personnel that such has occurred. Control system  77  may continue to monitor the sensors, as per step  95 . If the condition still exists after step  93 , for whatever reason, control system  77  may then actuate either connector  23  or  33  to release riser  35  from wellhead assembly  11 . BOP stack  17  remains connected to subsea wellhead assembly  11 . The operating personnel would then proceed to move platform  40  from its station, bringing riser  35  along with it. 
     The automated mechanism for the initiation of an emergency disconnect sequence can also be applied and employed to the initiation of a wellbore shut-in sequence. That step depends upon the programming of control system  77 . It could be closing the annular BOP  27  per step  89 , if such hasn&#39;t already been done by the operating personnel. Control system  89  would also send a warning to the operating personnel that it has closed the annular BOP  27 . That warning would enable the operating personnel to begin pumping drilling mud down the choke and kills lines into the well, preferably with a heavier drilling mud. Regardless of what steps the operating personnel take, if any, control system  77  will continue to monitor the sensors, process the data and determine whether the dangerous condition still exists, as indicated in step  91 . If after a selected interval, the dangerous condition is not abating, control system  77  will take another step and open the inner and outer bleed valves, signaling the shut-in completion of the wellbore. 
     The control system can also track the existing stack configuration mode that the control system is currently being used in and continuously monitor signals from sensors  61 , 65 , 67 , 69 ,  71 ,  73  and  75  and possibly others. Depending on the stack configuration mode, the control system can alert the operating personnel with confirmation to proceed with the existing stack condition or change the stack configuration mode to ensure that the BOP stack is brought to a safe mode. After a stipulated time interval, if there is no confirmation from the operating personnel, based on the current conditions of the stack and the functions involved, the emergency disconnect sequence or the well shut-in sequence is initiated. 
     Although not necessarily related to kicks, a riser inclination sensor  99  ( FIG. 1 ) provides information of a serious problem. Riser  35  will incline when platform  40  moves from directly above wellhead assembly  11 . Platform  40  typically has thrusters that are linked to a global positioning system (GPS). The GPS receives satellite signals and controls the thrusters to maintain platform  40  on the desired station. Sometimes the satellite signal is interrupted or a malfunction of the GPS occurs. If not detected timely, platform  40  might drift off station too far. Riser  35  has a maximum angle that it can achieve and still be disconnected at connector  23  or  33 . Beyond that angle, connectors  23  or  33  would not be able to disconnect riser  35 , thus damage to riser  35  would likely occur. 
     Signals from riser inclination sensor  99  can be fed to BOP control system  77 , which determines if the inclination is out of a selected range. If so, BOP control system  77  can proceed through the same steps as illustrated in  FIG. 2 , eventually disconnecting riser  35 , if necessary.