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BACKGROUND OF THE INVENTION 
     1. Field of the Invention 
     The present invention relates to a method and an apparatus for drilling a well. More particularly, the invention relates to a method and an apparatus for drilling a well in an underbalanced condition. More particularly still, the invention relates to a method and an apparatus enhancing safety of the personnel and equipment during drilling a well in an underbalanced condition using a dynamic column of heavy fluid. 
     2. Description of the Related Art 
     Historically, wells have been drilled with a column of fluid in the wellbore designed to overcome any formation pressure encountered as the wellbore is formed. In additional to control, the column of fluid is effective in carrying away cuttings as it is injected at the lower end of drill string and is then circulated to the surface of the well. While this approach is effective in well control, the drilling fluid can enter and be lost in the formation. Additionally, the weight of the fluid in the wellbore can damage the formation, preventing an adequate migration of hydrocarbons into the wellbore after the well is completed. Also, additives placed in the drilling fluid to improve viscosity can cake at the formation and impede production. 
     More recently, underbalanced drilling has been used to avoid the shortcomings of the forgoing method. Underbalanced drilling is a method wherein the pressure of drilling fluid in a borehole is intentionally maintained below the formation pressure in wellbore. 
     In underbalanced drilling operations, a rotating control head (RCH) is an essential piece of wellhead equipment in order to provide some barrier between wellbore pressure and the surface of the well. A RCH is located at the top of the well bore to act as barrier and prevent leakage of return fluid to the top of the wellhead so that personnel on the rig floor are not exposed to produced liquid and hazardous gases. An RCH operates with a rotating seal that fits around the drill string. The rotating seal is housed in a bearing assembly in the RCH. Because it operates as a barrier, the RCH is often subjected to high-pressure differential from below. In order for the RCH to work properly, stripper rubber elements designed to seal the drill pipe must fit around the drill pipe closely. These rubber elements are frequently changed on the job with new elements to ensure proper functioning of the RCH. However, even with frequent change of these elements, operators are often concerned about the safety on the high-pressure wells, especially where hazardous gases are expected with the return fluid. Additionally, in relatively high-pressure gas wells the use of drilling fluid density for controlling return flow pressure lowers production from the well and requires the produced gas be recompressed before it is fed into a service line or used for re-injection. 
     In another form of underbalanced drilling, two concentric casing strings are disposed down the wellbore. Drilling fluid is pumped into the drill string disposed inside the inner casing. A surface RCH is connected to the drill string at the wellbore. Another fluid is pumped into an annulus formed between the two casing strings. Thereafter, both of the injected fluids return to the surface through an annulus formed between the drill string and inner casing. Gas rather then fluid may be pumped into the outer annulus when drilling a low-pressure well to urge return fluid up the annulus. Conversely, when drilling a high pressure well, fluid is preferred because the hydrostatic head of the fluid can control a wide range of downhole pressure. The operator can regulate the downhole pressure by varying the flow rate of the second fluid. This method has a positive effect on the rotating control head (RCH) in high-pressure wells because the pressure of returning fluid at the wellhead is reduced to the extent that there is added friction loss. However, the RCH is not isolated from produced fluids therefore imposes a safety risk on rig operators from leakage of produced fluid due to a failure in the RCH. 
     A mudcap drilling system is yet another method of underbalanced drilling. This drilling method is effective where the drilling operator is faced with high annular pressure. FIG. 1 is a section view showing a traditional mud cap drilling system. After a borehole is drilled, a casing  30  is disposed therein and cemented in the wellbore  15 . A drill string  35  is disposed in the wellbore  15  creating an annulus  10  between the casing  30  and the drill string  35 . The drill operator loads the annulus  10  by pumping a predetermined amount of heavy density fluid in an inlet port  60 . This fluid is designed to minimize gas migration up the annulus  10 . After the fluid reaches the predetermined hydrostatic pressure, the drill operator shuts in an inlet port  60 . 
     As illustrated on FIG. 1, the system includes a rotating control head (RCH)  50  at the surface of the wellhead  15 . The RCH  50  includes a seal that rotates with the drill string  35 . The heavy density fluid applies an upward pressure on the downward facing RCH  50 , thereby sealing off the outer diameter of the drill string  35 . The purpose of the RCH  50  is to form a barrier between the heavy density fluid mudcap and the rig floor. At this point, the shut in surface pressure on the annulus plus the hydrostatic pressure resulting from the heavy density fluid equals the formation pressure. This annular column of heavy density fluid is held in place by a pressure barrier  45  created between hydrostatic fluid column pressure and the downhole pressure. To offset any annular loses of fluid into to the formations  25 , it may be necessary to add fluid to the mudcap in the same sequence as it was initially introduced. Additionally, the system also includes a blow out preventor  55  (BOP) disposed at the surface of the well for use in an emergency. Thereafter the mudcap is established, the drilling operation may continue pumping clean fluid that is compatible with the formation fluids down a drill string  30  exiting out nozzles in a drill bit  40 . A permeable formation fracture  25  receives the drilling fluid as it pumped down the drill string  30 . A term used in the oil and gas industry called “bullheading” results due to the formation of the barrier  45  at the bottom of the annular column  10  between the heavy density fluid and hydrocarbon formation pressure. The barrier  45  prevents drilling fluid returning to the surface, thereby urging the fluid into the formations  25 . Although this process requires specialized well control and well circulation equipment during the mudcap drilling operation, there is no need for extensive fluid separation system since the formation fluids are kept downhole. 
     There are several problems that exist with the traditional mudcap drilling system. For example, as with other forms of well control the surface rotating control head (RCH) is the only barrier between the high-pressure return fluid and personnel on the rig floor. The operators are often concerned about safety on high-pressure wells since there is no early warning system in place. In another example, the RCH stripper rubbers wear out rapidly due to the high differential pressure. These stripper rubbers need to be changed periodically on the job to ensure proper functioning of the RCH. This is a costly operation in terms of rig time and cost of the rubber elements. In a further example, this drilling method can only operate if a permeable fracture or formation exists because all the drilling fluids are not returned to the surface but are being pumped into a permeable fracture. This drilling fluid loss is also a costly investment. In yet a further example, reservoir damage can occur due to the lack of control of a true underbalanced state between the fluid column pressure and the formation pressure, thereby reducing the productivity of the well. In the final example, the well does not produce hydrocarbons while tripping the drill string in a traditional mudcap drilling operation. 
     In view of the deficiencies of the traditional mudcap drilling system and other well control methods, a need exists to ensure the safety of the rig operators by providing an early warning system to tell the operators that a potential catastrophic problem exists. There is a further need to extend the life of the RCH due to the high cost of non-productive rig time as a result of replacing the rubber part. There is yet a further need to save operational costs and prevent formation damage by allowing the drilling fluid to return to the surface of the wellhead while maintaining the benefits of a traditional mudcap system. There is yet even a further need for a mudcap assembly, which allows the well to produce hydrocarbons while tripping the drill string. 
     SUMMARY OF THE INVENTION 
     The present invention provides a method and an apparatus for a dynamic mudcap drilling and well control assembly. In one embodiment, the apparatus comprises of a tubular body disposable in a well casing forming an outer annulus there between and an inner annulus formable between the body and a drill string disposed therein. The apparatus further includes a sealing member to seal the inner annulus at a location above a lower end of the tubular body and a pressure control member disposable in the inner annulus at a location above the lower end of the tubular body. 
     In another embodiment, the assembly uses two rotating control heads, one at the top of the wellhead assembly in a conventional manner and a specially designed downhole unit. Thus, creating dual barriers preventing any potential leak of produced gases or liquid hydrocarbon on to the rig floor, thereby ensuring the safety of the rig operators. Furthermore, the assembly provides an early warning method for detecting catastrophic failure in any of the two rotating control heads. Additionally, the assembly provides a practical method for reducing wear on the RCH stripper rubbers by ensuring the pressure differential across both the surface and downhole RCH is small, thereby extending the life of the RCH and reducing the non-productive time of the rig due to periodic replacement of the rubber part in the RCH. Further, the assembly provides for a way of circulating the return flow to the top of the wellbore thereby reducing cost of drilling by utilizing the return drilling fluid. Further yet, the assembly provides a practical method for containing and controlling wellhead pressure of return fluids by use of a high-density fluid column. Additionally, the assembly using a WEATHERFORD® deployment valve allows the well to continue to produce hydrocarbons without any drill string in the well bore. Finally, the assembly provides a method for allowing the well to produce hydrocarbons while tripping the drill string. 
    
    
     BRIEF DESCRIPTION OF THE DRAWINGS 
     So that the manner in which the above recited features, advantages and objects of the present invention are attained and can be understood in detail, a more particular description of the invention, briefly summarized above, may be had by reference to the embodiments thereof which are illustrated in the appended drawings. 
     It is to be noted, however, that the appended drawings illustrate only typical embodiments of this invention and are therefore not to be considered limiting of its scope, for the invention may admit to other equally effective embodiments. 
     FIG. 1 is a section view showing a traditional mud cap drilling operation. 
     FIG. 2 is a section view of one embodiment of a dynamic mudcap drilling and well control assembly of the present invention. 
     FIG. 3 is a section view of another embodiment of a dynamic mudcap drilling and well control assembly illustrating the placement of high density fluid in an inner annulus. 
     FIG. 4 illustrates the annulus return valve in the open position during a drilling operation using a mudcap drilling and well control assembly. 
     FIG. 5 is a section view of a dynamic mudcap drilling and well control assembly illustrating the removal of high density fluid from the inner annulus. 
     FIG. 6 is a section view of a dynamic mudcap drilling and well control assembly with a WEATHERFORD® deployment valve disposed in the inner casing string. 
    
    
     DETAILED DESCRIPTION OF THE PREFERRED EMBODIMENT 
     FIG. 2 is a section view of one embodiment of a dynamic mudcap drilling and well control assembly  100  of the present invention. The assembly  100  comprises of two concentric casings, an outer casing  180  and an inner casing  185 . In the embodiment shown in FIG. 2, the outer casing  180  is the wellbore casing and is cemented in a wellbore  195 . The inner casing  185  is disposed coaxially in the outer casing  180 , thus creating an outer annulus  155  between the outer casing  180  and the inner casing  185 . An inner annulus  150  is formed between the inner casing  185  and a drill string  190 , which extends through a bore of the inner casing  185 . The inner casing  185  is tied to the wellhead by an inner casing hanger  187  located at the surface of the well. Additionally, a liner  105  is attached at the lower end of the outer casing  180  by a liner hanger  215 . 
     A sealing member is disposed at the upper end of the assembly  100 . In the embodiment, the sealing member is a rubber stripper or a surface rotating control head (RCH)  110 . However, other forms of sealing members may be employed, so long as they are capable of maintaining a sealing relationship with the drill string  190 . Typically, the surface RCH  110  includes a seal that rotates with the drill string  190 . The seal contact is enhanced as a pressure control member, such as a high density fluid column  170 , applies upward pressure on the downward facing surface RCH  110 , thereby pushing the surface RCH  110  against the drill string  190  and sealing off the outer diameter of the drill string  190 . The purpose of the RCH  110  is to form a barrier between the inner annulus  150  and the rig floor. Below the surface RCH  110  is a valve member  120  to permit fluid communication between the surface of the well and the inner annulus  150 . As shown, an upper blow out preventor (BOP)  130  is disposed on the surface of the well for use in an emergency. Additionally, a return port  125  permits fluid to exit the well surface. 
     In the embodiment shown on FIG. 2, drilling fluid, as illustrated by arrow  205 , is pumped down the drill string  190  exiting out a drill bit  165 . The drilling fluid combines with the downhole fluid to create a downhole pressure. The down hole pressure acts against the hydrostatic pressure due to the heavy density fluid  170 , thereby creating a pressure barrier  220 . One function of the pressure barrier  220  is to maintain the heavy density fluid  170  within the inner annulus  150 . Another function of the pressure barrier  220  is to prevent hydrocarbons from traveling up the inner annulus  150 . As illustrated by arrow  210 , the hydrocarbons are urged by the wellbore pressure up the liner  105  into the outer annulus  155  then exiting out port  125 . In this manner, the assembly of the present invention offers advantages of a prior art mudcap and the ability to produce the well at the same time. 
     FIG. 3 is a section view of another embodiment of a dynamic mudcap drilling and well control assembly  100  illustrating the placement of high density fluid  170  in the inner annulus  150 . The inner annulus  150  is divided by a rotating control head (RCH)  115  into an upper annulus  150   a  and a lower annulus  150   b  as shown on this embodiment. The assembly  100  also includes an outward extending seal assembly  160  at a lower end of the inner casing  185 . The seal assembly  160  mates with a polish bore receptacle (PBR)  175  formed at an upper end of the liner  105 ; the liner  105  is centered in the wellbore. The seal assembly  160  and the PBR  175  permit a fluid tight relationship between the assembly  100  and the liner  105 . As further illustrated, the upper blow out preventor (BOP)  130  and a lower blow out preventor (BOP)  135  are disposed on the surface of the well for use in an emergency. 
     In this embodiment, the pressure control member comprises of the fluid column  170  and the rotating control head (RCH)  115 . The RCH  115  includes a seal that rotates the drill string. The high-density fluid column  170  applies downward pressure on the upward facing RCH  115  thereby pushing the RCH  115  against the drill string  190  and sealing off the outer diameter of the drill string  190 . 
     As illustrated on FIG. 3, a circulating valve  140  is disposed on the inner casing  185  above the RCH  115 . The circulating valve  140  provides fluid communication between upper annulus  150   a  and outer annulus  155 . As further illustrated, the assembly  100  also includes an annulus return valve  145  disposed at the lower end of in the inner casing  185 . The annulus return valve  145  facilitates fluid communication between the lower annulus  150   b  and the outer annulus  155 . 
     The assembly of FIG. 3 is constructed when the assembly  100  is inserted into the wellbore  195  forming the outer annulus  155  between the wellbore casing  180  and the inner casing  185 . The circulating valve  140  and the annulus control valve  145  are in the open position allowing displaced hydrocarbons to exit. Next, the assembly  100  is secured in the wellbore  195  by the inner-casing hanger  187 . Additionally, a fluid tight relationship is formed by mating the seal assembly  160  on the lower end of the assembly  100  to the PBR  175  at the upper end of the liner  105 . Thereafter, A drill string  190  is inserted in the bore of the inner casing  185 , thereby forming the upper annulus  150   a  and lower annulus  150   b . As shown, the surface RCH  110  and the RCH  115  seal off the upper annulus  150   a  for a high-density fluid column  170 . 
     In operation, the following steps occur to fill the upper annulus  150   a  with high-density fluid. First, annulus return valve  145  is closed, thereby preventing hydrocarbons in the inner annulus  150  to enter the outer annulus  155 . Second, the circulating valve  140  is opened to allow fluid communication between upper annulus  150   a  and outer annulus  155 . Third, a predetermined amount of high density fluid is pumped into the valve member  120  by an exterior pumping device, thereby displacing excess fluid in the upper annulus  150   a  out the circulating valve  140  into the outer annulus  155  exiting out the return port  125 . Fourth, after the upper annulus  150   a  is filled with high-density fluid, the circulating valve  140  is closed to retain the high-density fluid in the upper annulus  150   a . Fifth, the valve member  120  is closed to prevent leakage from the top of the fluid column. In the final step, the annulus return valve  145  is selectively opened to communicate hydrocarbons from the inner annulus  150  to the outer annulus  155  for collection at the return port  125 . 
     One use of the high-density fluid column  170  is to control pressure differential across the RCH  115 . The weight of the fluid column  170  is adjustable; it can be changed in response to the dynamic wellbore conditions. During operation of the assembly, the hydrostatic head of high-density fluid acting from above on the stripper rubber in the RCH  115  counters return fluid pressure from below leaving a small differential pressure across the stripper rubber thus enhancing the service life of the stripper rubbers. However, if the return fluid pressure is greater than the hydrostatic head of high-density fluid, the high-density fluid is pressurized at the surface to maintain pressure difference across the stripper rubber within the acceptable range. Conversely, if in return fluid pressure is much lower than the hydrostatic head above the downhole RCH  115  then some of the high-density fluid column is removed by opening the valve member  120  and the circulating valve  140 , thereby allowing high density fluid in the upper annulus  150   a  to pass through the circulating valve  140  and up the outer annulus  155  exiting through the return port  125 . In this manner the assembly  100  of the present invention offers advantages of a prior art mudcap and the ability to reduce wear in the RCH. 
     FIG. 4 illustrates the annulus return valve  145  in the open position during a drilling operation using the mudcap drilling and well control assembly  100 . The main function of the annulus control valve  145  is to selectively communicate return fluid from the lower annulus  150   b  to the outer annulus  155 . During a drilling operation the annulus control valve  145  is in the open position. Drilling fluid is pumped into the drill string  190  and exits through nozzles in the drill bit  165 . The return fluid consisting of drilling fluid and hydrocarbons produced into the wellbore is urged up the liner  105  into the lower annulus  150   b  formed between the drill string  190  and the inner casing  185  by formation pressure. The RCH  115  stops the upward flow of return fluid in the lower annulus  150   b  forcing it toward the annulus return valve  145 . The return fluid is selectively communicated between the lower annulus  150   b  and the outer annulus  155  through the ports in the annulus return valve  145 . Upon entering the outer annulus  155  the fluid is urged upward exiting out a return port  125  at the surface of the wellhead. 
     The preferred embodiment has several safety features. For example, during a drilling operation the annulus return valve  145  can be closed using a surface control device, thereby causing the well to be shut in downhole. Therefore, no return fluid is communicated to the outer annulus  155  from the inner annulus  150  and the seal formed between the RCH  115  and the drill string  190  prevents return fluid from continuing up the inner annulus  150 . Another example, the surface RCH  110  situated below the rig floor is completely isolated from the return fluid. Fluid pressure below the surface RCH  110  increases only if the downhole RCH  115  develops a leak causing high-density fluid in the inner annulus  150  to become pressurized. If a leak also occurs in the surface RCH  110  at the same time, high-density fluid would leak out the surface RCH  110  before any return fluid reaches the rig floor thereby providing sufficient time for remedial action such as closing the BOP  130 ,  135 . In practice, the pressure of the high-density fluid column  170  could be continuously monitored. Any change of pressure in high-density fluid column  170  would give a good indication of the condition of stripper rubber in the RCH  115 . 
     FIG. 5 is a section view of a dynamic mudcap drilling and well control assembly  100  illustrating the removal of high density fluid  170  from the inner annulus  150 . As shown, the drill string  190  is raised to a point below the RCH  115 . Thereafter, a lighter fluid, as illustrated by arrow  225 , is pumped into the port  125  at the surface of the well. The lighter fluid flows down the outer annulus  155  and then through the open circulation valve  140  into the upper annulus  150   a . Subsequently, the lighter fluid displaces the high density fluid column  170  causing the high density fluid  170  to exit through the open valve member  120 . This process continues until the high density fluid  170  is removed from the upper annulus  150   a . Thereafter, the drill string  190  is removed. 
     FIG. 6 is a section view of a dynamic mudcap drilling and well control assembly  100  with a WEATHERFORD® deployment valve  200  disposed in the inner casing  185 . In this embodiment, the WEATHERFORD® deployment valve  200 , U.S. Pat. No. 6,209,663, is disposed in the inner casing  185  at a predetermined point above the annulus return valve  145 . The predetermined point is based upon the weight of the drill string  190  (not shown) and the down hole pressure. During a drilling operation the deployment valve  200  is in the open position, thereby allowing the drill string  190  to pass through the valve  200  without interference. 
     The deployment valve  200  increases the functionality of the mudcap drilling and well control assembly  100 . For example, during a drilling operation if a drill bit or a motor needs replacement, the drill string  190  is pulled from the wellbore to a point above the deployment valve  200 . Thereafter, the valve  200  is closed preventing return fluid continuing up the inner annulus  150 . Therefore, the drill string  190  is pulled from the wellbore  195  without any effect of down hole fluid pressure. Upon re-insertion, the drill string  190  is lowered in the wellbore  195  to a point above the deployment valve  200 , thereafter the valve  200  is opened permitting further insertion in the wellbore  195 . 
     Another example is the ability to produce hydrocarbons without the drill string disposed in the wellbore  195 , as illustrated on FIG.  6 . The valve  200  is closed after the drill string is removed from the wellbore. Wellbore fluid is urged up the liner  105  by downhole pressure. The wellbore fluid enters the open annulus return valve  145 , then selectively communicated from the lower annulus  150   b  to the outer annulus  155 . Thereafter, the wellbore fluid travels up the outer annulus  155  exiting out the return port  125  for collection. A final example is the ability to close the deployment valve  200  and the annulus return valve  145  to effectively shut in the well for safety reasons. 
     While the foregoing is directed to embodiments of the present invention, other and further embodiments of the invention may be devised without departing from the basic scope thereof, and the scope thereof is determined by the claims that follow.

Summary:
A method and an apparatus for a dynamic mudcap drilling and well control assembly is provided. In one embodiment, the apparatus comprises of a tubular body disposable in a well casing forming an outer annulus there between and an inner annulus formable between the body and a drill string disposed therein. The apparatus further includes a sealing member to seal the inner annulus at a location above a lower end of the tubular body and a pressure control member disposable in the inner annulus at a location above the lower end of the tubular body. In another embodiment, the assembly uses two rotating control heads, one at the top of the wellhead assembly in a conventional manner and a specially designed downhole unit. Finally, the assembly provides a method for allowing the well to produce hydrocarbons while tripping the drill string.