Patent Publication Number: US-8122975-B2

Title: Annulus pressure control drilling systems and methods

Description:
CROSS-REFERENCE TO RELATED APPLICATIONS 
     This application is a continuation of U.S. patent application Ser. No. 11/850,479, filed Sep. 5, 2007 now U.S. Pat. No. 7,836,973, which claims the benefit of U.S. Prov. Pat. App. No. 60/824,806, entitled “Annulus Pressure Control Drilling System”, filed on Sep. 7, 2006, and U.S. Prov. Pat. App. No. 60/917,229, entitled “Annulus Pressure Control Drilling System”, filed on May 10, 2007, which are herein incorporated by reference in their entireties. U.S. patent application Ser. No. 11/850,479 is also a continuation-in-part of U.S. patent application Ser. No. 11/254,993, filed Oct. 20, 2005, 
     U.S. Pat. No. 6,209,663, U.S. patent application Ser. No. 10/677,135, filed Oct. 1, 2003, U.S. patent application Ser. No. 10/288,229, filed Nov. 5, 2002, U.S. patent application Ser. No. 10/676,376, filed Oct. 1, 2003 are hereby incorporated by reference in their entireties. 
     U.S. Pat. Pub. No. 2003/0150621, U.S. Pat. No. 6,412,554, U.S. Pat. Pub. No. 2005/0068703, U.S. Pat. Pub. No. 2005/0056419, U.S. Pat. Pub. No. 2005/0230118, and U.S. Pat. Pub. No. 2004/0069496 are hereby incorporated by reference in their entireties. 
     U.S. Prov. App. 60/952,539, U.S. Pat. No. 6,719,071, U.S. Pat. No. 6,837,313, U.S. Pat. No. 6,966,367, U.S. Pat. Pub. No. 2004/0221997, U.S. Pat. Pub. No. 2005/0045337, and U.S. patent application Ser. No. 11/254,993 are herein incorporated by reference in their entireties. 
    
    
     BACKGROUND OF THE INVENTION 
     1. Field of the Invention 
     The present invention relates to annulus pressure control drilling systems and methods. 
     2. Description of the Related Art 
     The exploration and production of hydrocarbons from subsurface formations ultimately requires a method to reach and extract the hydrocarbons from the formation. This is typically achieved by drilling a well with a drilling rig. In its simplest form, this constitutes a land-based drilling rig that is used to support and rotate a drill string, comprised of a series of drill tubulars with a drill bit mounted at the end. Furthermore, a pumping system is used to circulate a fluid, comprised of a base fluid, typically water or oil, and various additives down the drill string, the fluid then exits through the rotating drill bit and flows back to surface via the annular space formed between the borehole wall and the drill bit. This fluid has multiple functions, such as: to provide pressure in the open wellbore in order to prevent the influx of fluid from the formation, provide support to the borehole wall, transport the cuttings produced by the drill bit to surface, provide hydraulic power to tools fixed in the drill string and cooling of the drill bit. 
     Clean drilling fluid is circulated into the well through the drill string and then returns to the surface through the annulus between the wellbore wall and the drill string. In offshore drilling operations, a riser is used to contain the annulus fluid between the sea floor and the drilling rig located on the surface. The pressure developed in the annulus is of particular concern because it is the fluid in the annulus that acts directly on the uncased borehole. 
     The fluid flowing through the annulus, typically known as returns, includes the drilling fluid, cuttings from the well, and any formation fluids that may enter the wellbore. After being circulated through the well, the drilling fluid flows back into a mud handling system, generally comprised of a shaker table, to remove solids, a mud pit and a manual or automatic means for addition of various chemicals or additives to keep the properties of the returned fluid as required for the drilling operation. Once the fluid has been treated, it is circulated back into the well via re-injection into the top of the drill string with the pumping system. 
     The open wellbore extends below the lowermost casing string, which is cemented to the formation at, and for some distance above, a casing shoe. In an open wellbore that extends into a porous formation, deposits from the drilling fluid will collect on wellbore wall and form a filter cake. The filter cake forms an important barrier between the formation fluids contained in the permeable formation at a certain pore pressure and the wellbore fluids that are circulating at a higher pressure. Thus, the filter cake provides a buffer that allows wellbore pressure to be maintained above pore pressure without significant losses of drilling fluid into the formation. 
     Both temperature and pressure of subsurface formations increase with depth. Subsurface formations may be characterized by two separate pressures: pore pressure and fracture pressure. The fracture pressure is determined in part by the overburden acting at a particular depth of the formation. The overburden includes all of the rock and other material that overlays, and therefore must be supported by, a particular level of the formation. In an offshore well, the overburden includes not only the sediment of the earth but also the water above the mudline. The pore pressure at a given depth is determined in part by the hydrostatic pressure of the fluids above that depth. These fluids include fluids within the formation below the seafloor/mudline plus the seawater from the seafloor to the sea surface. 
     In order to maximize the rate of drilling and avoid formation fluids entering the well, it is desirable to maintain the bottom hole pressure (BHP) in the annulus at a level above, but relatively close to, the pore pressure. Maintaining the BHP above the pore pressure is referred to as overbalanced drilling. As BHP increases, drilling rate will decrease, and if the BHP is allowed to increase to the point it exceeds the fracture pressure, a formation fracture can occur. Pressures in excess of the formation fracture pressure FP will result in the fluid pressurizing the formation walls to the extent that small cracks or fractures will open in the borehole wall and the fluid pressure overcomes the formation pressure with significant fluid invasion. Fluid invasion can result in reduced permeability, adversely affecting formation production. Once the formation fractures, returns flowing in the annulus may exit the open wellbore thereby decreasing the fluid column in the well. If this fluid is not replaced, the wellbore pressure can drop and allow formation fluids to enter the wellbore, causing a kick and potentially a blowout. Therefore, the formation fracture pressure defines an upper limit for allowable wellbore pressure in an open wellbore. The pressure margin between the pore pressure and the fracture pressure is known as a window. 
     The drilling fluid typically has a fairly constant density and thus the hydrostatic pressure in the wellbore versus depth can typically be approximated by a single gradient starting at the top of the fluid column. In offshore drilling situations, the top of the fluid column is generally the top of the riser at the surface platform. The pressure profile of a given drilling fluid varies depending upon whether the drilling fluid is being circulated (dynamic) or not being circulated (static). In the dynamic case, there is a pressure loss as the returns flow up the annulus between the drill string and wellbore wall. This pressure loss adds to the hydrostatic pressure of the drilling fluid in the annulus. Thus, this additional pressure must be taken into consideration to ensure that annulus pressure is maintained in an acceptable pressure range between the pore pressure and fracture pressure profile. 
       FIG. 1A  is an exemplary diagram of the use of fluids during the drilling process in an intermediate borehole section. The borehole has been lined with a string of casing C to a first depth DC. The open hole section to be drilled is thus from the first depth DC to a target depth D 4  of the bore hole. The two drilling fluid pressure profiles are represented by the static pressure SP and dynamic pressure DP profiles. The static pressure SP maintained by the fluid during drilling will be safely above the pore pressure PP above a second depth D 2 . At the second depth D 2 , the pore pressure PP increases, thereby reducing the differential between the pore pressure PP and the static pressure SP and also decreasing the margin of safety during operations. This may occur where the borehole penetrates a formation interval D 2 -D 4  having significantly different characteristics than the prior formation DC-D 2 . A gas kick in this interval D 2 -D 4  may result in the pore pressure exceeding the annulus pressure with a release of fluid and gas into the borehole, possibly requiring activation of the surface BOP stack. As noted above, while additional weighting material may be added to the fluid, it will be generally ineffective in dealing with a gas kick due to the time required to increase the fluid density as seen in the borehole. 
     For the given open hole interval DC-D 4 , the window for a particular density drilling fluid lies between the pore pressure profile PP and the fracture pressure profile FP. Because the dynamic pressure DP is higher than the static pressure SP, it is the dynamic pressure which is limited by the fracture pressure FP at a third depth D 3 . Correspondingly, the lower static pressure SP must be maintained above the pore pressure PP at the second depth D 2  in the open wellbore. Therefore, the window for the particular density drilling fluid, as shown in  FIG. 1 , is limited by the dynamic pressure DP reaching fracture pressure FP at the depth D 3  and the static pressure SP reaching pore pressure PP at the depth D 2 . Thus, in common drilling practice, the density of the drilling fluid will be chosen so that the dynamic pressure is as close as is reasonable to the fracture pressure. This maximizes the depth that can then be drilled using that density fluid. Once the dynamic pressure DP pressure approaches fracture pressure at the depth D 3 , another string of casing will be set and the same process repeated. 
     Recently, oil exploration and production is moving towards more challenging environments, such as deep and ultra-deepwater. Also, wells are now drilled in areas with increasing environmental and technical risks. In this context, narrow windows between the pore pressure and the fracture pressure of the formation are problematic. 
       FIG. 1B  illustrates a prior art casing program for drilling a narrow-margin wellbore. Since this is a pressure gradient graph, constant density drilling fluids appear as vertical lines. On the right are the number and diameter of the casing strings required to safely drill a wellbore. Typically a safety margin is added to the pore pressure to allow for stopping circulation of the fluid and subtracted from the fracture pressure, reducing even more the narrow window, as shown by the dotted lines. Since the plot shown in  FIG. 1B  is referenced to the static mud pressure, the safety margin allows for the dynamic effect while drilling also. The pore pressure gradient and fracture pressure gradient curves shown are estimated before drilling. Actual values might never be determined by the current conventional drilling method. It is not difficult to imagine the problems created by drilling in a narrow window, with the requirement of several casing strings, increasing tremendously the cost of the well. Moreover, the current well design shown in  FIG. 1B  does not reach the required target depth for production, since the last casing size will be too small to allow for a sufficiently sized production tubing string which will deliver oil to the surface at a sufficient flow rate to justify the cost of drilling and completing the well. In many of these cases, the wells are abandoned, leaving the operators with huge losses. 
     These problems are further compounded and complicated by the density variations caused by temperature changes along the wellbore, especially in deepwater wells. This can lead to significant problems, relative to the narrow window, when wells are shut in to detect kicks/fluid losses. The cooling effect and subsequent density changes can modify the annulus pressure profile due to the temperature effect on mud viscosity, and due to the density increase leading to further complications on resuming circulation. Thus using the conventional method for wells in ultra deep water is rapidly reaching technical limits. 
     The influx of formation fluids into the wellbore is referred to as a kick. Even when using conservative overbalanced drilling techniques, the wellbore pressure may fall out of the acceptable range between pore pressure and fracture pressure and cause a kick. Kicks may occur for reasons, such as drilling through an abnormally high pressure formation, creating a swabbing effect when pulling the drill string out of the well for changing a bit, not replacing the drilling fluid displaced by the drill string when pulling the drill string out of the hole, and, as discussed above, fluid loss into the formation. A kick may be recognized by drilling fluids flowing up through the annulus after pumping is stopped. A kick may also be recognized by a sudden increase of the fluid level in the drilling fluid storage tanks. Because the formation fluid entering the wellbore ordinarily has a lower density than the drilling fluid, a kick will potentially reduce the hydrostatic pressure within the well and allow an accelerating influx of formation fluid. If not properly controlled, this influx is known as a blowout and may result in the loss of the well, the drilling rig, and possibly the lives of those operating the rig. 
     There are two commonly used methods for controlling kicks, namely the driller&#39;s method and the engineer&#39;s method. In both methods the well is shut in and the wellbore pressure allowed to stabilize. The pressure will stabilize when the pressure at the bottom of the hole equalizes with formation pressure. The pressure indicated at the surface in the drill string and the casing annulus can be used to calculate the pressure at the bottom of the wellbore. With the well in the shut-in condition, the pressure at the bottom of the wellbore will be the formation pressure. 
     When using the driller&#39;s method, once the wellbore pressure has stabilized, the pumps are restarted and drilling fluid is circulated through the well. The pressure within the casing is maintained so that no additional formation fluids flow into the well and fluid is circulated until any gas that has entered the wellbore has been removed. A higher density drilling fluid is then prepared and circulated through the well to bring the wellbore pressures back to within the desired pressure range. Thus, when killing a kick using the driller&#39;s method, the fluid within the wellbore is fully circulated twice. 
     When using the engineer&#39;s method, as the wellbore pressure stabilizes, the formation pressure is calculated. Based on the calculated formation pressure, a mixture of higher density drilling fluid is prepared and circulated through the well to kill the kick and circulate out any formation fluids in the wellbore. During this circulation, the annulus pressure is maintained until the heavy weight drilling fluid circulates completely through the well. Using the engineer&#39;s method, the kick can be killed in a single circulation, as opposed to the two circulation driller&#39;s method. 
     The key parameter for well control is determining the formation pressure and adjusting the annulus pressure profile accordingly. If the annulus pressure is allowed to decrease below the pore pressure at a certain depth, formation fluids will enter the well. If the annulus pressure exceeds fracture pressure at a certain depth, the formation will fracture and wellbore fluids may enter the formation. Conventionally, the BHP is calculated using drill pipe and annulus pressures measured at the surface. To accurately measure these surface pressures; circulation is normally stopped to allow the BHP to stabilize and to eliminate any dynamic component of the annulus pressure. Once this occurs, the well is fully shut in. Shutting the well in uses valuable rig time and involves a drilling stoppage, which may cause other problems, such as a stuck drill string. 
     Some drilling operations seek to determine a wellbore pressure (i.e., annulus pressure and/or pore pressure) using measurement while drilling (MWD) techniques. One deficiency of the prior art MWD methods is that many tools transmit pressure measurement data back to the surface on an intermittent basis. Many MWD tools incorporate several measurement tools, such as gamma ray sensors, neutron sensors, and densitometers, and typically only one measurement is transmitted back to the surface at a time. Accordingly, the interval between pressure data being reported may be as much as two minutes. 
     Transmitting the data back to the surface can be accomplished by one of several telemetry methods. One typical prior art telemetry method is mud pulse telemetry. A signal is transmitted by a series of pressure pulses through the drilling fluid. These small pressure variances are received and processed into useful information by equipment at the surface. Mud pulse telemetry systems exhibit low bandwidths, for example between about two-tenths of a bit and about ten bits per second. Further, the velocity of sound through mud varies from about three thousand three hundred feet per second to about five thousand feet per second, meaning that the pulse could take several seconds to travel from the bottom of a deep well to the surface. Further, attenuation is significant for higher frequency pulses. Mud pulse telemetry does not work or does not work well when fluids are not being circulated, are being circulated at a slow rate, and/or when gasified drilling fluid is used. Therefore, mud pulse telemetry and therefore standard MWD tools have very little utility when the well is shut in and fluid is not circulating. 
     Although MWD tools can not transmit data via mud pulse telemetry when the well is not circulating, many MWD tools can continue to take measurements and store the collected data in memory. The data can then be retrieved from memory at a later time when the entire drilling assembly is pulled out of the hole. In this manner, the operators can learn whether they have been swabbing the well, i.e. pulling fluids into the borehole, or surging the well, i.e. increasing the annulus pressure, as the drill string moves through the wellbore. 
     Another telemetry method of sending data to the surface is electromagnetic (EM) telemetry. A low frequency radio wave is transmitted through the formation to a receiver at the surface. EM telemetry systems also exhibit low bandwidths, for example about seven bits per second. EM telemetry is depth limited, and the signal attenuates quickly in water. Therefore, with wells being drilled in deep water, the signal will propagate fairly well through the earth but it will not propagate through the deep water. Accordingly, for deep water wells, a subsea receiver would have to be installed at the mud line, which may not be practical. Further, certain formations, i.e., salt domes, also serve as EM barriers. 
     Thus, there remains a need in the art for methods and apparatuses for measuring and controlling annulus pressure (i.e., BHP) based on real-time pressure data received from a location at or near an open hole section of a wellbore being drilled. 
     SUMMARY OF THE INVENTION 
     In one embodiment, a method for drilling a wellbore includes an act of drilling the wellbore by injecting drilling fluid through a tubular string disposed in the wellbore, the tubular string comprising a drill bit disposed on a bottom thereof. The drilling fluid exits the drill bit and carries cuttings from the drill bit. The drilling fluid and cuttings (returns) flow to a surface of the wellbore via an annulus defined by an outer surface of the tubular string and an inner surface of the wellbore. The method further includes an act performed while drilling the wellbore of measuring a first annulus pressure (FAP) using a pressure sensor attached to a casing string hung from a wellhead of the wellbore. The method further includes an act performed while drilling the wellbore of controlling a second annulus pressure (SAP) exerted on a formation exposed to the annulus. 
     In another embodiment, a method for drilling a wellbore includes an act of drilling the wellbore by injecting drilling fluid into a tubular string comprising a drill bit disposed on a bottom thereof. The drilling fluid is injected at a drilling rig. The method further includes an act performed while drilling the wellbore and at the drilling rig of continuously receiving a first annulus pressure (FAP) measurement measured at a location distal from the drilling rig and distal from a bottom of the wellbore. The method further includes an act performed while drilling the wellbore and at the drilling rig of continuously calculating a second annulus pressure (SAP) exerted on an exposed portion of the wellbore. The method further includes an act performed while drilling the wellbore and at the drilling rig of controlling the SAP. 
    
    
     
       BRIEF DESCRIPTION OF THE DRAWINGS 
       So that the manner in which the above recited features of the present invention can be understood in detail, a more particular description of the invention, briefly summarized above, may be had by reference to embodiments, some of 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. 1A  is a graphical representation of a pressure vs. depth profile for a well.  FIG. 1B  illustrates a prior art casing program for drilling a narrow-margin wellbore. 
         FIG. 2  is a schematic depicting a land-based drilling system, according to one embodiment of the present invention.  FIG. 2A  illustrates a section or joint of wired casing for optional use with the drilling system of  FIG. 2 .  FIG. 2B  illustrates an offshore drilling system, according to another embodiment of the present invention. 
         FIG. 3  illustrates a drilling system, according to another embodiment of the present invention.  FIG. 3A  shows a continuous circulation system (CCS) suitable for use with the drilling system of  FIG. 3 .  FIG. 3B  shows a continuous flow sub (CFS) suitable for use with the drilling system of  FIG. 3 . 
         FIG. 4  illustrates a drilling system, according to another embodiment of the present invention. 
         FIG. 5  illustrates a drilling system, according to another embodiment of the present invention. 
         FIG. 6  illustrates a drilling system, according to another embodiment of the present invention.  FIG. 6A  illustrates a multiphase meter (MPM) suitable for use with the drilling system of  FIG. 6 .  FIGS. 6B-6D  illustrate a centrifugal separator suitable for use with the drilling system of  FIG. 6 .  FIG. 6E  illustrates a multiphase pump (MPP) suitable for use with the drilling system of  FIG. 6 . 
         FIG. 7  illustrates a drilling system, according to another embodiment of the present invention. 
         FIG. 8  is an alternate downhole configuration for use with any of the drilling systems of  FIGS. 2 ,  2 B, and  3 - 7 , according to another embodiment of the present invention.  FIG. 8A  is a cross-sectional view of a gap sub assembly suitable for use with the downhole configuration of  FIG. 8 .  FIG. 8B  illustrates an expanded view of dielectric filled threads in the gap sub assembly.  FIG. 8C  illustrates an expanded view of an external gap ring disposed in the gap sub assembly.  FIG. 8D  illustrates an expanded view of a non-conductive seal arrangement in the gap sub assembly. 
         FIG. 9  is an alternate downhole configuration for use with any of the drilling systems of  FIGS. 2 ,  2 B, and  3 - 7 , according to another embodiment of the present invention.  FIG. 9A  is an enlargement of a portion of  FIG. 9 . 
         FIG. 10A  is an alternate downhole configuration for use with any of the drilling systems of  FIGS. 2 ,  2 B, and  3 - 7 , according to another embodiment of the present invention.  FIG. 10B  is an alternate downhole configuration for use with any of the drilling systems of  FIGS. 2 ,  2 B, and  3 - 7 , according to another embodiment of the present invention.  FIG. 10C  is a partial cross section of a joint of the dual-flow drill string suitable for use with the downhole configuration of  FIG. 10B .  FIG. 10D  is a cross section of a threaded coupling of the dual-flow drill string illustrating a pin of the joint mated with a box of a second joint.  FIG. 10E  is an enlarged top view of  FIG. 10C .  FIG. 10F  is cross section taken along line  10 E- 10 F of  FIG. 10C .  FIG. 10G  is an enlarged bottom view of  FIG. 10C .  FIG. 10H  is an alternate surface/downhole configuration for use with any of the drilling systems of  FIGS. 2 ,  2 B, and  3 - 7 , according to another embodiment of the present invention. 
         FIG. 11A  is an alternate downhole configuration for use with surface equipment of any of the drilling systems of  FIGS. 2 ,  2 B, and  3 - 7 , according to another embodiment of the present invention.  FIG. 11B  illustrates a downhole configuration in which the wellbore has been further extended from the downhole configuration of  FIG. 11A . 
         FIG. 12  is an alternate downhole configuration for use with surface equipment of any of the drilling systems of  FIGS. 2 ,  2 B, and  3 - 7 , according to another embodiment of the present invention. 
         FIG. 13  is an alternate downhole configuration for use with surface equipment of any of the drilling systems of  FIGS. 2 ,  2 B, and  3 - 7 , according to another embodiment of the present invention.  FIGS. 13A-13F  are cross-sectional views of an ECDRT  1350  suitable for use with the downhole configuration of  FIG. 13 . 
         FIG. 14  is an alternate downhole configuration for use with surface equipment of any of the drilling systems of  FIGS. 2 ,  2 B, and  3 - 7 , according to another embodiment of the present invention. 
         FIG. 15  is a flow diagram illustrating operation of the surface monitoring and control unit (SMCU), according to another embodiment of the present invention. 
         FIG. 16  is a wellbore pressure profile illustrating a desired depth of  FIG. 15 . 
         FIG. 17  is a wellbore pressure gradient profile illustrating drilling windows. 
         FIG. 18A  is a pressure profile, similar to  FIG. 1A , showing advantages of one drilling mode that may be performed by any of the drilling systems of  FIGS. 2 ,  2 B, and  3 - 9 ,  10 A,  10 B,  10 H,  11 A,  11 B, and  12 - 14 .  FIG. 18B  is a casing program, similar to  FIG. 1B , showing advantages of one drilling mode that may be performed by any of the drilling systems of  FIGS. 2 ,  2 B, and  3 - 9 ,  10 A,  10 B,  10 H,  11 A,  11 B, and  12 - 14 . 
         FIG. 19  illustrates a productivity graph that may be calculated and generated by the SMCU during underbalanced drilling, according to another embodiment of the present invention. 
         FIG. 20  illustrates a completion system compatible with any of the drilling systems of  FIGS. 2 ,  2 B, and  3 - 9 ,  10 A,  10 B,  10 H,  11 A,  11 B, and  12 - 14 , according to another embodiment of the present invention. 
     
    
    
     DETAILED DESCRIPTION 
       FIG. 2  is a schematic depicting a land-based drilling system  200 , according to one embodiment of the present invention. Alternatively, the drilling system  200  could be used offshore (see  FIG. 2B ). The drilling system  200  includes a drilling rig  7 , 7   a , 7   b  that is used to support drilling operations. The drilling rig  7 , 7   a , 7   b  includes a derrick  7  supported from a support structure  7   b  having a rig floor or platform  7   a  on which drilling operators may work. Many of the components used on the rig such as an optional Kelly, power tongs, slips, draw works and other equipment are not shown for ease of depiction. A wellbore  100  has already been partially drilled, casing  115  set and cemented  120  into place. The casing string  115  extends from a surface of the wellbore  100  where a wellhead  10  would typically be located. A downhole deployment valve (DDV)  150  is installed in the casing  115  to isolate an upper longitudinal portion of the wellbore  100  from a lower longitudinal portion of the wellbore (when the drillstring  105  is retracted into the upper longitudinal portion). 
     The drill string  105  includes a drill bit  110  disposed on a longitudinal end thereof. The drill string  105  may be made up of joints or segments of tubulars threaded together or coiled tubing. The drill string  105  may also include a bottom hole assembly (BHA) (not shown) that may include such equipment as a mud motor, a MWD/LWD sensor suite, and a check valve (to prevent backflow of fluid from the annulus), etc. Alternatively, the drill string  105  may be a second casing string or a liner string. Drilling with casing or liner is discussed with  FIG. 14 , below. As noted above, the drilling process requires the use of a drilling fluid  50   f , which is stored in a reservoir or mud tank  50 . The drilling fluid  50   f  may be water, water based mud, oil, oil-based mud, foam, mist, a gas, such as nitrogen or natural gas, or a liquid/gas mixture. The reservoir  50  is in fluid communication with one or more mud pumps  60  which pump the drilling fluid  50   f  through an outlet conduit, such as pipe. If the drilling fluid  50   f  is oil or oil-based, the mud tank may have a gas line in communication with a flare  55  (see  FIG. 3 ). The outlet pipe is in fluid communication with the last joint or segment of the drill string  105  that passes through a rotating control device (RCD) or rotating blowout preventer (RBOP)  15 . A pressure sensor (PI)  25   b  or pressure and temperature (PT) sensor may be disposed in the outlet pipe and in data (i.e., electrical or optical) communication with a surface monitoring and control unit (SMCU)  65 . 
     The RCD  15  provides an effective annular seal around the drill string  105  during drilling and while adding or removing (i.e., during a tripping operation to change a worn bit) segments to the drill string  105 . The RCD  15  achieves this by packing off around the drill string  105 . The RCD  15  includes a pressure-containing housing where one or more packer elements are supported between bearings and isolated by mechanical seals. The RCD  15  may be the active type or the passive type. The active type RCD uses external hydraulic pressure to activate the sealing mechanism. The sealing pressure is normally increased as the annulus pressure increases. The passive type RCD uses a mechanical seal with the sealing action activated by wellbore pressure. If the drillstring  105  is coiled tubing or segmented tubing using a mud motor, a stripper (not shown) may be used instead of the RCD  15 . Also illustrated are conventional blow out preventers (BOPs)  12  and  14  attached to the wellhead  10 . If the RCD is the active type, it may be in communication with and/or controlled by the SMCU  65 . 
     The drilling fluid  50   f  is pumped into the drill string  105  via a Kelly, drilling swivel or top drive  17 . The fluid  50   f  is pumped down through the drill string  105  and exits the drill bit  110 , where it circulates the cuttings away from the bit  110  and returns them up an annulus  125  defined between an inner surface of the casing  115  or wellbore  100  and an outer surface of the drill string  105 . The return mixture (returns)  50   r  returns to the surface and is diverted through an outlet line of the RCD  15  and a control valve or a variable choke valve  30 . The choke  30  may be fortified to operate in an environment where the returns  50   r  contain substantial drill cuttings and other solids. The choke  30  allows the SMCU to control backpressure exerted on the annulus  125 , discussed below (see  FIGS. 18A and 18B ). A pressure (or PT) sensor  25   a  is disposed in the RCD outlet line and is in data communication with the SMCU  65 . 
     Instead of, or in addition to, the choke  30 , the density and/or viscosity of the drilling fluid  50   f  can be controlled by automated drilling fluid control systems. Not only can the density/viscosity of the drilling fluid be quickly changed, but there also may be a computer calculated schedule for drilling fluid density/viscosity increases and pumping rates so that the volume, density, and/or viscosity of fluid passing through the system is known. The pump rate, fluid density, viscosity, and/or choke orifice size can then be varied to maintain the desired constant pressure. 
     The returns  50   r  are then processed by a separator  35  designed to remove contaminates, including cuttings, from the drilling fluid  50   f . The separator  35  may be a shaker, a horizontal separator, a vertical separator, or a centrifugal separator and may separate two or more phases. The separator  35  may include an outlet line to a solids tank  45 , an outlet line to a water or oil tank  40 , an outlet line to a flare or gas recovery line  55  for gas, and an outlet line for recycled drilling fluid  50   f  (i.e., water or oil) to the drilling fluid reservoir  50 . Alternatively, a shaker may be used in parallel with a three-phase (or more) separator with an automated diverter valve between the two. During normal operation, the shaker may be selected. If the SMCU  65  detects a kick, the SMCU  65  may switch the returns to the three-phase separator to handle gas until control over the wellbore is restored. Additionally, the separator  35  may be three or more phase and may be used in tandem with a shaker  335  (see  FIG. 3 ). 
     A three-way valve (or two gate valves)  70  is placed in an outlet line of the rig pump  60  and in communication with the SMCU  65 . A bypass conduit fluidly connects the rig pump  60  with the wellhead  10  via the three-way valve  70 , thereby bypassing the inlet to the interior of drill string  105 . The three-way valve  70  allows drilling fluid  50   f  from the rig pumps  60  to be completely diverted from the drill string  105  to the annulus  125  during tripping operations to provide backpressure thereto. In operation, three-way valve  70  would select either the drill pipe conduit or the bypass conduit, and the rig pump  60  engaged to ensure sufficient flow passes through the choke  30  to be able to maintain backpressure, even when there is no flow coming from the annulus  125 . Alternatively, a separate pump (not shown) may be used instead of the three-way valve  70  to maintain pressure control in the annulus  125 . Alternatively, a secondary fluid may be pumped or injected into the annulus  125  instead of drilling fluid  50   f.    
     Additionally, a single phase (FM) or multi-phase flow meter (MPM) (not shown, see  FIG. 6A ) may be provided in the RCD outlet line upstream of the choke  30 . The FM or MPM may be a mass-balance type or other high-resolution flow meter. Utilizing the FM or MPM, an operator will be able to determine how much drilling fluid  50   f  has been pumped into the wellbore  100  through drill string  105  and the amount of returns  50   r  exiting the wellbore  100 . Based on differences in the amount of fluid  50   f  pumped versus returns  50   f  recovered, the operator is able to determine whether returns  50   r  are being lost to a formation surrounding the wellbore  100 , which may indicate that formation fracturing has occurred, i.e., a significant negative fluid differential. Likewise, a significant positive differential would be indicative of formation fluid entering into the well bore (a kick). Additionally, an FM/MPM (not shown) may be provided in the outlet line of the rig pump  60 . Alternatively, an FM may be placed in each outlet line from the separator  35 . 
     The DDV  150  includes a tubular housing  152 , a flapper  160  having a hinge at one end, and a valve seat in an inner diameter of the housing  152  adjacent the flapper  160 . Alternatively, a ball valve (not shown) may be used instead of the flapper  160 . The housing  152  may be connected to the casing string  115  with a threaded connection, thereby making the DDV  150  an integral part of the casing string  115  and allowing the DDV  150  to be run into the wellbore  100  along with the casing string  115  prior to cementing. Alternatively, see ( FIGS. 11A and 11B ) the DDV  150  may be run in on a tie-back casing string. The housing  152  protects the components of the DDV  150  from damage during run in and cementing. Arrangement of the flapper  160  allows it to close in an upward fashion wherein pressure in a lower portion of the wellbore will act to keep the flapper  160  in a closed position. The DDV  110  is in communication with a surface monitoring and control unit (SMCU)  65  to permit the flapper  160  to be opened and closed remotely from the surface  5  of the well  100 . The DDV  150  further includes a mechanical-type actuator  155  (shown schematically), such as a piston, and one or more control lines  170   a,b  that can carry hydraulic fluid, electrical currents, and/or optical signals. As shown, line  170   a  includes a data line and a power line and line  170   b  is a hydraulic line. Clamps (not shown) can hold the control lines  170   a,b  next to the casing string  115  at regular intervals to protect the control lines  170   a,b . Alternatively, the casing string  115  may be a wired casing string  215  (see  FIG. 2A ). 
     The flapper  160  may be held in an open position by a tubular sleeve (not shown, a.k.a. a flow tube) coupled to the piston. The flow tube may be longitudinally moveable to force the flapper  160  open and cover the flapper  160  in the open position, thereby ensuring a substantially unobstructed bore through the DDV  150 . The hydraulic piston is operated by pressure supplied from the control line  170   b  and actuates the flow tube. Alternatively, the flow tube may be actuated by interactions with the drill string based on rotational or longitudinal movements of the drill string, the DDV  150  may include a sensor that detects the drill string  105  or receives a signal from the drill string  105 , the flow tube may include a magnetic coupling that interacts with a magnetic coupling on the drill string  105 , the DDV  150  may be actuated by pressure in the tie-back annulus in a tie-back installation, or the DDV  150  may include an electric motor instead of a hydraulic actuator. Additionally, the DDV  150  may include a series of slots and pins (not shown) so that the DDV may be selectively locked into an opened or closed position. A valve seat (not shown) in the housing  152  receives the flapper  160  as it closes. Once the flow tube longitudinally moves out of the way of the flapper  160  and the flapper engaging end of the valve seat, a biasing member (not shown) may bias the flapper  160  against the flapper engaging end of the valve seat. The biasing member may be a spring or a gas charge. Alternatively, a second control line may be provided instead of the biasing member to actuate the flow tube. In addition to the biasing member, a second control line may be provided as a balance line. 
     The DDV  150  may further include one or more pressure (or PT) sensors  165   a, b . As shown, an upper pressure sensor  165   a  is placed in an upper portion of the wellbore  100  (above the flapper  160 ) and a lower pressure sensor  165   b  placed in the lower portion of the wellbore (below the flapper  160  when closed). The upper pressure sensor  165   a  and the lower pressure sensor  165   b  can determine a fluid pressure within an upper portion and a lower portion of the wellbore, respectively. Additional sensors (not shown) may optionally be located in the housing  152  of the DDV  150  to measure any wellbore condition or DDV parameter, such as a position of the flow tube and the presence or absence of a drill string. The additional sensors can determine a fluid composition, such as an oil to water ratio, an oil to gas ratio, or a gas to liquid ratio. The sensors may be connected to a controller (not shown) in the DDV  150 . Power supply to the controller and data transfer therefrom to the SMCU  65  is achieved by the control line  170   a.    
     When the drill string  105  is moved longitudinally above the DDV  150  and the DDV  150  is in the closed position, the upper portion of the wellbore  100  is isolated from the lower portion of the wellbore  100  and any pressure remaining in the upper portion can be bled out through the choke valve  30  at the surface  5  of the wellbore  100 . Isolating the upper portion of the wellbore facilitates operations such as inserting or removing a bottom hole assembly of the drill string  105 . The BHA may include a bit, mud motor, MWD and/or LWD devices, rotary steering devices, etc. In later completion stages of the wellbore  100 , equipment, such as perforating systems, screens, and slotted liner systems may also be inserted/removed in/from the wellbore  100  using the DDV  150 . Because the DDV  150  may be located at a depth in the wellbore  100  which is greater than the length of the BHA or other equipment, the BHA or other equipment can be completely contained in the upper portion of the wellbore  100  while the upper portion is isolated from the lower portion of the wellbore  100  by the DDV  150  in the closed position. 
     Prior to opening the DDV  150 , fluid pressures in the upper portion of the wellbore  100  and the lower portion of the wellbore  100  at the flapper  160  in the DDV  150  must be equalized or nearly equalized to effectively and safely open the flapper  160 . Usually, the upper portion will be at a lower pressure than the lower portion. Based on data obtained from the pressure sensors  165   a,b  by the SMCU  65 , the pressure conditions and differentials in the upper portion and lower portion of the wellbore  100  can be accurately equalized prior to opening the DDV  150 , for example, by using the mud pump  60  and the three-way valve  70 . Alternatively, instead of the DDV  150 , an instrumentation sub including a pressure (or PT) sensor without the valve may be used. 
     The sensors  165   a, b  may be electro-mechanical sensors that use strain gages mounted on a diaphragm in a Whetstone bridge configuration or solid state piezoelectric or magnetostrictive materials. Alternatively, the sensors  165   a,b  may be optical sensors, such as those described in U.S. Pat. No. 6,422,084, which is herein incorporated by reference in its entirety. For example, the optical sensors  165   a,b  may comprise an optical fiber, having the reflective element embedded therein; and a tube, having the optical fiber and the reflective element encased therein along a longitudinal axis of the tube, the tube being fused to at least a portion of the fiber. Alternatively, the optical sensor  362  may comprise a large diameter optical waveguide having an outer cladding and an inner core disposed therein. Alternatively, the sensors  165   a, b  may be Bragg grating sensors which are described in commonly-owned U.S. Pat. No. 6,072,567, entitled “Vertical Seismic Profiling System Having Vertical Seismic Profiling Optical Signal Processing Equipment and Fiber Bragg Grafting Optical Sensors”, issued Jun. 6, 2000, which is herein incorporated by reference in its entirety. Construction and operation of the optical sensors suitable for use with the DDV  150 , in the embodiment of an FBG sensor, is described in the U.S. Pat. No. 6,597,711 issued on Jul. 22, 2003 and entitled “Bragg Grating-Based Laser”, which is herein incorporated by reference in its entirety. Each Bragg grating is constructed so as to reflect a particular wavelength or frequency of light propagating along the core, back in the direction of the light source from which it was launched. In particular, the wavelength of the Bragg grating is shifted to provide the sensor. 
     The optical sensors may also be FBG-based inferometric sensors. An embodiment of an FBG-based inferometric sensor which may be used as the optical sensors  165   a, b  is described in U.S. Pat. No. 6,175,108 issued on Jan. 16, 2001 and entitled “Accelerometer featuring fiber optic bragg grating sensor for providing multiplexed multi-axis acceleration sensing”, which is herein incorporated by reference in its entirety. The inferometric sensor includes two FBG wavelengths separated by a length of fiber. Upon change in the length of the fiber between the two wavelengths, a change in arrival time of light reflected from one wavelength to the other wavelength is measured. The change in arrival time indicates pressure measured by one of the sensors. 
     The SMCU  65  may include a hydraulic pump and a series of valves utilized in operating the DDV  150  by fluid communication through the control line  170   b . The SMCU  65  may also include a hydraulic, pneumatic, or electrical unit for operating the choke  30 . The SMCU  65  may also include a programmable logic controller (PLC) based system or a central processing unit (CPU) based system for monitoring and controlling the DDV and other parameters, circuitry for interfacing with downhole electronics, an onboard display, and standard interfaces (not shown), such as RS-232 or USB, for interfacing with external devices, such as a laptop computer and/or other rig equipment. In this arrangement, the SMCU  65  outputs information obtained by the sensors and/or receivers in the wellbore to the display. Using the arrangement illustrated, the pressure differential between the upper portion and the lower portion of the wellbore can be monitored and adjusted to an optimum level for opening the DDV. In addition to pressure information near the DDV, the system can also include proximity sensors that describe the position of the sleeve in the valve that is responsible for retaining the valve in the open position. By ensuring that the sleeve is entirely in the open or the closed position, the valve can be operated more effectively. A satellite, microwave, or other long-distance data transceiver or transmitter  75  may be provided in electrical communication with the SMCU  65  for relaying information from the SMCU  65  to a satellite  80  or other long-distance data transfer medium. The satellite  80  relays the information to a second transceiver or receiver where it may be relayed to the Internet or an intranet for remote viewing by a technician or engineer. 
     Conventionally, an operator monitors the pressure gauge  25   a  at the surface. However, there is a delay in the surface readings based on bottomhole pressure because the effect of changes in the downhole pressure must propagate to the surface (at the speed of sound). Thus, the adjustment of pumping rates is being performed on a delayed basis relative to the actual pressure changes at the bottom of the hole. However, if the pressure measurements are taken downhole in real-time, the downhole pressure is read substantially instantaneously and the ability to control the well is improved. 
       FIG. 2A  illustrates a section or joint  215   j  of wired casing for optional use with the drilling system  200 . The joint has a longitudinal groove  221  formed therein. The joint includes a coupling  215   c  at a first end thereof having a longitudinal groove  222  formed therein and threads at a second end thereof for connection to other identical joints. The grooves  221  and  222  may be sub-flushed to the surface of the joint  215   j  and coupling  215   c , respectively. Additionally, one or more clamps  230  may be disposed in the groove  221 . The joint  215   j  and the coupling  215   c  connected by a threaded connection so that the grooves  221 ,  222  are aligned with one another to form a continuous groove along the length of the joint  215   j  and the coupling  215   c . Alternatively, the coupling  215   c  may welded to the joint  215   j . The grooves  221 ,  222  are designed to receive and house one or more control lines  170   a, b . The groove  222  of the coupling  215   c  slopes upward from the groove  121  of the joint  215   j  as the coupling  215   c  is larger in diameter than the joint  215   j  so that the male threads of the joint  215   j  may be housed within the female threads of coupling  215   c . Accordingly, the control lines  170   a, b  ramp upward from the joint  215   j  to the coupling  215   c  when disposed within the grooves  221 ,  222 . Correspondingly, the control lines  170   a, b  will ramp downward into the groove of the second joint. Alternatively, the wired joint may include a bore formed (i.e., gun drilled) longitudinally through the wall of the joint for disposal of an electric line therein. The alternative wired joint would then communicate with other wired joints via inductive couplings, discussed below regarding  FIG. 9  (or alternatives discussed therewith). 
       FIG. 2B  illustrates an offshore drilling system  250 , according to another embodiment of the present invention. A floating vessel  255  is shown but other offshore drilling vessels may be used. Surface equipment similar to that of drilling system  1  or  200  may be included on the vessel  255 . A tubular riser string  268  is normally used to interconnect the floating vessel  255  and a wellhead  260  disposed on the sea floor  259 . The riser string  268  conducts returns  50   r  back to the floating vessel  255  during drilling through an annulus created between the riser string  268  and the drillstring  105 . The riser string  268  is exaggerated for clarity. Also connected to the wellhead are two or more ram-BOPs  262  and an annular BOP  266 . A riser bypass valve  264  is also connected to the wellhead  260 . A bypass line  265  extends from the bypass valve  264  to the floating vessel  255 . When adding or removing a segment to or from the drill string  105 , drilling fluid  50   f  may be injected via the bypass line  265  and bypass valve  264  or via the riser string  268 . 
     Alternatively, instead of disposing the DDV  150  with pressure sensors  165   a, b , or a pressure sensor in the casing string  115 , a pressure (or PT sensor) (not shown) may be attached to the riser string  268  in fluid communication with an annulus defined between the riser string  268  and the drill string  105 . A control line may then place the riser pressure sensor in data communication with the SMCU  65 . The riser pressure sensor may be attached to the riser  268  at or near a bottom of the riser or instead be disposed in the wellhead  260 . Additionally, the riser/wellhead pressure sensor may be used with the DDV  150  (with pressure sensors  165   a, b ) and/or a pressure sensor in the casing string  115 . 
       FIG. 3  illustrates a drilling system  300 , according to another embodiment of the present invention. Although shown simply, the downhole configuration may be similar to that of the drilling system  200 . As compared to the drilling system  200 , a continuous circulation system (CCS)  350  or a continuous flow sub (CFS)  350   b  is used instead of the three-way valve  70  to maintain pressure control of the annulus during tripping of the drill string  105 . The CCS  350   a  or the CFS  350   b  allows circulation of drilling fluid through the drill string  105  to be maintained during tripping of the drill string  105 . Additionally, the CCS/CFS  350   a, b  may be used with the three-way valve  70 . Alternatively, the CCS/CFS  350   a, b  may be used without the choke valve  30 . In this alternative, a variable speed drive may be installed in the prime mover or a control valve or variable choke valve (not shown) could be installed on the outlet line of the rig pump  60  to vary an injection rate of the drilling fluid to control annulus pressure during drilling instead of applying back pressure with the choke valve  30 . 
       FIG. 3A  shows a suitable CCS  350   a . The CCS  350   a  includes a platform  314  movably mounted to and above the rig floor  7   a . Each of two cylinders  316  has a movable piston  318  movable to raise and lower the platform  314  to which other components of the CCS  350   a  are connected. Any suitable piston/cylinder may be used for each of the cylinders  316 /pistons  318  with suitable known control apparatuses, flow lines, consoles, switches, etc. so that the platform  314  is movable by an operator or automatically. Movement of the platform  314  may be guided and controlled by a bushings secured to the platform  314  which may slide along guide posts attached to the rig floor  7   a . The top drive or the swivel  17  is connected to a segment  305   a  which will be connected to the drill string  105 . An optional saver sub is interconnected between the top drive  17  and the segment  305   a.    
     A spider  322  including, but not limited to, known flush-mounted spiders, or other apparatus extends beneath the rig floor  7   a  and accommodates movable slips  324  for releasably engaging and holding the drill string  105  extending down from the rig floor  7   a  into the wellbore  100 . The spider  322 , in one aspect, may have keyed slips, e.g. slips held with a key that is received and held in recesses in the spider body and slip so that the slips do not move or rotate with respect to the body. 
     The CCS  350   a  has upper control head  327   a  and lower control head  327   b . These may be known commercially available rotating control heads. The drill segment  305   a  is passable through a stripper seal  334  of the upper control head  327   a  to an upper chamber  343  and an upper portion of the drill string  105  passes through a stripper seal  336  of the lower control head  327   b  to a lower chamber  345 . The segment  305   a  is passable through an upper sabot or inner bushing  338 . The upper sabot  338  is releasably held within the upper chamber by an activation device  340 . Similarly, the upper portion of the drill string  105  passes through a lower sabot or inner bushing  342 . 
     The CCS  350   a  further includes upper  344  and lower  346  housings. Within housings  344 , 346  are, respectively, the upper chamber  343  and the lower chamber  345 . The stripper seals  334 , 336  seal around the drill string segment  305   a  and drill sting  105  and wipe them. The sabots or inner bushings  338 ,  342  protect the stripper seals  334 , 336  from damage due to the drill string segment  305   a  and drill sting  105  passing through them. The sabots  338 , 342  also facilitate entry of the drill string segment  305   a  and drill sting  105  into the stripper seals  334 , 336 . 
     Movement of the upper sabot or inner bushing  338  with respect to the stripper seal  334  is accomplished by the activation device  340  which, in one aspect, involves the expansion or retraction of one or more pistons  349  of one or more cylinders  351 . The cylinders  351  are secured to clamp parts (which are releasably clamped together) of the control head  327   a . The pistons  349  are secured, respectively, to a ring  356  to which the upper sabot  338  is also secured. The pistons  349 /cylinders  351  may be any known suitable cylinder/piston assembly with suitable known control apparatuses, flow lines, switches, consoles, etc. so that the sabots are selectively movable by an operator (or automatically) as desired, e.g. to expand and protect the upper stripper seal  334  during drill string  105 /segment  305   a  passage therethrough, then to remove the upper sabot  338  to permit the upper stripper seal  334  to seal against the drill string  105 /segment  305   a . A second activation device (not shown) is also provided for the lower control head  327   b.    
     Disposed between the housings  344 ,  346  is a gate valve  320  which includes a movable gate  320   a  therein to sealingly isolate the upper chamber  343  from the lower chamber  345 . Joint connection and disconnection may be accomplished in the lower chamber  345  or in the upper chamber  343 . The gate valve  320  defines a central chamber  320   b  within which the connection and disconnection the drill string  105 /segment  305   a  can be accomplished. A power tong  328   a  may be isolated from axial loads imposed on it by the pressure of fluid in the chamber(s). In one aspect lines, e.g. ropes or cables, or fluid operated (pneumatic or hydraulic) cylinders connect the tong  328   a  to the platform  314 . In another aspect of a gripping device such as, but not limited to a typical rotatably mounted snubbing spider, grips the segment  305   a  below the tong  328   a  and above the upper control head  327   a  or above the tong  328   a , the snubbing spider connected to the platform  314  to take the axial load and prevent the tong  328   a  from being subjected to it. Alternatively, the tong  328   a  may have a jaw mechanism that can handle axial loads imposed on the tong  328   a . The drill string  105  may be rotationally restrained by a backup tong  328   b.    
       FIG. 3A  also illustrates a power/control circuit for the CCS  350   a . Drilling fluid  50   f  is pumped from the reservoir  50  by the pump  60  through a line and is selectively supplied to the lower chamber  345  with valves  303   b - e  closed and a valve  303   a  open. Drilling fluid  50   f  is selectively supplied to the upper chamber  343  with the valves  303   a,c -e closed and the valve  303   b  open. Fluid  50   f  in both chambers  343 ,  345  is allowed to equalize by opening valve  303   d  with valves  303   c,e  closed. By providing fluid  50   f  to at least one of the chambers  343 ,  345  when the chambers are isolated from each other or to both chambers when the gate valve  320  is open, continuous circulation of fluid  50   f  is maintained to the drill string  105  through the upper portion thereof. This is possible with the gate valve  320  opened (when the drill string  105 /segment  305   a  ends are separated or joined); with the gate valve  320  closed (with flow through the lower chamber  345  into the upper portion of the drill string  105 ); or from the upper chamber  343  into the lower chamber  345  when the gate valve  320  is closed. An optional control valve or variable choke valve  330  or fixed choke (not shown) is provided to prevent damage to the CCS  350   a . The choke valve  330  may be in communication with the SMCU  65 . An optional pressure sensor  325  is provided in or near an outlet side of the choke valve  330  and is also in communication with the SMCU  65 . The gate valves  303   a - e ,  320  may be automatically actuated by, and in communication with, the SMCU  65 . 
     Operation of the CCS  350   a , where  17  is the top drive, in a disassembly or break out operation of the drill string  105  is as follows. The top drive  17  is stopped with a joint to be broken positioned within a desired chamber of the CCS  350   a  or at a position at which the CCS  350   a  can be moved to correctly encompass the joint. By stopping the top drive  17 , rotation of the drill string  105  string ceases and the string is held stationary. The spider  322  is set to hold the string  105 . Optionally, although the continuous circulation of drilling fluid  50   f  is maintained, the rate can be reduced to the minimum necessary, e.g. the minimum necessary to suspend cuttings. If necessary, the height of the CCS  350   a  with respect to the joint to be broken out is adjusted. If the CCS  350   a  includes upper and lower BOPs, they are now set. 
     The drain valve  303   e  is closed so that fluid may not drain from the chambers of the CCS  350   a  and the balance valve  303   d  is opened to equalize pressure between the upper  343  and lower  345  chambers of the CCS  350   a . At this point the gate valve  320  is open. The valve  303   b  is opened to fill the upper  343  and lower  345  chambers with drilling fluid  50   f . Once the chambers  343 , 345  are filled, the valve  303   b  is closed and the valve  303   a  is opened so that the pump  60  maintains pressure in the system and fluid circulation to the drill string  105 . The power tong  328   a  and lower back-up tong  328   b  now engage the string  105  and the top drive  17  and/or power tong  328   a  apply torque to the segment  305   a  (engaged by the power tong  328   a ) to break its joint with the upper portion of the drill string  105  held by the back-up  328   b ). Once the joint is broken, the top drive  17  spins out the segment  305   a  from the upper portion of the drill string  105 . 
     The segment  305   a  (and any other tubulars connected above it) is now lifted so that its lower end is positioned in the upper chamber  343 . The gate valve  320  is now closed, isolating the upper chamber  343  from the lower chamber  345 , with the upper portion of the drill string  105  held in position in the lower chamber  345  by the back-up  328   b  (and by the slips  322 ). The valve  303   c  (previously open to permit the pump to circulate fluid to the top drive  17  and from it into the drill string) and the balance valve  303   d  are now closed. The drain valve  303   e  is opened and fluid is drained from the upper chamber  343 . The upper BOP&#39;s seal (if present) is released. The power tong  328   a  and back-up tong  328   b  are released from their respective tubulars and the segment  305   a  (which may be a plurality of segments) is lifted with the top drive  17  out from the upper chamber  343  while the pump  60  maintains fluid circulation to the drill string  105  through the lower chamber  345 . 
     An elevator (not shown) is attached to the segment  305   a  and the top drive  17  separates the drill stand from a saver sub. The separated segment  305   a  is moved into the rig&#39;s pipe rack with any suitable known pipe movement/manipulating apparatus. A typical breakout wrench or breakout foot (not shown) typically used with a top drive  17  is released from gripping the saver sub and is then retracted upwardly. The saver sub or pup joint is then lowered by the top drive  17  into the upper chamber  343  and is engaged by the power tong  328   a . The upper BOP (if present) is set. The drain valve  303   e  is closed, the valve  303   b  is opened, and the upper chamber  343  is pumped full of drilling fluid  50   f . Then the valve  303   b  is closed, the valve  303   c  is opened, and the balance valve  303   d  is opened to balance the fluid in the upper  343  and lower  345  chambers. 
     The gate valve  320  is now opened and the power tong  328   a  is used to guide the saver sub into the lower chamber  343   b  and then the top drive  17  is rotated to connect the saver sub to the upper portion of the drill string  105  (positioned and held in the lower chamber  345 ). Once the connection has been made, the top drive  17  is stopped, the valve  303   a  is opened, the drain valve  303   e  is opened, and the upper and lower BOPs (if present) and the power tong  328   a  are released. The spider  322  is released, releasing the drill string  105  for raising by the top drive  17 . Then the break-out sequence described above is repeated. A make-up operation may be accomplished by reversing the break-out operation. 
       FIG. 3B  shows a suitable continuous flow sub (CFS)  350   b . The CFS  350   b  is installed atop each stand (not shown) of drill string  105  instead of being a single unit stationed on the rig  7  as is the CCS  350   a . Each stand and CFS  350   b  is then assembled with the drill string  105  and is inserted into the wellbore  100 . The CFS  350   b  includes a tubular housing  355  which is similar to the tubulars that make up the drill string  105 . A bore  360   a  is formed longitudinally through the housing  355  and a side port  360   b  is formed through a wall of the housing  355 . A first valve  365   a  is disposed in the bore  360   a  and a second valve  365   b  is disposed in the port  360   b . Each valve is movable between an open and a closed position. As shown, the first valve  365   a  is a check valve having a flapper  370  which opens when drilling fluid is injected through the bore  360   a  from the mud pump  60  and which closes in response to fluid injected through the side port  360   b . Alternatively, the first valve  365   a  may be a ball valve (a.k.a. a Kelly valve). 
     Also as shown, the second valve  365   b  is a pressure activated poppet valve. A side circulation line (not shown) is connected to the side port  360   b  and the mud pump  60  so that drilling fluid  50   f  may be injected through the side port  360   b  when adding/removing a segment of the drill string  105  (above the CFS  350   b ). When drilling fluid  50   f  is injected through the side port  360   b , the second valve  360   b  is forced open and allows flow through the side circulation line and into the bore  360   a , thereby maintaining circulation through the drill string  105 . When drilling fluid  50   f  is injected through the bore  360   a  during drilling, the valve second  365   b  closes and seals the side port  360   a . A valve manifold (not shown) diverts drilling fluid  50   f  from the Kelly/top drive  17  to the side port  360   b  during connections. The valve manifold may be controlled by the SMCU  65  and/or manual control system through hydraulic or pneumatic actuators. 
     Alternatively, a hydraulically actuated sliding sleeve may be used instead of the poppet valve as discussed in the &#39;539 Provisional. Alternatively, a downhole CCS may be used instead of the CFS  350   b  as also discussed in the &#39;539 Provisional. An alternate configuration of the poppet valve discussed in the &#39;539 Provisional may be used instead of the poppet valve  365   b . Alternatively, a prior art single flapper sub or single 3-way ball valve as also discussed in the &#39;539 Provisional may be used instead of the CFS  350   b.    
       FIG. 4  illustrates a drilling system  400 , according to another embodiment of the present invention. Compared to the drilling system  200  of  FIG. 2 , an accumulator tank  480  has been added to replace the three-way valve  70 . The accumulator tank  480  is in fluid communication with the rig pump outlet line via an inlet line having a control valve or variable choke valve  430  which is in communication with the SMCU  65 . A pressure sensor  425  is disposed in the inlet line or on the accumulator and is also in communication with the SMCU  65 . An automated gate valve  470  in communication with the SMCU  65  is disposed in an outlet line of the accumulator  480 . The accumulator outlet line is in fluid communication with the wellhead  10 . In operation, the SMCU  65  charges the accumulator  480  to a set pressure during drilling operations by controlling the choke valve  430 . The set pressure is calculated by the SMCU  65  during drilling in order to maintain a desired annulus pressure at a certain downhole depth, i.e. the bottom hole pressure, during tripping of the drill string  105 . Once circulation has stopped to add or remove a segment (or just before stopping circulation), the SMCU  65  closes the choke valve  30  and opens the valve  470  to pressurize the annulus  125  to the set pressure. Once circulation is resumed (or just before), the valve  470  is closed and the choke  30  is opened. The timing of opening and closing of each of the valves is coordinated by the SMCU  65  to ensure that deviations from the desired annulus pressure are minimized. 
       FIG. 5  illustrates a drilling system  500 , according to another embodiment of the present invention. Compared to the drilling system  200  of  FIG. 2 , the choke valve  30  and pressure sensor  25   a  have been moved to a gas outlet line of the separator  35  and a gate valve  591  has been placed in the RCD outlet. Alternatively, gate valve  591  may be a choke valve and be used for start-up, shut-down, and unpredicted flow operations. The three-way valve  70  and bypass line have been removed. The choke valve  30  maintains a desired pressure in the separator  35 . Control valves or variable choke valves  593   a,b  have been placed in the liquid outlet lines of the separator  35  and are in communication with the SMCU  65 . Level sensors  595   a,b , also in communication with the SMCU, have been disposed in liquid chambers of the separator  35 . The level sensors  595   a,b  and choke valves  593   a,b  allow the SMCU  65  to monitor and control liquid levels in the separator  35 . In this manner, the SMCU  65  may maintain a constant gas volume (for a given desired pressure) in the separator  35  for more precise pressure control. The level sensors  595   a,b  and choke valves  593   a,b  may also be optionally included in the systems  200 ,  250 ,  300 , and  400  of  FIGS. 2 ,  2 B,  3 , and  4 . 
     The choke valve  30  applies backpressure to the annulus  125  during drilling by maintaining the desired pressure in the separator  35 . Advantageously, since solids have been removed from the returns  50   r , the choke valve  30  is not subject to erosion as in the drilling system  200 . Further, controlling the annulus pressure with a compressible medium dampens transient effects of pressure changes. Additionally, if gas hydrates are present in the return fluid they are separated with the rest of the solids and sublimation may carefully be controlled (i.e., with a heating element in the separator  35  or solids tank  45 ) instead of uncontrolled through the choke valve  30 . An optional compressor  560 , gas source/tank  550 , and variable choke valve  596  are provided in fluid communication with the gas outlet line of the separator  35  to maintain annulus pressure control during drilling when the formation is not producing gas and/or the drilling fluid is not gas based. Alternatively, the choke valve  596  may be placed in the RCD outlet instead of using the compressor  560  and/or gas tank  550 . 
     The gas source  550  may be a nitrogen tank. Alternatively, the gas source  550  may be a nitrogen generator, exhaust fumes from the prime mover, or a natural gas line. The gas source  550  may be sufficiently pressurized so that the compressor  560  is not required. Annulus pressure control may be maintained during tripping operations by using the compressor  598  and/or the alternative gas source  550 , by including the CCS/CFS  350   a,b  or by including the three-way valve  70  (see  FIG. 2 ) and bypass line from/in the outlet line of the rig pump  60 . A bypass line, including gate valve  532 , is provided to the wellhead  10  for servicing the wellhead equipment. Otherwise, the valve  232  is normally closed. 
       FIG. 6  illustrates a drilling system  600 , according to another embodiment of the present invention. Although shown simply, the downhole configuration may be similar to that of the drilling system  200 . The drilling system  600  is capable of injecting a multiphase drilling fluid  50   f , i.e. a liquid/gas mixture. The liquid may be oil, oil based mud, water, or water based mud, and the gas may be nitrogen or natural gas. Returns  50   r  exiting an outlet line of the RCD  15  are measured by a multi-phase meter (MPM)  610   a . The MPM  610   a  is in communication with the SMCU  65  and may provide a pressure (or pressure and temperature) at the RCD outlet to the SMCU  65  in addition to component flow rates, discussed below. The returns  50   r  continue through the RCD outlet line through the optional choke  30  which controls back pressure exerted on the annulus  125  and is in communication with the SMCU  65 . The returns  50   r  flow through the choke  30  and into a separator  635 . As shown, the separator  635  is two-phase. Alternatively, the separator  635  may be three or four phase. The liquid level in the separator is monitored and controlled by the level sensor  595  and choke  593  which are both in communication with the SMCU  65 . 
     The liquid and cuttings portion of the returns  50   r  exits the separator  635  through a liquid outlet line and through the choke  593  disposed in the liquid outlet line. The liquid and cuttings continue through the liquid line to shakers  650  which remove the cuttings and into a mud reservoir or tank  650 . The liquid portion of the returns  50   r  may then be recycled as drilling fluid  50   f . An additional flare or cold vent line (not shown, see  FIG. 3 ) may be provided on the mud tank  650  if the liquid portion of the drilling fluid  50   f  is oil or oil based. Alternatively, the cuttings may be removed at the separator  635 . Liquid drilling fluid may be pumped from the mud tank  650  by an optional charge pump  661  into an inlet line of a multi-phase pump (MPP)  660 . Alternatively, the MPP  660  or a compressor may be disposed in the gas outlet line of the separator  635  and a conventional mud pump may be disposed in the mud tank outlet line. 
     The gas portion of the returns  50   r  exits the separator  635  through a gas outlet line. The gas outlet line splits into two branches. A first branch leads to an inlet line of the MPP  660  so that the gas portion of the returns  50   r  may be recycled. The second branch leads to a gas recovery system or flare  55  to dispose or recover excess gas produced in the wellbore  100 . Flow is distributed between the two branches using chokes  530   a,b  which are both in communication with the SMCU. The first branch of the gas outlet line and an outlet line of the mud tank  650  join to form the inlet line of the MPP  660 . The SMCU  65  controls the amount of gas entering the MPP inlet line, thereby controlling the density of the drilling fluid mixture  50   f , to maintain a desired annulus pressure profile. A gas storage tank (not shown) may also be provided for start-up and other transient operations. The drilling fluid mixture  50   f  exits the MPP  660  and flows through an MPM  610   b  which is in communication with the SMCU. The CFS/CCS  350   a,b  maintains circulation and thus annulus pressure control during tripping of the drill string. 
       FIG. 6A  illustrates a suitable MPM  610 . The MPM  610  is capable of measuring the component mass flow rates of a multiphase fluid, i.e. gas, oil, and water. Additionally, the MPM  610  may be configured to measure a component flow rate of solids, the component flow rate of solids may be neglected, or the flow rate of solids may be calculated by measuring the amount of solids disposed in the solids tank  45 , i.e., using a load cell. The MPM  610  includes a pipe section comprising a convergent Venturi  611  whose narrowest portion  612  is referred to as the throat. The constriction of the flow section in the Venturi induces a pressure drop Δp between level  613 , situated upstream from the Venturi at the inlet to the measurement section, and the throat  612 . The pressure drop Δp is measured by means of a differential pressure sensor  615  connected to two pressure takeoffs  616  and  617  opening out into the measurement section respectively at the upstream level  613  and in the throat  612  of the Venturi. Additionally/alternatively, as discussed above, absolute pressure measurements may be made at the takeoffs  616  and  617 . 
     The density of the returns/drilling fluid mixture  50   f, r  is determined by a sensor which measures the attenuation of gamma rays, by using a source  620  and a detector  621  placed on opposite sides of the Venturi throat  612 . The throat  612  is provided with “windows” of a material that shows low absorption of photons at the energies under consideration. The source  620  produces gamma rays at two different energy levels Whi and Wlo, referred to below as the “high energy” level and as the “low energy” level. The detector  621  which comprises in conventional manner a scintillator crystal such as NaI and a photomultiplier produces two series of signals and referred to as count rates, representative of the numbers of photons detected per sampling period in the energy ranges bracketing the above-mentioned levels respectively. 
     These energy levels are such that the high energy count rate is essentially sensitive to the density of the fluid mixture, while the low energy count rate is also sensitive to the composition thereof, thus making it possible to determine the water content of the liquid phase. The high energy level may lie in a range 85 keV to 150 keV. For characterizing oil effluent, this energy range presents the remarkable property that the mass attenuation coefficient of gamma rays therein is substantially the same for water, for sodium chloride, and for oil. This means that based on the high energy attenuation, it is possible to determine the density of the fluid mixture without the need to perform auxiliary measurements to determine the properties of the individual phases of the fluid mixture (attenuation coefficients and densities). 
     A material that is suitable for producing high energy gamma rays in the energy range under consideration, and low energy rays is gadolinium  153 . This radioisotope has an emission line at an energy that is approximately 100 keV (in fact there are two lines around 100 keV, but they are so close together they can be treated as a single line), and that is entirely suitable for use as the high energy source. Gadolinium  153  also has an emission line at about 40 keV, which is suitable for the low energy level that is used to determine water content. This level provides good contrast between water and oil, since the attenuation coefficients at this level are significantly different. 
     A pressure sensor  622  connected to a pressure takeoff  623  opening out into the throat  612  of the Venturi, which sensor produces signals representative of the pressure pv in the throat of the Venturi, and a temperature sensor  624  producing signals T representative of the temperature of the fluid mixture. The data pv and T is used in particular for determining gas density under the flow rate conditions and gas flow rate under normal conditions of pressure and temperature on the basis of the value for the flow rate under the flow rate conditions. 
     The information coming from the above-mentioned sensors is applied to a data processing unit (DPU)  665  which includes a microprocessor controller running a program to calculate the total mass flow rate of the mixture by: determining a mean value of the pressure drop is over a period t 1  corresponding to a frequency f 1  that is low relative to the frequency at which gas and liquid alternate in a slug flow regime; determining a mean value for the density of the fluid mixture at the constriction of the Venturi over said period t 1 ; and deducing a total mass flow rate value for the period t 1  under consideration from the mean values of pressure drop and of density. Appropriately, the density of the fluid mixture is measured by gamma ray attenuation at a first energy level at a frequency f 2  that is high relative to said frequency of gas/liquid alternation in a slug flow regime, and the mean of the measurements obtained in this way over each period t 1  corresponding to the frequency f 1  is formed to obtain said mean density value. Once the total mass flow rate is calculated, the DPU  665  may proceed to calculate the mass flow rates of the individual components. Alternatively, the SMCU  65  may perform the calculations. 
     As discussed above, having MPMs  610   a, b  measuring both the drilling fluid injected into the wellbore and returns exiting the wellbore allows for kick detection and/or lost circulation detection when drilling balanced or overbalanced. Further, when drilling underbalanced, the MPM measurements allow for formation evaluation while drilling, discussed more below. Alternatively, instead of MPMs  610   a, b , the flow rates of the returns/drilling fluid mixtures  50   f, r  may be measured in the liquid outlet and gas outlet lines of the separator  635  and/or in the mud tank outlet and second branch line of the gas outlet using FMs. 
       FIGS. 6B-6D  illustrate a suitable centrifugal separator  635 . Alternatively, the separator  635  may be a conventional horizontal or vertical separator. The returns  50   r  flow through inlet line  635   i  arranged at a suitable decline, i.e., 20-30 degrees to horizontal, to cause the returns  650   r  to initially stratify into separated liquid and gas components prior to reaching inlet port  639  of vertical separator tube  641 . Maintaining the liquid fluid level below the inlet port  639  ensures that the maximum gas velocity in the gas recovery portion  643  of the separator  635  above inlet port  639  is less than the velocity needed to achieve churn flow, which is generally about 10 ft/sec. 
     In operation, the multiphase returns  50   r  enter inlet line  637  and are initially stratified into liquid and gas phase components as a result of the declination angle of the inflow line. The inflow line is mounted eccentrically to vertical separator tube  641  having a two-dimensional convergent nozzle  649  at inlet port  639 , as shown in  FIGS. 6C and 6D , to accelerate the fluid as it enters vertical separator tube  641 . Upon entering separator tube  641 , the stratified fluid undergoes a flow-splitting separation, where the disassociated gas component rises into the recovery section  643  as the liquid component, having been accelerated in a downward direction as a result of nozzle  649 , tangentially enters vertical separator  641  as an accelerated downwardly spiraling ribbon of fluid along the separator wall, thereby creating an efficient vortex enhanced separation mechanism for any gas component remaining in the liquid stream. 
     Because of the downward spiral of the liquid flow along the separator wall, the liquid does not pass in front of inlet port  639  on subsequent spirals, resulting in the bulk of gas remaining in the liquid stream to pass into and up the separator  641  as a result of the centrifugal force generated by the vortex, unobstructed by the incoming multiphase fluid stream  50   r . The liquid stream continues to downwardly spiral against the separator wall below inlet port  639 , where the stream then centrally converges to an enhanced vortex flow until encountering the tangential exit port  647 , where the liquid flow is directed through to liquid line  645 . It is to be noted that the tangential exit port  647  allows maintenance of the vortex energy of the fluid stream by allowing the flow to exit the separator without any redirection of the stream. 
       FIG. 6E  illustrates a suitable MPP  660 . The MPP  660  is capable of handling fluids containing one or more phases, including solids, water, gas, oil, and combinations thereof. The MPP  660  may be skid mounted and includes a power unit  682 . The MPP  660  includes a pair of driving cylinders  662 ,  664  placed in line with a respective vertically disposed plunger  668 ,  672 . The MPP  660  includes a pressure compensating pump  678  for supplying hydraulic fluid to the pair of cylinders  662 ,  664  to control the movement of the first and the second plungers  668 ,  672 . The power unit  682  provides energy to the pressure compensated pump  678  to drive the plungers  668 ,  672 . 
     The plungers  668 ,  672  are designed to move in alternating cycles. When the first plunger  668  is driven towards its retracted position, a pressure increase is triggered towards the end of the first plunger&#39;s movement. This pressure spike causes a shuttle valve (not shown) to shift. In turn, a swash plate (not shown) of the compensated pump  678  is caused to reverse angle, thereby redirecting the hydraulic fluid to the second cylinder  664 . As a result, the second plunger  672  in the second cylinder  664  is pushed downward to its retracted position. The second cylinder  664  triggers a pressure spike towards the end of its movement, thereby causing the compensating pump  678  to redirect the hydraulic fluid to the first cylinder  662 . In this manner, the plungers  668 ,  672  are caused to move in alternating cycles. 
     In operation, a suction is created when the first plunger  668  moves toward an extended position. The suction causes the drilling fluid mixture  50   f  to enter the MPP  660  through a process inlet  674  and fill a first plunger cavity. At the same time, the second plunger  672  is moving in an opposite direction toward a retracted position. This causes the drilling fluid mixture in the second plunger cavity to expel through an outlet  676 . In this manner, the multiphase drilling fluid mixture  50   f  may be injected into the drill string  105 . Although a pair of cylinders  662 ,  664  is shown, the MPP  660  may include one cylinder or more than two cylinders. 
       FIG. 7  illustrates a drilling system  700 , according to another embodiment of the present invention. Although shown simply, the downhole configuration may be similar to that of the drilling system  200 . Compared to the drilling system  600  of  FIG. 6 , a low pressure (relative to the separator  635 ) separator  735  has been added between the liquid level choke  593  and the mud tank  750 . As shown, the low pressure separator  735  is a three-phase separator. Alternatively, the low pressure separator  735  may be a two or four phase separator. A second flare or cold vent line  755   b  has also been added for the low pressure separator  735  and the mud tank  750 . An oil recovery line  755   c , gate valve  703 , have been added to the mud tank  750  (if the liquid portion of the drilling fluid is oil or oil based) to remove liquid hydrocarbons produced in the wellbore  100 . Alternatively, a variable choke and a level sensor in fluid communication with the mud tank  750  an din communication with the SMCU  65  may be used instead/in addition to the gate valve  703 . If the liquid portion of the drilling fluid  50   f  is water or water based, then the gate valve  703  (and/or level sensor  795  and choke valve) and oil recovery line  755   c , may be instead installed on the oil outlet line or oil chamber of the low pressure separator  735 . The second flare or cold vent line  55   b  connection to the mud tank  750  may also be omitted. 
       FIG. 8  is an alternate downhole configuration  800  for use with surface equipment of any of the drilling systems  200 ,  250 ,  300 - 700  of  FIGS. 2 ,  2 B, and  3 - 7 , according to another embodiment of the present invention. A pressure sensor (or PT sensor)  865 , controller  820 , and EM gap sub  825  have been added to a drillstring  305 . The pressure sensor  865  may be similar to the pressure sensors (or PT sensors)  165   a,b  and is in communication with the annulus at or near the bottom of the drill string  805  (BHP). Additionally the pressure sensor (or a second pressure sensor) may be in communication with a bore of the drill string  805 . The pressure sensor  865  is in electrical or optical communication with the controller  820  via line  817   b . The controller  820  receives an analog pressure signal from the sensor  865 , samples the pressure signal, modulates the signal, and sends the signal to a casing antenna  807   a,b  via the EM gap sub  825 . The controller is in electrical communication with the EM gap sub  825  via lines  817   a,c . The controller may include a battery pack (not shown) as a power source. The casing antenna  807   a,b  may be disposed in the casing string  815  below the DDV  150 . The casing antenna  807   a,b  may be a sub that attaches to the DDV  150  with a threaded connection. Utilizing the EM casing antenna  807   a,b  with the DDV  150  shortens the path over which the radiated EM signal from the gap sub  825  must travel, thus lessening the attenuation of the radiated EM signal. This is particularly advantageous where the DDV system and the associated casing penetrate below certain formations and/or the sea that might otherwise render the EM link ineffective. The EM casing antenna system  807   a,b  includes two annular or tubular members  807   a,b  that are mounted coaxially onto a casing joint. The two antenna members  807   a,b  may be substantially identical and may be made from a metal or alloy. The casing joint may be selected from a desired standard size and thread. A radial gap exists between each of the antenna members  807   a,b  and the casing joint, and is filled with an insulating material  808 , such as epoxy. 
     The arrangement of the antenna members  807   a,b  is used to form an electric dipole whose axis is coincident with the casing string  815 . To increase the effectiveness of the dipole, the surface area of the members  807   a,b  and the spacing between them can be increased or maximized. The antenna members  807   a,b  can act as both transmitter and receiver antenna elements. The antenna members  807   a,b  may be driven (transmit mode) and amplified (receive mode) in a full differential arrangement, which results in increased signal-to-noise ratio, along with improved common mode rejection of stray signals. The antenna members  807   a,b  receive the signal and relay the signal to a controller  810  via lines  809   a,b . The controller  810  demodulates the signal, remodulates the signal for transmission to the SMCU  65 , and multiplexes the signal with signals from the pressure sensors  165   a,b.    
     Alternatively, the controller  810  may simply be an amplifier and have a dedicated control line to the SMCU  65 . Additionally, a second gap sub and casing antenna (not shown) may be provided for transmitting and receiving other MWD/LWD data so as not to slow the transmission of the pressure signal. In this alternative, the second gap sub and casing antenna would operate on a different frequency. Alternatively, wired drill pipe may be used to transmit the pressure measurement to the surface instead of the EM gap sub  825 . The wired drill pipe may be similar to the wired casing  215   j  (or alternatives discussed therewith). Alternatively, a mud-pulse generator (not shown) may be used instead of the EM gap sub to transmit the pressure measurement to the surface. Additionally, a second pressure (or PT sensor) may be disposed along the drill string  805  at a longitudinal or substantial longitudinal distance from the pressure sensor  865 . The second pressure sensor would also be in communication with the annulus  825  and the second pressure sensor may be transmitted to the surface using the same device used for the first pressure sensor or a different one of the devices. In this manner, the second pressure sensor may serve as a backup in case of failure of the first pressure sensor and/or failure of the transmission device. Having a second pressure sensor may also be advantageous when drilling through irregular formations (see  FIG. 16 ) especially when the pressure sensor  865  has moved a substantial distance from the irregular formation. The second pressure sensor may then be proximate to the irregular formation. 
       FIG. 8A  is a cross-sectional view of a suitable gap sub assembly  825 . As shown, the gap sub assembly  825  includes a lower thread-saver  833  which mates with a lower portion of the drill string  805  and an upper thread-saver  832  which mates with an upper portion of the drill string  805 . Disposed between the upper and lower thread-savers  832 ,  833  is a tubular mandrel  840 , a tubular housing  830 , and a first gap ring  835 . 
       FIG. 8B  illustrates an expanded view of dielectric filled threads  837  in the gap sub assembly  825 . As shown, the mandrel  840  contains an external threadform that has a larger than normal space between adjacent threads  837 . In the same manner, the housing  830  has an internal threadform with widely spaced threads  837 . The mandrel  840  and housing  830  are separated from each other by a dielectric material  839 , such as epoxy, which is capable of carrying axial and bending loads through the compression between adjacent threads  837 . Typically, the load carrying ability of most dielectric materials is much higher in compression than tension and/or shear. In this respect, the total surface area bonded with the dielectric material  839  may also be increased dramatically over a purely cylindrical interface of the same length. Therefore, the increased surface area equates to higher strength in all loading scenarios. 
     Additionally, if the dielectric material  839  adhesive bonds fail and/or the dielectric material  839  can no longer carry adequate compressive loads due to excessive temperature or fluid invasion, the metal on metal engagement of the threads  837  prevents the gap sub assembly  825  from physically separating. Therefore, the mandrel  840  will remain axially coupled to the housing  830  and may be successfully retrieved from the wellbore. 
       FIG. 8C  illustrates an expanded view of the first gap ring  835  disposed in the gap sub assembly  825 . The first gap ring  835  is constructed from a toughened ceramic material, such as yttria stabilized tetragonal zirconia polycrystals, as it is a highly abrasion resistant, as well as an impact resistant material. Zirconia also has an elastic modulus and thermal expansion co-efficient comparable to that of steel and an extremely high compressive strength (i.e. 290 ksi) in excess of the surrounding metal components. These properties allow the first gap ring  835  to support the joint under bending and compressive loading producing a significantly stronger and robust gap sub assembly  835 . An optional first compression ring  844   a  is disposed between the housing  830  and the first gap ring  835 . Since the first compression ring  844   a  radially extends to the mandrel  840 , an optional second compression ring  844   b  is disposed between the first gap ring  835  and the lower thread-saver  833 . Preferably, the compression rings  844   a,b  are made from a relatively soft strain hardenable metal or alloy, such as an aluminum or bronze alloy. 
     A primary external seal is formed by torquing the lower thread-saver  833  onto the mandrel  840  to compress the first gap ring  835  and the compression rings  844   a,b  between the two halves of the gap sub assembly  825 , thereby forming the primary external seal. A secondary seal arrangement is disposed adjacent the external gap ring  835 . The secondary seal arrangement includes first sleeve segments  846   a,b  made from a high strength, high temperature polymer, such as PEEK and a series of elastomer seals  841 ,  842  disposed on the interior of the housing  830  and the exterior of the mandrel  840 , respectfully. The seals  841 ,  842  prevent fluid from entering the space between the mandrel  840  and the housing  830  if the primary seal should fail. Furthermore, the first sleeve segment  846   b  supports the first gap ring  835  and provides some shock absorption should the first gap ring  835  experience a severe lateral impact. 
       FIG. 8D  illustrates an expanded view of an internal, non-conductive seal arrangement in the gap sub assembly  825 . The internal, non-conductive seal arrangement may include a second sleeve  855  formed from a high temperature, high strength dielectric polymer, such as PEEK, and a series of elastomer seals  846 ,  848  disposed on the mandrel  840  and housing  830  respectively. The elastomer seals  846 ,  848  prevent drilling fluid from entering the internal space between mandrel  340  and housing  330 . A second, non-conductive gap ring  850  is provided in the bore of the gap sub assembly  825  to improve the electrical performance of the system. More specifically, as with the first gap ring  835 , the second, non-conductive gap ring  850  increases the path length that the current must flow through, thereby increasing the resistance of that path, and thus decreasing the unwanted current flow in the interior of the gap sub assembly  825 . The second gap ring  850  may be formed from a high temperature, high strength dielectric polymer, such as PEEK. 
     A plurality of non conductive torsion pins  845  are also included in the gap sub assembly  825 . The torsion pins  845  are constructed and arranged to ensure that no relative rotation between the mandrel  840  and housing  830  may occur, even if the dielectric material  839  bond fails. The torsion pins  845  are cylindrical pins disposed in matching machined grooves. 
       FIG. 9  is an alternate downhole configuration  900  for use with surface equipment of any of the drilling systems  200 ,  250 ,  300 - 700  of  FIGS. 2 ,  2 B, and  3 - 7 , according to another embodiment of the present invention. A pressure sensor (or PT sensor)  965   a  is included in the casing string  915  instead of the DDV  150 . Alternatively, the DDV  150  (with sensor(s)) may be included in the casing string  915 . The pressure sensor  965   a  is in electrical or optical communication with a controller  930   a  via line  970   c . A pressure (or PT sensor)  965   b  is disposed near a longitudinal end of a liner  915   a . The sensor  965   b  is in electrical or optical communication with the liner controller  930   b  via line  970   f . The liner  915   a  has been hung from the casing string  915  by anchor  920 . The anchor  920  may also include a packing element. The liner  915   a  is cemented  120  in place. A drill string  905  having a bit  910  is disposed through the casing string  915  and the liner  915   a.    
     Disposed near a longitudinal end of the casing string  915  is a part of an inductive coupling  955   a  and a part of an inductive coupling  955   b . The other parts of the inductive couplings  955   a,b  are disposed near a longitudinal end of the liner  915   a . The casing controller  930   a  is in electrical communication with each part of the couplings  955   a, b  via lines  970   a, b , respectively. One of the couplings  955   a, b  is used for power transfer and the other coupling  955   a, b  is used for data transfer. The liner controller  930   b  is in electrical communication with each part of the couplings  955   a, b  via lines  970   d, e , respectively. The controller  930   b  and the lines  970   d - f  may be disposed along an outer surface of the liner  915   a  or within a wall of the liner  915   a.    
     Alternatively, only one inductive coupling may be used to transmit both power and data. In this alternative, the frequencies of the power and data signals would be different so as not to interfere with one another. Additionally, the liner  915   a  may include one or more additional inductive couplings (not shown) for data and power communication with a second liner (not shown) which may be disposed along an inner surface of the liner  915   a . The casing parts and the liner parts of the inductive couplings  955   a, b  may each be disposed in separate subs made from a non-magnetic material (i.e., austenitic stainless steel) that are joined to the respective casing  915  and liner  915   a  by a threaded connection to avoid interference. Additionally, there may be several sets of the casing part of the inductive couplings  955   a, b  disposed in the casing  915 , each set longitudinally spaced to create a window (i.e., 90 feet) to allow for tolerance in the setting depth of the liner  915   a . Alternatively, the casing  915  may include a profile formed on an inner surface thereof and the liner  915   a  may include a mating drag block received by the profile to ensure proximal alignment of the parts of the inductive couplings  955   a, b.    
     The couplings  955   a, b  are an inductive energy/data transfer devices. The couplings  955   a, b  are devoid of any mechanical contact between the two parts of each coupling. Each part of each of the couplings  955   a,b  include either a primary coil or a secondary coil. Each of the coils may be strands of wire made from a conductive material, such as aluminum, copper, or alloys thereof. The wire may be jacketed in an insulating polymer, such as a thermoplastic or elastomer. The coils may then be encased in a polymer, such as epoxy. In general, the couplings  955   a,b  each act similar to a common transformer in that they employ electromagnetic induction to transfer electrical energy/data from one circuit, via a primary coil, to another, via a secondary coil, and does so without direct connection between circuits. In operation, an alternating current (AC) signal generated by a sine wave generator included in each of the controllers  930   a,b.    
     For the power coupling, the AC signal is generated by the casing controller  930   a  and for the data coupling the AC signal is generated by the liner controller  930   b . When the AC flows through the primary coil the resulting magnetic flux induces an AC signal across the secondary coil. The liner controller  930   b  also includes a rectifier and direct current (DC) voltage regulator (DCRR) to convert the induced AC current into a usable DC signal. The casing controller  930   a  may then demodulate the data signal and remodulate the data signal for transmission along the line  170   a  to the SMCU (multiplexed with the signal from the pressure sensor  965   a ). The couplings  955   a,b  are sufficiently longitudinally spaced to avoid interference with one another. Alternatively, conventional slip rings, capacitive couplings, roll rings, or transmitters using fluid metal may be used instead of the inductive couplings  955   a,b.    
     Adding another pressure sensor  965   b  in the liner  915   a  minimizes the distance between the sensing depth and the open-hole section of the wellbore  100 , thereby providing a more accurate indication of the pressure profile in the open-hole section. By using the couplings  955   a,b , a high bandwidth data (and power) connection may be maintained between the sensor  965   b  and the SMCU  65  without otherwise having to run a second data (and power) line from the surface  5 . Running a second data line from the surface would expose the data line to drilling fluid returning in the annulus  125  and, in the case that a DDV  150  is installed in the casing  915 , prevent closure of the DDV. 
       FIG. 10A  is an alternate surface/downhole configuration  1000  for use with any of the drilling systems  200 ,  250 ,  300 - 700  of  FIGS. 2 ,  2 B, and  3 - 7 , according to another embodiment of the present invention. The drilling system  1000  provides the capability to reduce (or increase) the density of the drilling fluid  50   f , for example during underbalanced or near underbalanced drilling operation. 
     The drilling system  1000  includes a modified wellhead  1012 . Additionally, a secondary fluid  1040   s  is injected from a secondary fluid source  1040 , such as a nitrogen tank or nitrogen generator, is connected to the modified wellhead  1012 . Alternatively, the secondary fluid  1040   s  could be natural gas, exhaust fumes from a prime mover (not shown), a liquid having a lower density than the drilling fluid  50   f , or a liquid having a higher density than the drilling fluid  50   f . An injection rate from the secondary fluid source  1040  may be regulated by a control valve or variable choke valve  1030  which is in communication with the SMCU  65 . The injection rate may be monitored by providing a pressure (or PT) sensor  1055  and/or FM in data communication with the SMCU  65 . A string of casing  1015  is hung from the wellhead  1012  and cemented  120  to the wellbore  100 . A liner  1015   a  has been hung from the casing string  1015  by anchor  1020 . The anchor  1020  may also include a packing element. The liner  1015   a  is also cemented  120  in place. 
     A tieback casing string  1015   b  is also hung from the modified wellhead  1012  and disposed within the casing string  1015 . A pressure sensor (or PT sensor)  1065  is included in the tieback casing  1015   b . Alternatively, the DDV  150  (with sensor(s)) may be included in the tieback casing  1015   b . Alternatively, the liner  1015   a  may also have a pressure sensor (or PT sensor) (not shown) connected to the surface using inductive couplings between the liner and the casing  1015 , similar to the drilling system  900 . The pressure sensor  1065  is in electrical or optical communication with the SMCU  65  via control line  1070 . Annuluses  1025   a - c  are defined between: an outer surface of the tieback casing  1015   b  and an inner surface of the casing  1015 , an inner surface of the tieback casing  1015   b  and an outer surface of the drill string  1005 , and the outer surface of the drill string  1005  and an inner surface of the liner  1015   a , respectively. The secondary fluid source  1040  is in fluid communication with the annulus  1025   a.    
     In operation, drilling fluid  50   f , such as conventional oil or water-based mud, is injected through the drill string  1005  and exits from the drill bit  1010 . The returns  50   r  return to the surface  5  via annulus  1025   c . A flow rate of the secondary fluid  1040   s , determined by the SMCU  65 , is injected through the annulus  1025   a . The secondary fluid mixes with the returns  50   r  at a junction between annulus  1025   a  and  1025   c . The secondary fluid mixes with the returns  50   r , thereby lowering (or raising) the density of the returns/secondary fluid mixture  1040   r  as compared to the density of the returns  50   r . The resulting lighter mixture lowers (or increases) the annulus pressure that would otherwise be exerted by the column of the returns  50   r . Thus, by adjusting the injection rate, the annulus pressure can be controlled. Additionally, a second (or more) injection location may be provided in the tieback casing string  1015   b , for example, midway between the end of the tieback casing  1015   b  and the wellhead  1012 . Alternatively, injection of the secondary fluid may be used to maintain annulus pressure control during tripping of the drill string  1005  instead of (or in addition to) applying back pressure to the annulus  1025   b  from the surface or using the CCS/CFS  350   a, b.    
       FIG. 10B  is an alternate surface/downhole configuration  1050  for use with any of the drilling systems  200 ,  250 ,  300 - 700  of  FIGS. 2 ,  2 B, and  3 - 7 , according to another embodiment of the present invention. The drilling system  1050  is similar to the drilling system  1000  except that the secondary fluid  1040   s  is injected through one of the chambers  1006   a, b  of a dual-flow drill string  1006  instead of the tie-back annulus  1025   a . Drilling fluid is injected through the other one of the chambers  1006   a, b . Alternatively, the secondary fluid  1040   s  may be injected through the annulus  125  and the return mixture  1040   r  would flow through one of the chambers  1006   a, b.    
       FIG. 10C  is a partial cross section of a joint  1006   j  of the dual-flow drill string  1006 .  FIG. 10D  is a cross section of a threaded coupling of the dual-flow drill string  1006  illustrating a pin  1006   m  of the joint  1006   j  mated with a box  1006   f  of a second joint  1006   j ′.  FIG. 10E  is an enlarged top view of  FIG. 10C .  FIG. 10F  is cross section taken along line  10 E- 10 F of  FIG. 10C .  FIG. 10G  is an enlarged bottom view of  FIG. 10C . A partition is formed in a wall of the joint  1006   j  and divides an interior of the drill string  1006  into two flow paths  1006   a  and  1006   b , respectively. A box  1006   f  is provided at a first longitudinal end of the joint  1006   j  and the pin  1006   m  is provided at the second longitudinal end of the joint  1006   j . A face of one of the pin  1006   m  and box  1006   f  (box as shown) has a groove formed therein which receives a gasket  1006   g . The face of one of the pin  1006   m  and box  1006   f  (pin as shown) may have an enlarged partition to ensure a seal over a certain angle α. This angle α allows for some thread slippage. Alternatively, a concentric dual drill string (not shown) may be used instead of the dual-flow drill string  1006 . 
       FIG. 10H  is an alternate surface/downhole configuration  1075  for use with any of the drilling systems  200 ,  250 ,  300 - 700  of  FIGS. 2 ,  2 B, and  3 - 7 , according to another embodiment of the present invention. The drilling system  1075  includes the tieback casing string  1015   b  hung from the wellhead  1012  by hanger  1020   b  and the liner  1015   a  hung from the casing  1015  by hanger  1020   a . A column of high density fluid (relative to the density of the returns  50   r )  1040   h , a.k.a. a mudcap, is maintained in the annulus  1025   b  between the drillstring  1005  and the tieback casing string  1015   b . Alternatively, the mudcap may be maintained in the annulus  1025   a  between the tieback casing string  1015   b  and the casing string  1015 . The returns  50   r  exit the wellbore  100  through the tieback annulus  1025   a  and an outlet of the wellhead  1012 . 
     The mudcap  1040   h  provides a pressure barrier so that minimal pressure is exerted on the RCD  15 , thereby increasing the service life of the RCD  15  and reducing leakage across the RCD  15 . The mudcap  1040   h  also discourages any gas migration therethrough which, in combination with reduced leakage across the RCD  15 , is beneficial when drilling through hazardous formations (i.e., hydrogen sulfide). The mudcap  1040   h  is injected into the tieback annulus  1025   a  and the depth of the pressure barrier  1090  is maintained by a pump  1060  in communication with the RCD outlet. One or more pressure (or PT) sensors  1065   a - c  are disposed in the tieback string  1015   b  and in fluid communication with both the tieback annulus  1025   a  and the drillstring annulus  1025   a . The pressure sensors  1065   a - c  are in electrical/optical communication with the SMCU  65  via control line The sensors  1065   a - c  may be incrementally spaced so that the SMCU  65  may determine and control a level of an interface  1090  between the mudcap  1040   h  and the returns  50   r  by activating and/or controlling a flow rate of the pump  1060 , by reversing the pump  1060 , and/or not activating and/or reducing the flow rate of the pump (the mudcap  1040   h  may gradually mix with the returns  50   r  so that by not activating and/or reducing a flow rate of the pump  1060 , the SMCU  65  may let the level of the interface  1090  decrease (up in the FIG.)). A pressure (or PT) sensor  1065   d  may also be provided in fluid communication with the RCD outlet to monitor the pressure exerted on the RCD  15  and in data communication with the SMCU  65 . 
     Additionally, the DDV  150  (with sensor(s)) may be included in the tieback casing  1015   b . Additionally, the casing  1015  may have a pressure sensor (or PT sensor) installed therein and the liner  1015   a  may also have a pressure sensor (or PT sensor) (not shown) connected to the surface  5  using inductive couplings between the liner and the casing  1015 , similar to the drilling system  900 . Alternatively, the tieback casing  1015   b  may extend to a polished bore receptacle (see  FIG. 11 ) on the hanger  1020   a  and may include first and second valves and a second RCD between the valves. This alternative is disclosed in U.S. Pat. No. 6,732,804, which is hereby incorporated by reference in its entirety. 
       FIG. 11A  is an alternate downhole configuration  1100   a  for use with surface equipment of any of the drilling systems  200 ,  250 ,  300 - 700  of  FIGS. 2 ,  2 B, and  3 - 7 , according to another embodiment of the present invention.  FIG. 11B  illustrates a downhole configuration  1100   b  in which the wellbore has been further extended from the downhole configuration  1100   a.    
     Referring to  FIG. 11A , a string of casing  1115  is hung from a wellhead (not shown) and cemented  120  to the wellbore  100 . A liner  1115   a  has been hung from the casing string  1115  by anchor  1120   a . The anchor  1120   a  may also include a packing element. The liner  1115   a  is also cemented  120  in place. Attached to the anchor  1120   a  is a polished bore receptacle (PBR)  1130   a . A tieback casing string  1115   b , including a DDV  1150  (similar to the DDV  150 ) is also hung from the wellhead and disposed within the casing string  1115 . Alternatively, a pressure sensor (or PT sensor) (without the valve) may be disposed in the tieback casing  1115   b . Disposed along an outer surface near a longitudinal end of the tieback casing string  1115   b  is a sealing element  1135   a . As the casing string  115   a  is inserted into the PBR, the sealing element  1135   a  engages an inner surface of the PBR, thereby forming a seal therebetween and isolating an annulus  1125   a  defined between an inner surface of the casing string  1115  and an outer surface of the tieback string  1115   b  from an annulus defined between an inner surface of the tieback casing  1115   b /liner  1115   a  and an outer surface of the drill string  1105   a . The DDV  1150  is able to isolate (with the drillstring  1105   a  removed) a bore of the tieback casing  1115   b  from a bore of the liner  1115   a , thereby effectively isolating an upper portion of the wellbore from a lower portion of the wellbore (the annulus  1125   a  need not be isolated by the DDV since it isolated by the seal  1135   a ). The return mixture travels to the surface  5  via the annulus  1125 . This configuration  1100   a  is advantageous over the embodiment of  FIG. 1  in that the DDV  1150  is not fixed to the casing  1115 . When adding another casing string to the configuration of  FIG. 1 , the DDV  150  ends up being cemented between the casing string  115  and the next casing string. In this configuration  1100   a , after drilling the next section of wellbore  100 , the tieback casing string  1115   b , along with the DDV  1150 , may be removed. 
     Referring to  FIG. 11B , a second liner  1115   c  has been hung from the first liner  1115   a , via a second anchor  1120   b , and cemented  120  to the wellbore. A second PBR  1130   b  is attached to the second anchor  1120   b . A second tieback casing  1115   d , having a second DDV  1150   b , is hung from a wellhead and disposed within the casing string  1115  and first liner  1115   a . A seal  1135   b  disposed along an outer surface of the tieback casing  1115   c  near a longitudinal end thereof engages an inner surface of the second PBR  1130   b , thereby isolating the annulus  11125  from the annulus  1125   a . Analogously to the drilling system  900  of  FIG. 9 , running the second DDV  1150   b  (with sensor(s)), minimizes the distance between the sensing depth and the open-hole section of the wellbore  100 , thereby providing a more accurate indication of the pressure profile in the open-hole section. Further, using a tie-back casing string instead of liner may be advantageous in that the drilling fluid annulus  1125  is mono-bore to the surface, whereas if a liner were used the drilling fluid annulus would increase in area (see  FIG. 9 ) which causes a reduction in fluid velocity of the return mixture, thereby reducing the cuttings carrying capability of the return mixture. 
       FIG. 12  is an alternate downhole configuration  1200  for use any of the drilling systems  200 ,  250 ,  300 - 700  of  FIGS. 2 ,  2 B, and  3 - 7 , according to another embodiment of the present invention. A flow meter  1275  may be included as part of the casing string  1215  to measure volumetric fractions of individual phases of the returns  50   r  flowing through the casing string  1215 , as well as to measure flow rates of components in the returns  50   r . Obtaining these measurements allows monitoring of the substances being added or removed from the wellbore while drilling, as described below. The flow meter  975  may provide mass flow rate or volumetric flow rate of components in the multiphase mixture. 
     The flow meter  1275  may be substantially the same as the flow meter disclosed in U.S. Pat. No. 6,945,095 which is herein incorporated by reference in its entirety. The flow meter  1275  allows volumetric fractions of individual phases of the returns  50   r  flowing through the casing string  1215 , as well as flow rates of individual phases of the returns  50   r , to be found. The volumetric fractions are determined by using a mixture density and speed of sound of the returns  50   r . The mixture density may be determined by direct measurement from a densitometer or based on a measured pressure difference between two vertically displaced measurement points (shown as P 1  and P 2 ) and a measured bulk velocity of the mixture, as disclosed in the &#39;095 patent. Various equations are utilized to calculate flow rate and/or component fractions of the fluid flowing through the casing string  915  using the above parameters, as disclosed in the &#39;095 patent. 
     The flow meter  1275  may include a velocity sensor  1291  and speed of sound sensor  1292  for measuring bulk velocity and speed of sound of the fluid, respectively, up through the inner surface of the casing string  1215 , which parameters are used in equations to calculate flow rate and/or phase fractions of the fluid. As illustrated, the sensors  1291  and  1292  may be integrated in single flow sensor assembly (FSA)  1293 . In the alternative, sensors  1291  and  1292  may be separate sensors. The velocity sensor  1291  and speed of sound sensor  1292  of FSA  1293  may be similar to those described in commonly-owned U.S. Pat. No. 6,354,147, entitled “Fluid Parameter Measurement in Pipes Using Acoustic Pressures”, issued Mar. 12, 2002 and incorporated herein by reference. 
     The flow meter  1275  may also include PT sensors  1214   a,b  around the outer surface of the casing string  1215 , the sensors  1214   a,b  similar to those described in detail in commonly-owned U.S. Pat. No. 5,892,860, entitled “Multi-Parameter Fiber Optic Sensor For Use In Harsh Environments”, issued Apr. 6, 1999 and incorporated herein by reference. In the alternative, the pressure and temperature sensors may be separate from one another. Further, for some embodiments, the flow meter  1275  may utilize an optical differential pressure sensor (not shown). The sensors  1291 ,  1292 , and/or  1214   a,b  may be attached to the casing string  1215  using the methods and apparatus described in relation to attaching the sensors 30, 130, 230, 330, 430 to the casing strings 5, 105, 205, 305, 405 of FIGS. 1-5 of U.S. patent application Ser. No. 10/676,376 and entitled “Permanent Downhole Deployment of Optical Sensors”, filed on Oct. 1, 2003, which is herein incorporated by reference in its entirety. 
     Optical line  1270   b  is provided for optical communication between the sensors  1291 ,  1292 , and  1214   a,b  and an optional downhole controller  1210 . An optical or electrical line is provided between the downhole controller  1210  and the sensors of the DDV  150 . The downhole controller  1210  is in data/power communication with the SMCU  65  via line  1270 . The downhole controller provides amplification, modulation, and multiplexing capabilities for communication between the sensors  1291 ,  1292 , and  1214   a,b  and the SMCU  65 . 
     Optionally, a conventional densitometer (e.g., a nuclear fluid densitometer) may be used to measure mixture density as illustrated in FIG. 2B of the &#39;095 patent. However, for other embodiments, mixture density may be determined based on a measured differential pressure between two vertically displaced measurement points and a bulk velocity of the fluid mixture, also disclosed in the &#39;095 patent. 
     While the returns  50   r  are circulating up through the annulus  1225 , the flow meter  1275  may be used to measure the flow rate of the returns  50   r  in real time. Furthermore, the flow meter  1275  may be utilized to measure in real time the component fractions of oil, water, mud, gas, and/or particulate matter including cuttings, flowing up through the annulus in the returns  50   r . Specifically, the optical sensors  1291 ,  1292 , and  1214   a,b  send the measured wellbore parameters up through the control line  1270  to the SMCU  65 . The optical signal processing portion of the SMCU  65  calculates the flow rate and component fractions of the returns  1225  utilizing the equations and algorithms disclosed in the &#39;095 patent. 
     By utilizing the flow meter  1275  to obtain real-time measurements while drilling, the composition of the drilling fluid  50   f  may be altered to optimize drilling conditions, and the flow rate of the drilling fluid  50   f  may be adjusted to provide the desired composition and/or flow rate of the returns  50   r . Additionally, the real-time measurements while drilling may prove helpful in indicating the amount of cuttings making it to the surface  5  of the wellbore  100 , specifically by measuring the amount of cuttings present in the returns  50   r  while it is flowing up through the annulus using the flow meter  1275 , then measuring the amount of cuttings present in the fluid exiting to the surface  5 . The composition and/or flow rate of the drilling fluid  50   f  may then be adjusted during the drilling process to ensure, for example, that the cuttings do not accumulate within the wellbore  100  and hinder the path of the drill string  105  through the formation. 
     Utilizing the flow meter  1275  may be advantageous for slimhole drilling. In slimhole drilling the monitoring of flow rates becomes very important because a small change in fluid volume in the well translates into a significant change in height and hence pressure head in the annulus. Generally, if the mass flow in equals the mass flow out, then the well is in control. If the mass flow out is greater than the mass flow in then there is an influx of well fluids into the borehole. If the mass flow in is greater than the mass flow out, then drilling fluid is flowing into the formation, i.e., leaking of fluid into the formation. This may be used for a detection of a kick or a detection of lost circulation. Real-time monitoring of the mass flow rates into and out of the well using the flow meter  1275  provides an alternative to the traditional liquid level monitoring techniques of the prior art. Further, having the flow meter  1275  in the wellbore  100  reduces the delay time of liquid level changes propagating to the surface. 
     Alternatively, measuring a parameter of the return mixture (i.e., the oil to water ratio) using the flow meter  1275  or a flow meter in the outlet line of the RCD  15  may be used to determine a formation threshold pressure (i.e., pore pressure). For example, if the drilling fluid is an oil based mud and the wellbore is intersecting a water bearing formation (or vice versa), a change in the oil to water ratio would indicate either that drilling fluid is entering the formation or that formation fluid is entering the wellbore. From this behavior, a drilling condition (i.e., overbalanced or underbalanced) may be determined and the bottom hole pressure may be adjusted accordingly. Further, if the change in the oil to water ratio is drastic, then a kick or formation fracture would be indicated and the appropriate steps taken to remedy the situation. 
       FIG. 13  is an alternate downhole configuration  1300  for use with surface equipment of any of the drilling systems  200 ,  250 ,  300 - 700  of  FIGS. 2 ,  2 B, and  3 - 7 , according to another embodiment of the present invention. A first casing string  1315   a  may be cemented to the wellbore  100 . A second casing string  1315   b  may be disposed in the wellbore and cemented to the wellbore and the first casing string  1315   a . The DDV  150  may be assembled as part of the second casing string  1315   b . The DDV  150  may include the pressure (or PT) sensors  165   a, b  and a casing antenna  807  (assembled with or near the DDV  150 ). Data communication may be provided between the DDV  150  and the SMCU  65  via control line  170   a  which may be disposed along (or within) an outer surface of the second casing string  1315   b . For clarity, the control line  170   a  is shown outside the wellbore  100  but would actually be in an annulus  1325   a  formed between the second casing string  1315   b  and the wellbore  100 /first casing string  1315   a  or within a wall of the second casing string  1315   b . As discussed above, a hydraulic line  170   b  (not shown) may also be run with the control line  170   a  for operating the DDV  150 . The second casing string  1315   b  may also include one or more additional pressure (or PT) sensors  1365   a - c  longitudinally spaced therealong for monitoring the performance of an equivalent circulation density (ECD) reduction tool (ECDRT)  1350  disposed in the drill string. Additionally, the MPM  1275  (not shown) may also be disposed in the second casing string  1315   b . Alternatively, the second casing string  1315   b  may be a liner hung from the first casing string  1315   a  or a tie-back casing string seated in a PBR disposed in a liner hung from the first casing string  1315   a . Alternatively, the first casing string  1315   a  may be omitted. 
     The drill string  1305  includes the ECDRT  1350  and a drill bit  1310  disposed at a longitudinal end thereof. The ECDRT  1350 , discussed more below, provides hydraulic lift to the returns  50   r  in the annulus  1325  in order to offset the effect of friction loss on the BHP. The pressure sensors  165   a, b / 1365   a - c  may be used to monitor the performance of the ECDRT in real time. The pressure sensors  165   a,b / 1365   a - c  may be longitudinally spaced so that at least one pressure sensor is proximate to the ECDRT inlet  1390  and at least one pressure sensor is proximate to the ECDRT outlet  1362  as the ECDRT  1350  travels along the second casing string  1315   b . The SMCU  65  may then vary one or more operating parameters of the ECDRT  1350  (i.e. injection rate of drilling fluid  50   f  through the drill string  1305  and/or the surface choke  30 ) to maintain a desired annulus pressure. Additionally, the SMCU  65  may detect failure of the ECDRT  1350  and signal a need to trip the ECDRT  1350  for maintenance. Alternatively, only one pressure sensor may be disposed in the second casing string  1315   b  and the performance of the ECDRT  1350  may be monitored by calculating inlet  1390  and/or outlet  1362  pressures using an annulus flow model, discussed more below. 
     The drill string  1305  may further include LWD sonde  1395 . The LWD sonde  1395  may include one or more instruments, such as spontaneous potential, gamma ray, resistivity, neutron porosity, gamma-gamma/formation density, sonic/acoustic velocity, and caliper. The LWD sonde  1395  may also include a pressure (or PT) sensor. Raw data from these instruments may be transmitted to the casing antenna  807  using an EM gap sub  825  in communication with the LWD sonde  825 . The raw data may then be relayed to the SMCU  65  via the control line  170   a . The SMCU may then process the raw data to calculate lithology, permeability, porosity, water content, oil content, and gas content of Formations A-E as they are being drilled through (or shortly thereafter). Alternatively, the LWD sonde may include a controller to process or partially process the data on-board and then transmit the processed data to the SMCU. Alternatively, the logging data may be transmitted via mud-pulse or wired drill pipe. The drill string  1305  may further include an MWD sonde (not shown) for providing orientation of the drill bit  1310 . The drill string  1305  may further include a mud motor (not shown) and/or a steering tool (not shown) for controlling the direction of the bit  1310 . 
       FIGS. 13A-13F  are cross-sectional views of a suitable ECDRT  1350 . The ECDRT  1350  includes three sections  1350   a - c . The first section is a turbine motor  1350   a , which harnesses fluid energy from drilling fluid  50   f  pumped through the drill string  1305  and converts the fluid energy into rotational energy. The second section is a multi-stage mixed flow pump  1350   b  driven by the turbine motor  1350   a . The pump  1350   b  pumps the returns  50   r  returning from the drill bit  110  through the annulus  1325 , toward the surface  5 . The lower section  1350   c  includes seals  1386   a, b  that engage the inner surface of the casing  1310   b  to prevent the returns  50   r  from bypassing the pump  1350   b  through the annulus  1325 . 
     The turbine  1350   a  is schematically shown. A more detailed illustration may be found in FIGS. 8-12 of U.S. Pat. No. 6,527,513, which is incorporated by reference in its entirety. The turbine motor  1350   a  includes a housing  1352  defining a chamber therein. A rotor  1357  is disposed in the housing chamber and is supported by bearings  1354   a,b  to allow rotation relative to the housing  1352 . The rotor  1357  includes at least one wheel blade array with an annular array of angularly distributed blades. Nozzles are provided for directing jets of drilling fluid  50   f  onto the blades for imparting rotational energy to the rotor  1357 . Drilling fluid  50   f  is diverted from the motor chamber to a bore of the rotor  1357  via an outlet  1356  of the motor  1350   a . At a lower end, the rotor  1357  is rotationally coupled by a hexagonal, spline-like coupling  1358  to a shaft  1366  of the pump  1350   b . The hexagonal coupling  1358  allows for some longitudinal movement between the rotor  1357  and the pump shaft  1366  within the connection  1358 . The motor housing  1352  is connected to an upper end of a housing  1364  of the pump  1350   b  with a threaded connection. 
     The pump shaft  1366  is mounted at upper and lower ends thereof by bearing cartridges to center the pump shaft  1366  within the pump housing  1364 . A bore of the pump shaft  1366  provides a conduit for drilling fluid  50   f  exiting the motor  1350   a  through the pump  1350   b  to the seal section  1350   c . An impeller section  1370  of the pump  1350   b  includes outwardly formed undulations  1368  rotationally coupled to an outer surface of the pump shaft  1366  and matching, inwardly formed undulations  1374  rotationally coupled to an inner surface of the pump housing  1364 . In order to add energy to the fluid, each shaft undulation  1368  includes helical blades  1372  formed thereupon. As the pump shaft  1366  rotates, the returns  50   r  are acted upon by the blades  1372  as the returns  50   r  travel through the impeller section  1370 , thereby transferring rotational energy generated by the motor  1350   a  to the returns  50   r.    
     The lower section  1350   c  includes a seal shaft  1378  disposed within a seal housing  1380 . A bore of the seal shaft  1378  provides a conduit for drilling fluid  50   f  exiting the pump  1350   b  through the seal section  1350   c  to the drill string  1305 . The seal housing  1380  is connected to a lower end of the pump housing  1364  with a threaded connection. A seal sleeve  1384  is disposed along an outer surface of the seal housing  1380 . The seal sleeve  1384  is supported from the seal housing  1380  by bearings  1382   a, b  so that the seal housing  1380  may rotate relative to the seal sleeve  1384 . Disposed along an outer surface of the seal sleeve  1384  are two annular seals  1386   a, b . The annular seals  1386   a, b  engage the inner surface of the casing  1310   b , thereby isolating an inlet  1390  from a portion of the annulus  1325  above the annular seals  1386   a,b  and preventing the returns  50   r  from bypassing the pump  1350   b  via the annulus  1325 . The pump inlet  1390  includes a screen for filtering large particulates from the returns  50   r  to prevent damage to the pump  1350   b.    
     The returns  50   r  returning from the drill bit  110  through the annulus  1325  enter the seal section  1350   c  through the inlet  1390 . The returns  50   r  are transported through the seal section  1350   c  via an annulus  1388  formed between an inner surface of the seal housing  1380  and an outer surface of the seal shaft  1378 . The annulus  1388  is in fluid communication with a pump annulus  1376  which transports the returns  50   r  to the impeller section  1370  where energy is added to the returns  50   r . The returns  50   r  exit the pump  1350   b  at an outlet  1362  and return to the surface  5  via the annulus  1325 . 
       FIG. 14  is an alternate downhole configuration  1400  for use with surface equipment of any of the drilling systems  200 ,  250 ,  300 - 700  of  FIGS. 2 ,  2 B, and  3 - 7 , according to another embodiment of the present invention. A casing string  1415  has been run-in and cemented  120  to the wellbore. The portion of the wellbore  100  for casing string  1415  may have been drilled with a conventional drill string  105 . The casing string  1415  includes the DDV  150  and part of an inductive coupling  1455 . The casing part of the inductive coupling  1455  is in data communication with the SMCU  65  via control line  170   a.    
     A liner string  1415   a  may be being drilled into the wellbore using a run-in string  1405  (i.e., a drill string). The liner string  1415   a  may be rotationally and longitudinally coupled to the run-in string  1405  via crossover  1420 . The crossover  1420  may also provide fluid communication between a bore of the run-in string  1405  and a bore of the liner  1415   a . The crossover  1420  may also serve as an anchor (or anchor and packer) to hang the liner  1415   a  from the casing  1415  once drilling is completed. Alternatively, a separate anchor may be included. Whether the run-in string  1405  is required depends on whether a length of the liner string  1415   a  is longer than that of the casing string  1415  (plus any sea depth, if applicable). 
     A drill bit  1410  and mud motor  1460  are disposed on a longitudinal end of the liner string  1415   a . The drill bit  1410  and mud motor  1460  may be drillable or may be latched to the liner string and removable (or one drillable and the other removable). A pressure (or PT) sensor  1465  is disposed near the longitudinal end of the liner string. The pressure sensor  1465  is in fluid communication with the annulus  1425  and a bore of the liner  1415   a . The pressure sensor  1465  is in signal communication with part of the inductive coupling  1455  via control line  1470 . The control line  1470  may be disposed in a groove formed in an outer surface of the liner similar to the wired casing  215   j  (or any alternatives discussed therewith). Although only one inductive coupling  1455  is shown, a second inductive coupling may be installed as discussed above in reference to  FIG. 9  (or any other alternatives discussed therewith). Surface equipment for assembling segments of the wired liner  1415   a  while drilling is disclosed in U.S. Pub. No. 2004/0262013, which is incorporated by reference. The pressure sensor  1465  may have been in data communication with the SMCU  65  while segments were still being added to the liner string  1415   a . Additionally, the run-in string  1405  may include a gap sub  825  (and another part of the inductive coupling) for transmitting a signal from the pressure sensor  1465  while drilling or the run-in string  1405  may be wired (if the run-in string  1405  is needed). 
     Once drilling is completed (i.e., the liner part of the inductive coupling  1455  is longitudinally aligned with the casing part of the inductive coupling  1455 ), the liner  1415   a  may be cemented in the wellbore  100 . The mud motor  1460  and drill bit  1410  may be removed before cementing (if the latch is used). A cementing tool (not shown) may be included to facilitate the cementing operation. After injection of the cement, the run-in string  1405  may be removed. Drilling may be continued by drilling through the drill bit and/or mud motor (if the latch was not used). The pressure sensor  1465  will be in data/power communication with the SMCU  65  via the inductive coupling  1455 . Alternatively, one or more concentric liners may be disposed in the liner  1415   a  and each have another drill bit connected thereto. In this alternative, the run-in string would be connected to the innermost concentric liner. A releasable connection, i.e. a shear pin, would hold the liners together. Once the outermost liner was drilled in, one of the shear pins would be broken and drilling would continue with the next inner liner. Each of the liners may include a pressure sensor and an inductive coupling. Alternatively, the casing string  1415  may have been drilled in (with the DDV  150  or with just a pressure sensor). 
       FIG. 15  is a flow diagram illustrating operation  1500  of the surface monitoring and control unit (SMCU)  65 , according to another embodiment of the present invention. The SMCU operation  1500  may be for any of the drilling systems  200 ,  250 ,  300 - 1000 ,  1050 ,  1075 , and  1100 - 1400 . During act  505 , the SMCU  65  inputs conventional drilling parameters, such as rig pump strokes (and/or stroke rate), stand pipe pressure (SPP) (from pressure sensor  25   b ), well head pressure (WHP) (from pressure sensor  25   a ), torque exerted by top drive  17  (or rotary table), bit depth and/or hole depth, the rotational velocity of the drill string  105 , and the upward force that the rig works exert on the drill string  105  (hook load). The drilling parameters may also include mud density, drill string dimensions, and casing dimensions. Minimally, the SMCU  65  may input at least one of SPP and WHP and at least one of drilling fluid flow rate (rig pump rate) and returns flow rate (if a flow meter is used). 
     Simultaneously, during act  1510 , the SMCU  65  inputs a pressure measurement from the DDV  150  sensor(s)  165   a,b  (may only be a pressure sensor, i.e.  465   a ). The communication between the SMCU  65  and the drilling parameters sources and the DDV sensors  165   a,b  is a high bandwidth (i.e., greater than or equal to one-thousand bits per second) connection. Depending on various factors, such as the type of data line used, channel widths, etc., bandwidths of ten-thousand, one-hundred thousand, one-million bits per second, or even higher, may be achieved. These high bandwidth connections support high or continuous sampling rates of data (i.e., greater than or equal to ten times per second). Depending on various factors, such as bandwidth, hardware speeds, etc., sampling rates of one-hundred, one-thousand times per second, or even higher may be achieved. Further, the data travels through the connection mediums at the speed of light so the data travel time is negligible. Therefore, the drilling parameters and the DDV pressure measurement are provided to the SMCU  65  in real time (RTD). 
     During act  1515 , from at least some of the drilling parameters, the SMCU  65  may calculate an annulus flow model or pressure profile. During act  1520 , the SMCU  65  may then calibrate the annulus flow model using at least one of (or at least two of or all of) the DDV pressure  1510 , the stand pipe pressure  25   b , and the well head pressure  25   a . During act  1525 , using the calibrated annulus flow model, the SMCU  65  determines an annulus pressure at a desired depth. Additionally, there may be two or more desired depths between the sensor depth and the BHD. As is discussed in further detail below, the desired depth may be a depth of a formation (or portion thereof) that may generate a kick if the pressure is not carefully controlled in a balanced or overbalanced drilling operation or the desired depth may be a depth of a formation (or portion thereof) that is susceptible to collapse if the pressure is not carefully controlled in an underbalanced drilling operation. 
     During act  1527 , the SMCU  65  compares the calculated annulus pressure to one or more formation threshold pressures (i.e., pore pressure, stability pressure, fracture pressure, and/or leakoff pressure) to determine if a setting of the choke valve  30  needs to be adjusted. Alternatively, as discussed above, the SMCU  65  may instead alter the injection rate of drilling fluid  50   f  and/or alter the density of the drilling fluid  50   f . Alternatively, SMCU  65  may determine if the calculated annulus pressure is within a window defined by two of the threshold pressures. The window may include a safety margin from each of the threshold pressures. If the choke  30  setting needs to be adjusted, during act  1530 , the SMCU  65  determines a choke setting that maintains the calculated annulus pressure within a desired operating envelope or at a desired level (i.e., greater than or equal to) with respect to the one or more threshold pressures at the desired depth. The SMCU  65  then sends a control signal to the choke valve  30  to vary the choke so that the calculated annulus pressure is maintained according to the desired program. The acts  1505 - 1527  may be iterated continuously (i.e., in real time). This is advantageous in that sudden formation changes or events (i.e., a kick) can be immediately detected and compensated for (i.e., by increasing the backpressure exerted on the annulus by the choke  30 ). 
     The SMCU  65  may also input a BHP (i.e., from sensor  825 ) during act  1535 . Since this measurement is transmitted to the SMCU  65  using EM or mud-pulse telemetry, the measurement is not available in real time. This is a consequence of the low bandwidth of both EM and mud pulse systems. Further, as discussed above, travel time of the mud-pulse signal becomes significant for deeper wells. The sampling rate of the BHP signal is thus limited. However, the BHP measurement may still be valuable especially as the distance between the DDV  150  and the BHD becomes significant. Since the desired depth will be below the DDV  150 , the SMCU  65  extrapolates the calibrated flow model to calculate the desired depth. Regularly calibrating the annular flow model with the BHP will thus improve the accuracy of the annulus flow model notwithstanding the slow sampling rate. Alternatively, if the drill string  105  is a coiled tubing string (with embedded conductors) or wired drill pipe, then a high bandwidth connection may be established for the BHP measurement. 
     Alternatively, act  1505  may be performed by a separate rig data acquisition system (not shown) which may be in communication with the SMCU  65 . Alternatively, or in addition to the first alternative, acts  1515  and/or  1520  may be performed by an engineer having a separate computer (i.e., a laptop) who may then manually enter or upload the necessary parameters from the annulus flow model (and/or calibrated flow model) to the SMCU  65 . The engineer&#39;s computer may be in communication with the SMCU  65  and/or rig data acquisition system for downloading the necessary data to generate and/or calibrate the annulus flow model. Alternatively, or in addition to the first and second alternatives, acts  1525 ,  1527 , and/or  1530  may be performed manually. 
     During act  1540 , adding or removing drill string segments, the SMCU  65  also maintains the calculated annulus pressure greater than or equal to the formation threshold pressure at the desired depth by i.e., actuating the three-way valve  70 , operating the CCS  350   a  or CFS  350   b , or operating the accumulator  480 . 
       FIG. 16  is a wellbore pressure profile illustrating a desired depth of  FIG. 15 . The pressure sensor  165   b  is shown disposed in the casing string  115  at a depth Ds. Formation changes have caused discontinuities in the fracture pressure profile. The desired depth Dd is the depth where the fracture pressure is at a minimum and is closest to the pore pressure, thereby leaving a narrow drilling window. During a balanced/overbalanced drilling operation, it would be advantageous to maintain the annulus pressure in the narrow drilling window (the annulus pressure at the desired depth Dd is greater than or equal to the pore pressure at the desired depth and less than or equal to the fracture pressure at the desired depth Dd) for reasons discussed above. During act  1525 , the SMCU  65  would calculate the annulus pressure at the desired depth Dd even when the BHD is considerably deeper than the desired depth Dd. Additionally, the SMCU  65  may monitor both the pressure at the desired depth Dd and the BHP and control the choke  30  such that the annulus pressure at the desired depth Dd is in the narrow window while maintaining the BHP in the window at the BHD. Additionally, there may be two or more desired depths between the sensor depth and the BHD. As shown, the fracture pressure profile has become irregular due to changing formations. Alternatively or in addition to, the pore pressure profile (or any of the other threshold pressures) may be become irregular because of formation changes. 
       FIG. 17  is a wellbore pressure gradient profile illustrating an example drilling window (shaded) that is available using the drilling systems  200 ,  250 ,  200 ,  250 ,  300 - 1000 ,  1050 ,  1075 , and  1100 - 1400 . As with  FIGS. 1B and 10B , this is a pressure gradient graph so vertical lines denote a linear increase of pressure with depth. The casing  915  is set at a boundary line of formation A. A first liner  915   a  is set at a boundary line of Formation B. A second liner  915   b  is set at a boundary line of Formation C. The casing  915  and the liners  915   a,b  may be configured as shown in  FIG. 9 , each having pressure sensors and inductive couplings. Alternatively, only the casing  915  may have a DDV or pressure sensor. Alternatively, the liners  915   a,b  may each be strings of casing extending to the surface  5 , each having a DDV or pressure sensor. Alternatively, one of the liners  915   a,b  may be a string of casing and one of the liners may be a liner, each having a DDV or pressure sensor. Alternatively, tie back casing strings, each having a DDV or pressure sensor, may be used with the liners (see  FIGS. 11A and 11B ). 
     The drilling window is bounded on one side by a wellbore stability gradient and on the other side by the lesser of a fracture gradient and a leakoff gradient (when present). The drilling window includes three sub-window portions: an underbalanced portion UB, a mixed underbalanced and overbalanced portion MB, and an overbalanced portion OB. Each of the sub-portions are defined by peaks and valleys of respective boundary lines. For example, during drilling of Formation B, a noticeable valley V and peak P occur in the stability gradient bounding the UB sub-window. After setting the casing string  915 , thereby isolating Formation A, the minimum UB sub-window is determined first by a fairly vertical portion VP of the stability gradient. The gradient then declines into the Valley V. However, the drilling window is not bounded by the valley V because doing so would cause the annulus pressure above the valley to decrease below the vertical portion VP, thereby risking cave-in of the wellbore. Similarly, when the peak P is encountered, it becomes a boundary for drilling at depths below the peak until a greater peak is encountered. Similar principles apply to the other boundary lines. 
     The drilling systems  200 ,  250 ,  200 ,  250 ,  300 - 1000 ,  1050 ,  1075 , and  1100 - 1400  may be used to drill each section of the wellbore  100  in any of the available sub-windows. For example, Formation A may be drilled both in the OB and MB sub-windows. Formation B may be drilled entirely in the UB, MB, or OB sub-windows or may alternate between the three. There are advantages and disadvantages to drilling in each sub-window and these may vary for each particular wellbore  100 . A software modeling package may be used to evaluate the risks and benefits of drilling a particular wellbore in a particular sub-window. These software packages will also provide economic models for each particular mode of drilling, thereby enabling engineers to make informed decisions as to which particular sub-window or combination thereof may be most beneficial. 
     The real time data capabilities of the drilling systems  200 ,  250 ,  200 ,  250 ,  300 - 1000 ,  1050 ,  1075 , and  1100 - 1400  enable better control, thereby enabling an operator to stay at least within the drilling window, preferably a selected sub-window, especially when the windows become very narrow, for example during drilling of Formations C and D. Alternatively, a formation may be drilled outside of the windows, i.e., the BHP is maintained above the leakoff pressure and/or fracture pressure. This alternative may be desirable when drilling through hazardous formations (i.e., hydrogen sulfide) to ensure that the formation does not kick. 
       FIG. 18A  is a pressure profile, similar to  FIG. 1A , showing advantages of one drilling mode that may be performed by any of the drilling systems  200 ,  250 ,  200 ,  250 ,  300 - 1000 ,  1050 ,  1075 , and  1100 - 1400 . As compared to  FIG. 1A , a lighter drilling fluid may be used. The annulus pressure may be maintained in the drilling window by application of backpressure (CP), for example using choke valve  30  of drilling system  200 . During adding or removing segments to or from the drill string, the annulus pressure may be maintained, for example, by using the three-way valve  70  and the choke  30  (SP+CP). Similar results may be obtained by using the accumulator  480  or the CCS/CFS system  350   a, b . Using the lighter drilling fluid allows the target depth D 4  to be reached without setting an intermediate string of casing. 
       FIG. 18B  is a casing program, similar to  FIG. 1B , showing advantages of one drilling mode that may be performed by any of the drilling systems  200 ,  250 ,  200 ,  250 ,  300 - 1000 ,  1050 ,  1075 , and  1100 - 1400 . Since the static pressure SP and dynamic pressure DP of a particular drilling fluid can be equalized and the annulus pressure monitored and controlled in real time, the safety margins may be reduced, thereby greatly reducing the required number of casing strings. As shown, the target depth is achieved with a seven and five-eighths inch casing string which allows the well to be completed with an adequately sized production tubing string. Further, significant cost savings are realized by having to set fewer differently sized casing strings. 
       FIG. 19  illustrates a productivity graph that may be calculated and generated by the SMCU  65  during underbalanced drilling, according to another embodiment of the present invention. The graph includes a productivity curve plotted as a function of productivity (left vertical axis) against measured depth (horizontal axis). The graph may further include a wellbore trajectory curve plotted as a function of total vertical depth (right vertical axis) against measured depth. The productivity value may be calculated by the SMCU  65  using a flow rate of a formation being drilled through measured by the surface MPM  610   a  and/or the downhole MPM  1275 , a pore or shut-in pressure of the formation which may be calculated using pre-existing data and/or data obtained from the LWD sonde  1395  or measured with a transient pressure test, and the BHP calculated using the annulus pressure profile and/or the BHP sensor  865 . The productivity calculation allows for pseudo-quantitative and pseudo-qualitative characterization of a reservoir while underbalanced drilling. Once the productivity curve is generated over the length of the formation, the shape of the productivity curve can be compared to known shapes to determine the formation type (i.e., matrix, fracture, vulgar, channel sand, non-productive, or compartmental). The productivity curve illustrated is of the matrix type. 
     It can be observed the wellbore trajectory curve intersects a productive layer as identified by the productivity curve. The productivity curve may be used to geo-steer during directional (i.e., horizontal) drilling to maximize well productivity while minimizing the length of the wellbore, thereby increasing net present value. Formation factors, such as dip angle, porosity and an approximation of relative in-situ permeability may also be determined. The productivity graph may also identify sub-optimal drilling operational events that may cause undesirable formation impairment. Further, the productivity graph may be used to identify narrow formations that may otherwise have been overlooked using conventional methods. 
       FIG. 20  illustrates a completion system  2000 , according to another embodiment of the present invention. The completion system  2000  may be installed in wellbores  100  drilled with any of the drilling systems  200 ,  250 ,  300 - 1000 ,  1050 ,  1075 , and  1100 - 1400 . The wellbore has been drilled through a hydrocarbon-bearing formation (HC Formation). If the formation has been drilled underbalanced, then the completion system  2000  may also be installed underbalanced (without killing the formation). Part of an inductive coupling  2055  has been installed on the last casing string  2015 . Alternatively, the casing string  2015  may be a liner string. Although only one inductive coupling  2055  is shown, a second inductive coupling may be installed as discussed above in reference to  FIG. 9  (or any other alternatives discussed therewith). The casing string  2015  also includes the DDV  150 . As discussed above, the DDV allows the RCD  15  to be removed when running-in equipment that will not fit through the RCD  15 , i.e., expandable liner  2015   a  and an expansion tool (not shown). 
     The expandable liner  2015   a  has been run-in to a portion of the wellbore  100  extending through the HC Formation and expanded into engagement with the wellbore  100  using an expansion tool (not shown) carried by the run-in string. The expansion tool may be a radial expansion tool having fluid actuated rollers or a cone that is simply pushed/pulled through the liner. The expandable liner  2015   a  includes one or more pressure (or PT) sensors  2065   a, b  in fluid communication with a bore thereof. A control line  2070  disposed in a wall of the expandable liner  2015   a  provides data communication between the pressure sensors  2065   a, b  and part of the inductive coupling  2055 . Alternatively, the control line  2070  may be disposed along an outer surface of the expandable liner  2015   a . The control line  2070  may also provide power to the pressure sensors  2065   a, b . The formation portion of the wellbore  100  may have been underreamed, such as with a bi-center or expandable bit, resulting in a diameter near an inside diameter of the casing string  2015 . The expandable liner  1135   a  may be constructed from one or more layers (three as shown). The three layers include a slotted structural base pipe, a layer of filter media, and an outer protecting sheath, or “shroud”. Both the base pipe and the outer shroud are configured to permit hydrocarbons to flow through perforations formed therein. The filter material is held between the base pipe  1140   a  and the outer shroud, and serves to filter sand and other particulates from entering the liner  2015   a  and a production tubular. Although a vertical completion is shown, the completion system  2000  may also be installed in a lateral wellbore. 
     Alternatively, a conventional solid liner (not shown, see  FIG. 9 ) may be run-in and cemented to the HC Formation and then perforated to provide fluid communication. Alternatively, a perforated liner (and/or sandscreen) and gravel pack may be installed or the HC Formation may be left exposed (a.k.a. barefoot). Alternatively or additionally, a removable or drillable bridge plug may be set in the casing  2015  to isolate the HC Formation for running the expandable liner  915   a . The liner run-in string may then include a retrieval tool or bit and the plug may be disengaged or drilled through to expose the HC formation. The retrieval tool and plug or bit would then be left at the bottom of the wellbore  100 . 
     A packer  2020  has been run-in into the wellbore  100  and actuated into an engagement with an inner surface of the casing  2015 . The packer  2020  may include a removable plug in the tailpipe so the HC Formation is isolated while running-in a string of production tubing  2005 . The string of production tubing  2005  may then be run-in to the wellbore  100 , hung from the wellhead  10 , and engaged with the packer  2020  so that a longitudinal end of the production tubing  2005  is in fluid communication with the liner bore. Alternatively, the packer  2020  and the production tubing  2005  may be run-in to the wellbore during the same trip. Hydrocarbons produced from the formation enter a bore of the liner  2015   a , travel through the liner bore and enter a bore of the production tubing  2005  for transport to the surface. 
     In another embodiment (not shown), a solid (non-perforated) expandable liner and a radial expansion tool may be carried by a drill string in case problem formation (i.e., a non-hydrocarbon water or salt-water bearing formation or a formation with a low leak-off or fracture pressure) is encountered while drilling. To isolate the problem formation, the liner and expansion tool may be aligned with the formation boundary and the radial expansion tool may be activated, thereby expanding a portion of the liner into engagement with the formation. The drill string and expansion tool may then be advanced/retracted (even while drilling) to expand the rest of the liner into engagement with the problem formation. The problem formation is then isolated from contamination into or production from during the drilling operation and subsequent production from other formations without requiring a separate trip. This embodiment may be compatible with any of the drilling systems  200 ,  250 ,  300 - 1000 ,  1050 ,  1075 , and  1100 - 1400 . 
     In another embodiment, a method for drilling a wellbore includes an act of drilling the wellbore by injecting drilling fluid through a tubular string disposed in the wellbore, the tubular string comprising a drill bit disposed on a bottom thereof. The drilling fluid exits the drill bit and carries cuttings from the drill bit. The drilling fluid and cuttings (returns) flow to a surface of the wellbore via an annulus defined by an outer surface of the tubular string and an inner surface of the wellbore. The method further includes an act performed while drilling the wellbore of measuring a first annulus pressure (FAP) using a pressure sensor attached to a casing string hung from a wellhead of the wellbore. The method further includes an act performed while drilling the wellbore of controlling a second annulus pressure (SAP) exerted on a formation exposed to the annulus. In one aspect of the embodiment, the pressure sensor is at or near a bottom of the casing string. 
     In another aspect of the embodiment, the method further includes transmitting the FAP measurement to a surface of the wellbore using a high-bandwidth medium. The pressure sensor may be in communication with a surface monitoring and control unit (SMCU) via a cable disposed along an outer surface of the casing string or within a wall of the casing string. The antenna may be attached to the casing string. The drill string may include a second pressure sensor at or near a bottom thereof configured to measure a bottom hole pressure (BHP) and a gap sub in communication with the second pressure sensor. The method may further include transmitting a BHP measurement from the drill string gap sub to the casing string antenna and relaying the BHP measurement to the surface via the cable. A liner string may be hung from the casing string at or near a bottom of the casing string. The liner string may have a second pressure sensor configured to measure a third annulus pressure (TAP). Each of the casing string and the liner may have part of an inductive coupling. The method may further include measuring the TAP with the liner sensor; transmitting the TAP measurement from the liner to the casing string via the inductive coupling; and relaying the TAP measurement to the SMCU via the cable. 
     In another aspect of the embodiment, the method may further include calculating the SAP using the FAP measurement. The FAP may be continuously measured and the SAP may be continuously calculated. The SAP may be calculated using at least one of a standpipe pressure and a wellhead pressure and at least one of a flow rate of drilling fluid injected into the tubular string and a flow rate of the returns. The method may further include, while drilling, measuring a bottom hole pressure (BHP); and wirelessly transmitting the BHP measurement to the casing string or to the surface of the wellbore. The tubular string may further include a pressure sensor disposed at or near a bottom thereof and a second pressure sensor longitudinally spaced at a distance from the pressure sensor. 
     In another aspect of the embodiment, the measuring and controlling acts are performed by a computer or microprocessor controller. In another aspect of the embodiment, the SAP is controlled by choking fluid flow of the returns. In another aspect of the embodiment, the returns enter a separator and the SAP is controlled by choking gas flow from the separator. In another aspect of the embodiment, the SAP is controlled by controlling an injection rate of the drilling fluid. 
     In another aspect of the embodiment, the drilling fluid is a mixture formed by mixing a liquid portion and a gas portion and the SAP is controlled by controlling a flow rate of the gas portion. The drilling fluid may be injected into the tubular string using a multiphase pump. In another aspect of the embodiment, the method further includes measuring a flow rate of a liquid portion of the returns and a flow rate of a gas portion of the returns using a multiphase meter (MPM). The MPM may be disposed in the wellbore. In another aspect of the embodiment, the method further includes calculating a productivity of a formation while drilling through the formation. The tubular string may be a drill string and the method further may further include geo-steering the drill string using the calculated productivity. 
     In another aspect of the embodiment, the method further includes measuring an injection rate of the drilling fluid; and comparing the injection rate to a flow rate of the returns. The tubular string may be a drill string. The drilling fluid may be injected into a first chamber of the drill string. The SAP may be controlled by injecting a fluid having a density different from a density of the drilling fluid through a second chamber of the drill string. In another aspect of the embodiment, the method further includes separating gas from the returns using a high-pressure separator and separating the cuttings from the returns using a low pressure separator. The SAP may be controlled so that the SAP is less than a pore pressure of the formation and the method further comprises recovering crude oil produced from the formation from the returns. 
     In another aspect of the embodiment, the tubular string is a drill string including joints of drill pipe joined by threaded connections. The method may further include adding or removing a joint of drill pipe to the drill string; and controlling the SAP while adding or removing the joint to/from the drill string. The SAP may be controlled while adding or removing the joint by pressurizing the annulus. The annulus may be pressurized by circulating fluid through a choke. The wellbore may be a subsea wellbore. A riser string may extend from a rig at a surface of the sea to or near a floor of the sea. The riser string may be in selective fluid communication with the wellbore. A bypass line may extend from a platform at a surface of the sea to or near a floor of the sea. The bypass line may be in selective fluid communication with the wellbore. The SAP may be controlled while adding or removing the joint by injecting a second fluid into the bypass line. 
     The SAP may be controlled while adding or removing the joint using a continuous circulation system or a continuous flow sub disposed in the drill string. The continuous circulation system may include a housing having upper and lower chambers, a gate valve operable to selectively isolate the upper chamber from the lower chamber, an upper control head operable to engage a joint to be added or removed to the drill string, and a lower control head operable to engage the drill string. The continuous flow sub may include a housing having a longitudinal bore disposed therethrough and a side port disposed through a wall thereof, a first valve operable to isolate an upper portion of the bore from a lower portion of the bore in response to drilling fluid being injected through the side port, a second valve operable to isolate the side port from the bore in response to drilling fluid being injected through the bore. The method may further include charging an accumulator while drilling. The SAP may be controlled while adding or removing the joint by pressurizing the annulus with the accumulator. The returns may enter a separator and the SAP may be controlled while adding or removing the joint by pressurizing the separator. 
     In another aspect of the embodiment, the SAP is controlled so that the SAP is greater than or equal to a pore pressure of the formation. In another aspect of the embodiment, the SAP is controlled so that the SAP is greater than or equal to a wellbore stability pressure (WSP) of the formation. In another aspect of the embodiment, the SAP is controlled to be within a window defined by a first threshold pressure of the formation, with or without a safety margin therefrom, and a second threshold pressure of the formation, with or without a safety margin therefrom. In another aspect of the embodiment, the SAP is a bottom hole pressure. In another aspect of the embodiment, a depth of the SAP is distal from a bottom of the wellbore. The method may further include, while drilling, calculating the SAP using the FAP; and calculating a bottom hole pressure (BHP) using the FAP. 
     In another aspect of the embodiment, the casing string is a tie-back casing string. The second casing string may be disposed in the wellbore. A tie-back annulus may be defined between the tie-back casing string and the second string of casing. The SAP may be controlled by injecting a second fluid having a density different from a density of the drilling fluid through the tie-back annulus. A second casing string may be disposed in the wellbore. A tie-back annulus may be defined between the tie-back casing string and the second string of casing. A mudcap may be maintained in a bore of the tie-back casing string or in the tie-back annulus, the mudcap being a fluid having a density substantially greater than a density of the drilling fluid. A plurality of pressure sensors (TBPS) may be disposed along a length of the tie-back casing string. The method may further include monitoring a level of an interface between the mudcap and the returns using the TBPS. 
     In another aspect of the embodiment, the casing string is cemented to the wellbore. In another aspect of the embodiment, a downhole deployment valve (DDV) is assembled as part of the casing string proximate to the sensor. The DDV may include a housing having a longitudinal bore therethrough in fluid communication with a bore of the casing string, a flapper or ball operable to isolate an upper portion of the casing string bore from a lower portion of the casing string bore, the pressure sensor in communication with the lower portion of the casing string bore, and a second pressure sensor in communication with the upper portion of the casing string bore. The casing string may be a tie-back casing string. A second casing string may be disposed in the wellbore and cemented thereto. A liner may be hung from the second casing string at or near a bottom of the second casing string. The method may further include removing the tie-back casing string from the wellbore, attaching a second liner to the first liner at or near a bottom of the first liner, cementing the second liner to the wellbore, inserting a second tie-back casing string, having a second DDV assembled as a part thereof and a second pressure sensor attached thereto proximate the second DDV, into the wellbore, and forming a seal between the second liner and the second tie-back casing string. 
     In another aspect of the embodiment, the tubular string is a drill string further including an equivalent circulation density reduction tool (ECDRT). The ECDRT may include a motor, a pump, and an annular seal. The drilling fluid may operate the motor. The annular seal may be engaged with the casing string and may divert the returns from the annulus and through the pump. The pump may be rotationally coupled to the motor, thereby being operated by the motor. The pump may add energy to the returns, thereby reducing an equivalent circulation density (ECD) of the returns. A second pressure sensor may be attached along the casing string so that the pressure sensor is in fluid communication with an inlet of the pump and the second pressure sensor is in fluid communication with an outlet of the pump. The method may further include measuring a third annulus pressure (TAP) using the second pressure sensor while drilling the wellbore. The method may further include monitoring operation of the ECDRT using the FAP and the TAP. The SAP may be controlled by controlling an operating parameter of the ECDRT. The ECDRT operating parameter may be an injection rate of the drilling fluid. 
     In another aspect of the embodiment, the tubular string is a drill string, the drill string further comprises a logging while drilling (LWD) sonde, and the method further includes determining lithology, permeability, porosity, water content, oil content, and gas content of a formation while drilling through the formation. In another aspect of the embodiment, the tubular string may include a second casing string or liner string and the method further includes hanging the second casing string or liner string from the wellhead or the casing string. The casing string may be cemented to the wellbore and may include a pressure sensor and a first part of an inductive coupling. The second casing string or liner string may further include a mud motor coupled to the drill bit, a pressure sensor attached near the bottom thereof, a cable disposed within a wall of the tubular string, the cable in communication with the pressure sensor and a second part of an inductive coupling disposed at or near a top of the tubular string. The second casing string or liner string may be hung from the casing string when the second part of the inductive coupling is in longitudinal alignment or near alignment with the first part of the inductive coupling. 
     In another aspect of the embodiment, a density of the drilling fluid is less than that required to maintain the formation in a balanced or an overbalanced state, and the SAP is controlled to maintain the formation in the balanced or overbalanced state. In another aspect of the embodiment, the method further includes running a sand screen into the formation; and expanding the sand screen into engagement with the formation. The casing string may be cemented to the wellbore and may include a pressure sensor and a first part of an inductive coupling. The sand screen may further include a pressure sensor, and a cable disposed along an outer surface of the liner string or within a wall of the liner string, the cable in communication with the pressure sensor and a second part of an inductive coupling disposed at or near a top of the sand screen. The sand screen may be expanded when the second part of the inductive coupling is in longitudinal alignment or near alignment with the first part of the inductive coupling. 
     In another aspect of the embodiment, the tubular string is a drill string and the drill string further includes a length of expandable liner and a radial expansion tool. The method may further include aligning the expandable liner with a problem formation, and expanding the liner into engagement with the problem formation, thereby isolating the problem formation. 
     In another embodiment, a method for drilling a wellbore includes an act of drilling the wellbore by injecting drilling fluid into a tubular string comprising a drill bit disposed on a bottom thereof. The drilling fluid is injected at a drilling rig. The method further includes an act performed while drilling the wellbore and at the drilling rig of continuously receiving a first annulus pressure (FAP) measurement measured at a location distal from the drilling rig and distal from a bottom of the wellbore. The method further includes an act performed while drilling the wellbore and at the drilling rig of continuously calculating a second annulus pressure (SAP) exerted on an exposed portion of the wellbore. The method further includes an act performed while drilling the wellbore and at the drilling rig of controlling the SAP. 
     In one aspect of the embodiment, the method further includes, while drilling the wellbore and at the drilling rig, intermittently receiving a bottom hole pressure (BHP) measured at a location near a bottom of the wellbore; and intermittently calibrating the calculated SAP using the BHP measurement. In another aspect of the embodiment, the wellbore may be a subsea wellbore. A riser string may extend from the rig at a surface of the sea to a wellhead of the wellbore at a floor of the sea. The riser string may be in fluid communication with the wellbore. The FAP may be measured using a pressure sensor attached to the riser string or the wellhead. 
     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.