Patent Publication Number: US-9845653-B2

Title: Fluid supply to sealed tubulars

Description:
CROSS-REFERENCE TO RELATED APPLICATIONS 
     This application is a continuation of prior application Ser. No. 14/163,617 filed on 24 Jan. 2014, which is a continuation of U.S. Pat. No. 8,636,087, which is a division of U.S. Pat. No. 8,347,983. The entire disclosures of these prior applications are incorporated herein by this reference. 
    
    
     STATEMENT REGARDING FEDERALLY SPONSORED RESEARCH OR DEVELOPMENT 
     N/A 
     REFERENCE TO MICROFICHE APPENDIX 
     N/A 
     BACKGROUND OF THE INVENTION 
     1. Field of the Invention 
     The present invention relates to rotating control devices used when drilling wells and methods for use of these rotating control devices. 
     2. Description of the Related Art 
     Rotating control devices (RCDs) have been used for many years in the drilling industry for drilling wells. An internal sealing element fixed with an internal member of the RCD seals around the outside diameter of a tubular and rotates with the tubular. The tubular may be slidingly run through the RCD as the tubular rotates or when the tubular, such as a drill string, casing or coil tubing is not rotating. Examples of some proposed RCDs are shown in U.S. Pat. Nos. 5,213,158; 5,647,444 and 5,662,181. The internal sealing element may be passive or active. Passive sealing elements, such as stripper rubber sealing elements, can be fabricated with a desired stretch-fit. The wellbore pressure in the annulus acts on the cone shaped stripper rubber sealing elements with vector forces that augment a closing force of the stripper rubber sealing elements around the tubular. An example of a proposed stripper rubber sealing element is shown in U.S. Pat. No. 5,901,964. RCDs have been proposed with a single stripper rubber sealing element, as in U.S. Pat. Nos. 4,500,094 and 6,547,002; and Pub. No. US 2007/0163784, and with dual stripper rubber sealing elements, as in the &#39;158 patent, &#39;444 patent and the &#39;181 patent, and U.S. Pat. No. 7,448,454. U.S. Pat. No. 6,230,824 proposes two opposed stripper rubber sealing elements, the lower sealing element positioned in an axially downward, and the upper sealing element positioned in an axially upward (see FIGS. 4B and 4C of &#39;824 patent). 
     Unlike a stripper rubber sealing element, an active sealing element typically requires a remote-to-the-tool source of hydraulic or other energy to open or close the sealing element around the outside diameter of the tubular. An active sealing element can be deactivated to reduce or eliminate the sealing forces of the sealing element with the tubular. RCDs have been proposed with a single active sealing element, as in the &#39;784 publication, and with a stripper rubber sealing element in combination with an active sealing element, as in U.S. Pat. Nos. 6,016,880 and 7,258,171 (both with a lower stripper rubber sealing element and an upper active sealing element), and Pub. No. US 2005/0241833 (with lower active sealing element and upper stripper rubber sealing element). 
     A tubular typically comprises sections with varying outer surface diameters. RCD passive and active sealing elements must seal around all of the rough and irregular surfaces of the components of the tubular, such as hardening surfaces (such as proposed in U.S. Pat. No. 6,375,895), drill pipe, tool joints, and drill collars. The continuous movement of the tubular through the sealing element while the sealing element is under pressure causes wear of the interior sealing surface of the sealing element. When drilling with a dual annular sealing element RCD, the lower of the two sealing elements is typically exposed to the majority of the pressurized fluid and cuttings returning from the wellbore, which communicate with the lower surface of the lower sealing element body. The upper sealing element is exposed to the fluid that is not blocked by the lower sealing element. When the lower sealing element blocks all of the pressurized fluid, the lower sealing element is exposed to a significant pressure differential across its body since its upper surface is essentially at atmospheric pressure when used on land or atop a riser. The highest demand on the RCD sealing elements occurs when tripping the tubular out of the wellbore under high pressure. 
     American Petroleum Institute Specification 16RCD (API-16RCD) entitled “Specification for Drill Through Equipment—Rotating Control Devices,” First Edition, © February 2005 American Petroleum Institute, proposes standards for safe and functionally interchangeable RCDs. The requirements for API-16RCD must be complied with when moving the drill string through a RCD in a pressurized wellbore. The sealing element is inherently limited in the number of times it can be fatigued with tool joints that pass under high differential pressure conditions. Of course, the deeper the wellbores are drilled, the more tool joints that will be stripped through sealing elements, some under high pressure. 
     In more recent years, RCDs have been used to contain annular fluids under pressure, and thereby manage the pressure within the wellbore relative to the pressure in the surrounding earth formation. During such use, the sealing element in the RCD can be exposed to extreme wellbore fluid pressure variations and conditions. In some circumstances, it may be desirable to drill in an underbalanced condition, which facilitates production of formation fluid to the surface of the wellbore since the formation pressure is higher than the wellbore pressure. U.S. Pat. No. 7,448,454 proposes underbalanced drilling with an RCD. At other times, it may be desirable to drill in an overbalanced condition, which helps to control the well and prevent blowouts since the wellbore pressure is greater than the formation pressure. While Pub. No. US 2006/0157282 generally proposes Managed Pressure Drilling (MPD), International Pub. No. WO 2007/092956 proposes Managed Pressure Drilling (MPD) with an RCD. Managed Pressure Drilling (MPD) is an adaptive drilling process used to control the annulus pressure profile throughout the wellbore. The objectives are to ascertain the downhole pressure environment limits and to manage the hydraulic annulus pressure profile accordingly. 
     One equation used in the drilling industry to determine the equivalent weight of the mud and cuttings in the wellbore when circulating with the rig mud pumps on is:
 
Equivalent Mud Weight (EMW)=Mud Weight Hydrostatic Head+ΔCirculating Annulus Friction Pressure (AFP)
 
This equation would be changed to conform the units of measurements as needed.
 
In one variation of MPD, the above Circulating Annulus Friction Pressure (AFP), with the rig mud pumps on, is swapped for an increase of surface backpressure, with the rig mud pumps off, resulting in a Constant Bottomhole Pressure (CBHP) variation of MPD, or a constant EMW, whether the mud pumps are circulating or not. Another variation of MPD is proposed in U.S. Pat. No. 7,237,623 for a method where a predetermined column height of heavy viscous mud (most often called kill fluid) is pumped into the annulus. This mud cap controls drilling fluid and cuttings from returning to surface. This pressurized mud cap drilling method is sometimes referred to as bull heading or drilling blind.
 
     The CBHP MPD variation is achieved using non-return valves (e.g., check valves) on the influent or front end of the drill string, an RCD and a pressure regulator, such as a drilling choke valve, on the effluent or back return side of the system. One such drilling choke valve is proposed in U.S. Pat. No. 4,355,784. A commercial hydraulically operated choke valve is sold by M-I Swaco of Houston, Tex. under the name SUPER AUTOCHOKE. Also, Secure Drilling International, L.P. of Houston, Tex., now owned by Weatherford International, Inc., has developed an electronic operated automatic choke valve that could be used with its underbalanced drilling system proposed in U.S. Pat. Nos. 7,044,237; 7,278,496 and 7,367,411 and Pub. No. US2008/0041149 A1. In summary, in the past, an operator of a well has used a manual choke valve, a semi-automatic choke valve and/or a fully automatic choke valve for an MPD program. 
     Generally, the CBHP MPD variation is accomplished with the choke valve open when circulating and the choke valve closed when not circulating. In CBHP MPD, sometimes there is a 10 choke-closing pressure setting when shutting down the rig mud pumps, and a 10 choke-opening setting when starting them up. The mud weight may be changed occasionally as the well is drilled deeper when circulating with the choke valve open so the well does not flow. Surface backpressure, within the available pressure containment capability rating of an RCD as discussed below, is used when the pumps are turned off (resulting in no AFP) during the making of pipe connections to keep the well from flowing. Also, in a typical CBHP application, the mud weight is reduced by about 0.5 ppg from conventional drilling mud weight for the similar environment. Applying the above EMW equation, the operator navigates generally within a shifting drilling window, defined by the pore pressure and fracture pressure of the formation, by swapping surface backpressure, for when the pumps are off and the AFP is eliminated, to achieve CBHP. 
     As discussed above, the CBHP MPD variation can only apply surface backpressure within the available pressure containment rating of an RCD. Pressure test results before the Feb. 6, 1997 filing date of the &#39;964 patent for the Williams Model 7100 RCD disclose stripper rubber sealing element failures at working pressures above 2500 psi (17,237 kPa) when the drill string is rotating. The Williams Model 7100 RCD with 7 inch (17.8 cm) ID is designed for a static pressure of 5000 psi (34,474 kPa) when the drill pipe is not rotating. The Williams Model 7100 RCD is available from Weatherford International of Houston, Tex. Weatherford International also manufactures a Model 7800 RCD and a Model 7900 RCD.  FIG. 6  is a pressure rating graph for the Weatherford Model 7800 RCD that shows wellbore pressure in pounds per square inch (psi) on the vertical axis, and RCD rotational speed in revolutions per minute (RPM) on the horizontal axis. The maximum allowable wellbore pressure without exceeding operational limits for the Weatherford Model 7800 RCD is 2500 psi (17,237 kPa) for rotational speeds of 100 RPM or less. The maximum allowable pressure decreases for higher rotational speeds. Like the Williams Model 7100 RCD, the Weatherford Model 7800 RCD has a maximum allowable static pressure of 5000 psi (34,474 kPa). The Williams Model 7100 RCD and the Weatherford Model 7800 and Model 7900 RCDs all have passive sealing elements. Weatherford also manufactures a lower pressure Model 7875 self-lubricated RCD bearing assembly with top and bottom flanges and a lower pressure Model 7875 self-lubricated bell nipple insert RCD bearing assembly with a bottom flange only. Since neither Model 7875 has means of circulating coolant to remove frictional heat, their pressure vs. RPM ratings are lower than the Model 7800 and the Model 7900. Weatherford also manufactures an active sealing element RCD, RBOP 5K RCD with 7 inch ID, which has a maximum allowable stripping pressure of 2500 psi, maximum rotating pressure of 3500 psi (24,132 kPa), and maximum static pressure of 5000 psi. 
     Pressure differential systems have been proposed for use with RCD components in the past. For example, U.S. Pat. No. 5,348,107 proposes a pressurized lubricant system to lubricate certain seals that are exposed to wellbore fluid pressures. However, unlike the RCD tubular sealing elements discussed above, the seals that are lubricated in the &#39;107 patent do not seal with the tubular. Pub. No. US 2006/0144622 also proposes a system to regulate the pressure between two radial seals. Again, the seals subject to this pressure regulation do not seal with the drill string. The &#39;622 publication also proposes an active sealing element in which fluid is supplied to energize a flexible bladder, and the pressure within the bladder is maintained at a controlled level above the wellbore pressure. The &#39;833 publication proposes an active sealing element in which a hydraulic control maintains the fluid pressure that urges the sealing element toward the drill string at a predetermined pressure above the wellbore pressure. U.S. Pat. No. 7,258,171 proposes a system to pressurize lubricants to lubricate bearings at a predetermined pressure in relation to the surrounding subsea water pressure. Also, U.S. Pat. No. 4,312,404 proposes a system for leak protection of a rotating blowout preventer and U.S. Pat. No. 4,531,591 proposes a system for lubrication of an RCD. 
     The above discussed U.S. Pat. Nos. 4,312,404; 4,355,784; 4,500,094; 4,531,591; 5,213,158; 5,348,107; 5,647,444; 5,662,181; 5,901,964; 6,016,880; 6,230,824; 6,375,895; 6,547,002; 7,040,394; 7,044,237; 7,237,623; 7,258,171; 7,278,496; 7,367,411; 7,448,454; and 7,487,837; and Pub. Nos. US 2005/0241833; 2006/0144622; 2006/0157282; and 2007/0163784; 2008/0041149; and International Pub. No. WO 2007/092956 or PCT/US2007/061929 are hereby incorporated by reference for all purposes in their entirety. U.S. Pat. Nos. 5,647,444; 5,662,181; 5,901,964; 6,547,002; 7,040,394; 7,237,623; 7,258,171; 7,448,454 and 7,487,837; and Pub. Nos. US 2005/0241833; 2006/0144622; 2006/0157282; and 2007/0163784; and International Pub. No. WO 2007/092956 or PCT/US2007/061929 are assigned to the assignee of the present invention. 
     A need exists for an RCD that can safely operate in dynamic or working conditions in annular wellbore fluid pressures greater than 2500 psi (17,237 kPa). Customers of the drilling industry have expressed a desire for a higher safety factor in both the static and dynamic rating of available RCDs for certain applications. A higher safety factor or dynamic rating would allow for use of RCDs to manage pressurized systems in well prospects with high wellbore pressure, such as in deep offshore wells. It would also be desirable if the design of the RCD complied with API-16RCD requirements. Furthermore, use of the higher rated RCD with a higher surface backpressure with a fluid program that disregards pore pressure and instead uses the fracture pressure of the formation and casing shoe leak off or pressure test as limiting pressure factors would be desirable. This novel drilling limitation variation of MPD would be desirable in that it would allow use of readily available, lighter mud weight and less expensive drilling fluids while drilling deeper with a larger resulting tubular opening area. 
     BRIEF SUMMARY OF THE INVENTION 
     A method and system are provided a high pressure rated RCD by, among other features, limiting the fluid pressure differential to which a RCD sealing element is exposed. For a dual annular sealing element RCD, a pressurized cavity fluid is communicated to the RCD cavity located between the two sealing elements. Sensors can be positioned to detect the wellbore annulus fluid pressure and temperature and the cavity fluid pressure and temperature in the RCD cavity and at other desired locations. The pressures and temperatures may be compared, and the cavity fluid pressure and temperature applied in the RCD cavity may be adjusted. The pressure differential to which one or more of the sealing elements is exposed may be reduced. The cavity fluid may be water, drilling fluid, gas, lubricant from the bearings, coolant from the cooling system, or hydraulic fluid used to activate an active sealing element. The cavity fluid may be circulated, which may be beneficial for lubricating and cooling or may be bullheaded. In another embodiment, the RCD may have more than two sealing elements. Pressurized cavity fluids may be communicated to each of the RCD internal cavities located between the sealing elements. Sensors can be positioned to detect the wellbore annulus fluid pressure and temperature and the cavity fluid pressures and temperatures in the RCD cavities. Again, the pressures and temperatures may be compared, and the cavity fluid pressures and temperatures in all of the RCD internal cavities may be adjusted. 
     In still another embodiment, conventional RCDs and rotating blowout preventers RBOPs can be stacked and adapted to communicate cavity fluid to their respective cavities to share the differential pressure across the sealing elements. 
     With a higher pressure rated RCD, a Drill-To-The-Limit (DTTL) drilling method variant to MPD would be feasible where surface backpressure is applied whether the mud is circulating (choke valve open) or not (choke valve closed). Because of the constant application of surface backpressure, the DTTL method can use lighter mud weight that still has the cutting carrying ability to keep the borehole clean. With a higher pressure rated RCD, the DTTL method would identify the weakest component of the pressure containment system, usually the fracture pressure of the formation or the casing shoe Leak Off Test (LOT) or pressure test. In the DTTL method, since surface backpressure is constantly applied, the pore pressure limitation of the conventional drilling window, such as used in the CBHP method and other MPD methods, can be disregarded in developing the fluid and drilling programs. 
     With a higher pressure rated RCD, such as 5,000 psi dynamic or working pressure and 10,000 psi static pressure, the limitation will usually be the fracture pressure of the formation or the LOT. Using the DTTL method, a deeper wellbore can be drilled with a larger resulting end tubulars opening area, such as casings or production liners, than would be possible with any other MPD application, including, but not limited to, the CBHP method. 
    
    
     
       BRIEF DESCRIPTION OF THE DRAWINGS 
       A better understanding of the present invention can be obtained with the following detailed descriptions of the various disclosed embodiments in the drawings: 
         FIG. 1  is a multiple broken elevational view of an exemplary embodiment of a land drilling rig showing an RCD positioned above a blowout preventer (“BOP”) stack, a cemented casing and casing shoe in partial cut away section, and a drill string extending through a formation into a wellbore. 
         FIG. 2  is a multiple broken elevational view of an exemplary embodiment of a floating semi-submersible drilling rig showing a RCD positioned above a BOP stack, a marine riser extending upward from an annular BOP on the surface, a cemented casing and casing shoe in partial cut away section, and a drill string extending through a formation into the wellbore. 
         FIG. 3  is a comparison chart of fluid programs and casing programs for the prior art conventional and Constant Bottom Hole Pressure “CBHP” MPD methods versus the DTTL method while drilling through a number of geological anomalies such as the Touscelousa (near Baton Rouge, La.) sand problems. 
         FIG. 4  is a comparison chart comparing the fluid programs and casing programs for prior art conventional and CBHP MPD methods versus the DTTL method for a jack-up rig in 400′ of water. 
         FIG. 4A  is a comparison chart of a light mud pressure gradient to a heavy mud pressure gradient relative to a pore pressure/fracture pressure window. 
         FIG. 5A  is a comparison chart of a prior art deep water well design for conventional versus Drilling with Casing (DwC). 
         FIG. 5B  is a comparison chart of casing programs comparing the prior art conventional program to the DTTL method program that provides two contingency casing strings. 
         FIG. 5C  is a comparison chart of casing programs using the prior art conventional fluid program to 16,000′ then using the DTTL method to provide a contingency casing string. 
         FIG. 6  is a prior art wellbore pressure rating vs. RPM graph for an exemplary prior art Weatherford Model 7800 RCD. 
         FIG. 7  is a cut away section elevational view of an RCD with two passive sealing elements, sensors for measuring pressures and temperatures in the diverter housing and the RCD internal cavity, and influent and effluent lines for circulating cavity fluid into, in and out of the RCD internal cavity. Also, arrows illustrate pressurized flow of fluids to cool the bottom passive sealing element. 
         FIG. 8  is a cut away section elevational view of an RCD with a lower active sealing element (shown inflated on one side and deflated on the other side to allow the tool joint to pass) and an upper passive sealing element, sensors for measuring pressures and temperatures in the diverter housing and the RCD internal cavity, and influent and effluent lines for circulating cavity fluid into, in and out of the RCD internal cavity. 
         FIG. 9  is a cut away section elevational view of an RCD with a lower active sealing element and two upper passive sealing elements, sensors for measuring pressures and temperatures from the diverter housing and into, in and out of the RCD upper and lower internal cavities, and influent and effluent lines for communicating cavity fluid into, in and out of each RCD internal cavity. 
         FIG. 10  is a cut away section elevational view of an RCD with two passive sealing elements, sensors for measuring pressures and temperatures in the diverter housing and into the RCD internal cavity, a pressure regulator, and influent and effluent lines for circulating cavity fluid into, in and out of the RCD internal cavity. Also, arrows illustrate pressurized flow of fluids to cool the bottom passive sealing element. 
         FIG. 11  is a cut away section elevational view of an RCD with three passive sealing elements positioned with a unitary housing, sensors for measuring pressures and temperatures in the diverter housing and into and out of the RCD upper and lower internal cavities, upper and lower RCD internal cavity pressure regulators, a mud line to communicate mud to the cavities via their respective regulators and influent and effluent lines for communicating cavity fluid into, in and out of each RCD internal cavity. 
         FIG. 11A  is enlarged detailed elevational cross-sectional view of the RCD upper pressure compensation means as indicated in  FIG. 11  to maintain the lubrication pressure above the wellbore pressure. 
         FIG. 11B  is enlarged detailed elevational cross-sectional view of the RCD lower pressure compensation means as indicated in  FIG. 11  to maintain the lubrication pressure above the wellbore pressure. 
         FIGS. 12A and 12B  is a cut away section elevational view of an RCD with four passive sealing elements, sensors for measuring pressures and temperatures into, in and out of the diverter housing and into and out of the three RCD internal cavities, three RCD internal cavity pressure regulators and influent and effluent lines for communicating cavity fluid into, in and out of each RCD internal cavity. A programmable logic controller “PLC” is wired to the three pressure regulators to provide desired relative pressures in each cavity for differential pressure and/or “burps” of the sealing elements with, for example, a nitrogen pad. 
         FIGS. 13A, 13B and 13C  is a cut away section elevational view of an RCD with an active sealing element and three passive sealing elements on a common RCD inner member above another independent active sealing element, sensors for measuring pressures and temperatures in the diverter housing and the RCD four internal cavities between these five sealing elements, four RCD internal cavity pressure regulators, ports in the RCD bearing assembly for communicating cavity fluid with each RCD internal cavity. Some of the housings and spools are connected by bolting and the remaining housing and spools are connected using a clam shell clamping device. 
         FIGS. 14A and 14B  is a cut away section elevational view of an RCD with two passive sealing elements above an independent active sealing element, sensors for measuring pressures and temperatures in the diverter housing and the RCD internal cavities, upper and lower RCD internal cavity pressure regulators, sized ports in the RCD bearing assembly for communicating cavity fluid with each RCD internal cavity. The regulators are provided with an accumulator, and a solenoid valve is located in a line running from the diverter housing for controlling mud with cuttings to the upper two pressure regulators. The active sealing element can be pressurized to reduce slippage with the tubular if the PLC indicates rotational velocity differences between the passive sealing elements and the active sealing element. 
         FIGS. 15A, 15B and 15C  is a cut away section elevational view of an RCD with four passive sealing elements, sensors for measuring pressures and temperatures in the diverter housing and the three RCD internal cavities, three RCD internal cavity pressure regulators and sized ports in the RCD bearing assembly for communicating cavity fluid with each RCD internal cavity. 
         FIGS. 16A and 16B  is a cut away section elevational view of an RCD with one active sealing element and two passive sealing elements, sensors for measuring pressures and temperatures in the diverter housing and into the RCD upper and lower internal cavities, upper and lower RCD internal cavity pressure regulators, and influent and effluent lines for communicating cavity fluid into, in and out of each RCD internal cavity. Three accumulators are provided in the line connecting the upper and lower pressure regulators. The active sealing element pressure can be controlled by the PLC relative to the rotation of the inner member supporting the two passive sealing elements. 
         FIGS. 17A and 17B  is a cut away section elevational view of an RCD with two passive sealing elements above an independent active sealing element, sensors for measuring pressures and temperatures in the diverter housing and the RCD upper and lower internal cavities, upper and lower RCD internal cavity pressure regulators and ports in the RCD bearing assembly for communicating cavity fluid with each RCD internal cavity. An accumulator is provided in the lines between the pressure regulators and a solenoid valve is provided in the line from the diverter housing. Additionally, the tubular extending through the RCD is provided with a stabilizer below the RCD. 
     
    
    
     DETAILED DESCRIPTION OF THE INVENTION 
     The DTTL method and the pressure sharing RCD systems may be used in many different drilling environments, including those environments shown in  FIGS. 1 and 2 . Exemplary drilling rigs or structures for use with the invention, generally indicated as S, are shown in  FIGS. 1 and 2 . Although a land drilling rig S is shown in  FIG. 1 , and an offshore floating semi-submersible rig S is shown in  FIG. 2 , other drilling rig configurations and embodiments are contemplated for use with the invention for both offshore and land drilling. For example, the invention is equally applicable to drilling rigs such as jack-up, semi-submersibles, submersibles, drill ships, barge rigs, platform rigs, and land rigs. Turning to  FIG. 1 , an RCD  10  is positioned below the drilling deck or floor F of the drilling rig S and above the BOP stack B. RCD  10  may include any of the RCD pressure sharing systems shown in  FIGS. 7 to 17B  or other adequately pressure rated RCD. The RCD, where possible, should be sized to be received through the opening in the drilling deck or floor F. The BOP stack B is positioned over the wellhead W. Casing C is hung from wellhead W and is cemented into position. Casing shoe CS at the base of casing C is also cemented into position. Drilling string DS extends through the RCD  10 , BOP stack B, wellhead W, casing C, wellbore WB and casing shoe CS into the wellbore borehole BH. As used herein, a wellbore WB may have casing in it or may be open (i.e., uncased as wellbore borehole BH); or a portion of it may be cased and a portion of it may be open. Mud pump P is on the surface and is in fluid communication with mud pit MP and drill string DS. 
     In  FIG. 2 , casing C is hung from wellhead W, which is positioned on the ocean floor. Casing C is cemented in place along with casing shoe CS. Marine riser R extends upward from the top of the wellhead W. Drill string DS is positioned through the RCD  10 , BOP stack B, riser R, wellhead W, casing C and wellbore WB into the wellbore borehole BH. BOP stack B is on top of riser R, and RCD  10  is positioned over BOP stack B and below rig floor F. Mud pump P is on the drilling rig and is in fluid communication with mud tank MT and drill string DS. 
     DTTL Method 
     In the DTTL method, a pressure containment system may be configured with casing C, a pressure rated RCD, such as a pressure sharing RCD system; for example, as shown in  FIGS. 7 to 17B , drill string non-return or check valves, a drilling choke manifold with a manual or adjustable automatic choke valve, and a mud-gas separator or buster. As will be discussed below in detail, in the DTTL method, the weakest component of the well construction program is determined. This will usually be the fracture gradient of the formation, the casing shoe integrity, or the integrity of any other component of the closed pressurized circulating fluid system&#39;s pressure containment capability. A leak off test (“LOT”), as is known in the art, may be run on the casing shoe CS to determine its integrity. The LOT involves a pressure test of the formation directly below the casing shoe CS to determine a casing shoe fracture pressure. The LOT is generally conducted when drilling resumes after an intermediate casing string has been set. The LOT provides the maximum pressure that may be safely applied and is typically used to design the mud program or choke pressures for well control purposes. Although there may be more than one casing shoe in the well, the most likely candidate to be the weakest link relative to the integrity of all the other casing shoes in the casing program will typically be the casing shoe CS that is immediately above the open borehole BH being drilled. A formation integrity test (“FIT”), as is also known in the art, may be run on the formation. The fracture gradient for the formation may be calculated from the FIT results. Surface equipment that may limit the amount of pressure that may be applied with the DTTL method include the RCD, the choke manifold, the mud-gas separator, the flare stack flow rate, and the mud pumps. The casing itself may also be the weakest component. Some of the other candidates for the limiting component include the standpipe assembly, non-return valves (NRVs), and ballooning. It is also contemplated that engineering calculations and/or actual experience on similar wells and/or offset well data from, for example, development wells could be used to determine the “limit” when designing the DTTL method fluid program. With the DTTL method, hydraulic flow modeling may be used to determine surface back pressures to be used, and to aid in designing the fluids program and the casing seat depths. Hydraulic flow modeling may also determine if the drilling rig&#39;s existing mud-gas separator has the appropriate capacity. 
     The “ballooning”, discussed above, is a phenomenon which occurs within the uncased hole as a direct result of pressures in the wellbore that cause an increase in the volume of fluids within, but do not fracture the wellbore to cause mud loss. Most geologically young sediments are somewhat elastic (e.g., not hard rock). Companion to ballooning is “breathing”. Both contribute to wellbore instability by massaging the walls of the wellbore. Breathing raises questions for a driller when making jointed pipe connections; mud pumps are off, but the rig&#39;s mud pits continue to show flow from the wellbore. Specifically, the driller questions whether the well is taking a kick of formation fluids requiring mud weight to be added . . . or whether the well is giving back some of the volumes of fluid that expanded the wellbore with the last stand of pipe drilled (by Circulating Annulus Friction Pressure (AFP) being added to the hydrostatic weight of the mud). The FIT can detect ballooning as well as establish an estimate of the fracture pressure, similar to testing the “yield point” vs. “break point” of metals and “elongation” vs. “tensile strength” of an elastomeric. Whether real or perceived, ballooning may also be seen as the “limit” to the DTTL method when determining the mud to drill with and casing shoe depths. 
     Using the DTTL method, the wellbore WB may be drilled at a fluid pressure slightly lower than the weakest component. Less complex wells may not require hydraulic flow modeling, the LOT, or the FIT, if there is confidence that the wellbore WB may be drilled by just tooling up at the surface to deal with the uncertainties of the formation pressures. This may apply to the drilling of reservoirs that are progressively more depleted. It is also contemplated that the DTTL method may use a prior art RCD for certain low pressure formations rather than the pressure sharing RCD systems shown in  FIGS. 7 to 17B . However, if an available RCD is used, it may be the weakest component, particularly if a factor of safety is applied. The Minerals Management Service (MMS) requires a 200% safety factor for offshore wells. In effect, this requires that the RCD be used at half its published pressure rating. One of the objectives of the high pressure rated RCD is to eliminate the RCD as the weakest component of the DTTL method. 
     Complimentary technologies that may be used with the DTTL method include downhole deployment valves, equivalent circulation density (ECD) reduction tools, continuous flow subs and continuous circulating systems, surface mud logging, micro-flux control, dynamic density control, dual gradient MPD, and gasified liquids. Surface mud logging allows for cuttings analysis for determining, among other things, rock strength and wellbore stability with lag time. Micro-flux control may allow early kick detection, real time wellbore pressure profile, and automated choke controls. As discussed above, Secure Drilling International, LP provides a micro-flux control system. Dynamic density control adds geomechanics capabilities to the real time analysis and prediction of stresses on the rock being drilled. Dynamic density control may be useful in determining the optimum DTTL method drilling fluid weight and casing set points in some complex wells. Gasified fluids may be used to keep the EMW of the drilling fluid low enough to avoid rupturing a casing seat, or exceeding the predetermined pressure of fracture gradient or FIT. 
     Turning to  FIG. 3 , the advantages of the DTTL method are shown for a particular geologic formation. The formation pore pressure and fracture gradient are shown for an onshore geologic prospect. The prospect has a shifting drilling window, which is the area between the fracture gradient and the pore pressure. If the total EMW is less than the pore pressure, the well will flow. If the total EMW is greater than the fracture gradient, then there may be an underground blowout and loss of circulation. The formation has kick-loss hazard zones around 1300 meters (4265 feet) and 1700 meters (5577 feet) in the reservoir. These kick-loss hazards may manifest themselves as differential sticking, loss circulation, influx, twist-offs, well control issues, and non-productive time. With conventional drilling methods, including the CBHP MPD method, concerns with kick-loss hazards often cause casing program designers to specify fail safe casing string programs. 
     The left side of the chart of  FIG. 3  shows a comparison of exemplary drilling fluids programs for the CBHP MPD method and the DTTL method. The Equivalent Mud Weight (“EMW”) for the drilling fluid used with the CBHP MPD method is shown with a dashed line from the surface until a depth of about 2000 meters (6561 feet). Typically, the EMW is a measure of the pressure applied to the formation by the circulating drilling fluid at a depth. When referring to the CBHP and DTTL methods, the fluid systems are referred to as an equivalent from the conventional hydrostatic mud weight. The EMW for the drilling fluid is about 9 ppg for the CBHP MPD method. Hydrostatic mud weight is sometimes expressed in ppg. Dynamic or circulating mud weight (EMW) is expressed in ppge, where the “e” is for “equivalent.” The EMW for the drilling fluid used with the DTTL method is shown with a solid line from the surface until a depth around 2000 meters (6561 feet). The EMW for the drilling fluid of the DTTL method is slightly less than 7 ppg. With the CBHP MPD method, the EMW of the drilling fluid is kept substantially constant to about 1900 meters (6233 feet), and within the drilling window except around 1700 meters (5577 feet), where it exceeds the fracture gradient. As shown in  FIG. 3 , with the DTTL method, the EMW of the drilling fluid may be a lower value than that for the drilling fluid with the CBHP MPD method for this prospect. It is contemplated that that the EMW of the drilling fluid may be two or three ppg less for the DTTL method, although other amounts are also contemplated. 
     In the DTTL method some amount of surface back pressure may be held whether or not the drilling fluid is circulating. Also, in the DTTL method, whatever the degree of static or dynamic underbalance of the EMW of the drilling fluid relative to the pore pressure, there will be an equivalent amount of surface back pressure applied to keep the total EMW in the drilling window above the pore pressure and below the fracture gradient. The objective is not to maintain a constant EMW, as CBHP MPD, but to keep it within the drilling window. The static and dynamic pressure imparted by the drilling fluid will usually become progressively less than the formation pore pressure as the depth increases, such as shown in  FIG. 3 , from the surface to a depth of about 1200 meters (3937 feet). Therefore, a progressively higher surface back pressure may be required as the drill bit travels deeper. In  FIG. 3 , the drilling fluid weight for the DTTL method is lower than the pore pressure in many depth locations, so that surface back pressure is needed whether circulating or not to keep the well from flowing (i.e. prevent influx). The amount of surface back pressure required is directly related to the hydrostatic or circulating amount of underbalance of the drilling fluid in the open hole. Because there may be a gross underbalance of the drilling fluid in the borehole at any particular time, the pressure containment capability of the RCD becomes paramount. The back pressure may be maintained with a back pressure control or choke system, such as proposed in U.S. Pat. Nos. 4,355,784; 7,044,237; 7,278,496; and 7,367,411; and Pub. No. US 2008/0041149. A hydraulically operated choke valve sold by M-I Swaco of Houston, Tex. under the name SUPER AUTOCHOKE may be used along with any known regulator or choke valve. The choke valve and system may have a dedicated hydraulic pump and manifold system. A positive displacement mud pump may be used for circulating drilling fluids. It is contemplated that there may be a system of choke valves, choke manifold, flow meter, and hydraulic power unit to actuate the choke valves, as well as sensors and an intelligent control unit. It is contemplated that the system may be capable of measuring return flow using a flow meter installed in line with the choke valves, and to detect either a fluid gain or fluid loss very early, allowing gain/loss volumes to be minimized. 
     It is contemplated that the DTTL method may use drill string non-return valves. Non-return or check valves are designed to prevent fluid from returning up the drill string. It is also contemplated that the DTTL method may use downhole deployment valves to control pressure in the wellbore, including when the drill string is tripped out of the wellbore. Downhole deployment valves are proposed in U.S. Pat. Nos. 6,209,663; 6,732,804; 7,086,481; 7,178,600; 7,204,315; 7,219,729; 7,255,173; 7,350,590; 7,413,018; 7,451,809; 7,475,732; and Pub. Nos. US 2008/0060846 and 2008/0245531; which are all hereby incorporated by reference for all purposes in their entirety and are assigned to the assignee of the present application. For the drilling fluid traveling down the wellbore, it may be pressurized in a system of the positive displacement mud pump, standpipe hose, the drill string, and the drill string non-return valves. For the drilling fluid returning up the annulus, it may be pressurized in a system of the casing shoe, casing and surface equipment, the RCD system, such as shown in  FIGS. 7 to 17B , and the dedicated choke manifold. The DTTL method may also be used for running tubulars without rotating, including, but not limited to, drill string, drill pipe, casing, and coiled tubing, into and out of the hole. 
     While rock mechanics, rheological and chemical compatibility issues with the formation to be drilled are factors to be considered, the DTTL method allows for lighter, more hydrostatically underbalanced, more readily available, and less expensive drilling fluids to be used. The DTTL method simplifies the drilling process by reducing non-productive time (NPT) dealing with drilling windows. Also, the lighter drilling fluid allows for faster and less resistive rotation of the drill string. Circulating Annular Friction Pressure (AFP) increases in a proportion to the weight and viscosity of the drilling fluid. It is important to recognize that AFP is a significant limiting factor to conventional drilling and the objective of CBHP is to counter its effect on the wellbore pressure profile by the application of surface back pressure when not circulating. The DTTL method&#39;s use of much lighter drilling fluids result in a significant reduction in pressures imparted by the circulation rate of the drilling fluid and offers the option to circulate at much higher rates with no ill effects. The DTTL method&#39;s drilling fluid offers another distinct advantage in that lighter fluids are less prone for its viscosity to increase during periods of idleness. This “jelling” manifests itself as a spike in the EMW upon restarting the rig&#39;s mud pumps to regain circulation. As such pressure fluctuations are detrimental to precise management of the uncased hole pressure environment, the DTTL method significantly minimizes the impact of jelling. However, one must be mindful that some formations require a minimum mud weight to aid in supporting the walls of the uncased hole, formations such as unconsolidated sand, rubble zones, and some grossly depleted formations. Given these considerations, the criteria for selection of the drilling fluids may be focused upon (1) the ability to clean the hole (cuttings carrying ability), (2) a light enough weight to avoid loss circulation, and (3) a heavy enough weight so that the back pressure required to prevent an influx from the formation will not exceed the limits of the weakest component of the well construction program. In designing the fluids program for the DTTL method, the formation pore pressure is not used, with the objective being to avoid exceeding the “weakest link” of the fracture gradient, the casing shoe integrity, or the integrity of any other component of the closed pressurized circulating fluid system&#39;s pressure containment capability. A LOT, offset well information or rock mechanics calculations should provide the maximum allowable pressure for the casing shoe. In land drilling programs, the casing shoe fracture pressure will most often not be the “weakest link” of the pressure containment system. However, the casing shoe pressure integrity may be less than the formation fracture pressure when drilling offshore, such as in geologically young particulate sediments, through salt domes, whose yielding characteristics challenge the ability to obtain an acceptable casing and casing shoe cement job. 
     The right side of the chart in  FIG. 3  shows a comparison of casing programs for the conventional and CBHP MPD methods to the DTTL method. Like the drilling fluids program, the casing program using the DTTL method for this geologic formation is simplified in comparison with the prior art casing programs. Simplification of the casing program with the DTTL method is a direct result of two distinguishing characteristics: 1.) a lighter mud imparting less depth vs. pressure gradient upon the wellbore, enabling deeper open holes than conventional or CBHP to be drilled before the fracture pressure is approached requiring a casing shoe set point as best shown in  FIG. 4A , and 2.) to maintain the EMW further away from the formation fracture gradient. For example, the DTTL method allows for a 24 inch wellhead, as compared with a more expensive 30 inch wellhead required by the conventional and CBHP MPD methods. The DTTL method also allows the total depth objective to be obtained with a larger and longer open hole than is possible with the prior art methods. In the example of  FIG. 3 , the DTTL method allows for a 10 inch diameter production liner (gravel pack-type completion or open hole) as compared with a 7 inch production liner for the conventional method or a 4½ inch production liner for the CBHP MPD method. The 10 inch production liner in the DTTL method advantageously extends completely through the reservoir, unlike the prior art methods. As a result, the DTTL method only requires three casing/liner size changes, compared with five changes with the CBHP MPD method and seven changes with the conventional method. Both the conventional and CBHP MPD methods require a dedicated casing set point around 1700 meters (5577 feet) for the kick hazard, but the DTTL method does not. In summary, the DTTL method allows use of smaller diameter wellhead and casing initially and a larger diameter liner to total depth (TD) with fewer tubular changes and with less expensive, more readily available lighter fluids. The contemplated maximum surface back pressure on the DTTL method would be 975 psi (circulating); 1030 psi (during connection) and 2713 psi (shut in). The LOT on the 13⅜″ casing shoe must be less than 4140 psi. 
     Turning to  FIG. 4 , the advantages of the DTTL method are shown in a different geologic formation with objectives of lightest mud, highest rate of penetration (ROP), slimmest casing program, deepest open hole below 9⅝″ casing for maximum access to reservoir. The formation pore pressure and fracture gradient are shown for an offshore geologic prospect for a jack-up rig having a mud line at 400 feet (122 meters). The prospect has a shifting drilling window. The shallow gas hazard is mitigated because the DTTL method teaches the application of surface backpressure whether circulating or not, and encountering a shallow gas hazard simply implies additional surface backpressure. There are kick-loss hazard zones around 9000 feet (2743 meters) and 14,000 feet (4267 meters). The left side of the chart shows a comparison of exemplary drilling fluids programs for the conventional method to the DTTL method. Note that the pressure-containing integrity of the 13⅝″ casing shoe at 9,500′ has a LOT value less than the fracture pressure. Therefore, this casing shoe is considered the limiting component relative to DTTL fluids selection and determines the maximum amount of surface backpressure that may be applied without risk of fracturing the casing shoe. The EMW for the drilling fluid used with the conventional method is shown with a series of dashed lines starting at about 9 ppg at the surface and making several changes until ending at about 17 ppg at a depth of about 16,000 feet (4877 meters). The conventional method is complicated by the need for eight drilling fluid density changes to navigate through the drilling window. The EMW for the drilling fluid of the DTTL method is shown with a solid line at about 6.7 ppg starting at the surface. The kick-loss hazards present challenges for the conventional method, and require rapid mud weight changes to navigate. In the DTTL method, the kick-loss hazards become a moot point, unlike in the conventional method, which must rely on mud weight changes. With CBHP, placing a casing shoe above the kick-loss hazard zones is a prudent and common practice, typically because of uncertainty of the accuracy of the estimated drilling window in the kick-loss hazard zone, and one should keep the option open to deviate from the pre-planned CBHP mud weight. With the DTTL method, the EMW of the drilling fluid is kept substantially constant to about 16,000 feet (4877 meters). Unlike the conventional method, in the DTTL method some amount of surface back pressure may be held on the drilling fluid. In the DTTL method surface back pressure is provided to keep the total EMW above pore pressure but below the fracture gradient. As should now be understood, the DTTL method simplifies the drilling process as it allows for less changes in the drilling fluid as compared with the conventional method. Again, the DTTL method allows for lighter, more hydrostatically underbalanced, more readily available, and less expensive drilling fluids to be used. In designing the fluids program with the DTTL method, the formation pore pressure is not used, with the objective being to avoid exceeding the fracture gradient, the casing shoe integrity, or the integrity of any other component of the closed pressurized circulating fluid system&#39;s pressure containment capability. 
     The right side of the chart in  FIG. 4  shows a comparison of casing programs for the conventional and CBHP MPD methods to the DTTL method. Like the drilling fluids program, the casing program of the DTTL method for this geologic formation is simplified in comparison with the prior art casing programs. For example, the DTTL method allows for a 24 inch wellhead, as compared with a more expensive 30 inch wellhead required by the conventional and CBHP MPD methods. The DTTL method also allows the total depth objective to be obtained with a larger and longer open hole than is possible with the prior art methods. The 9⅝″ casing and 7 inch production liner in the DTTL method extends completely through the Reservoir, unlike the prior art methods. In the example of  FIG. 4 , the DTTL method has three casing/liner size changes, compared with five changes with the CBHP MPD method. The conventional, CBHP MPD and DTTL methods require a dedicated casing set point around 14,000 feet (4267 meters). The casing shoe is set at 14,000 feet (4267 meters) for the kick-loss hazard and for enabling drilling fluid density adjustments below that point required to handle the new drilling window. This DTTL method illustrates a case study where a cemented casing shoe is the limit, as determined by a LOT, calculations or offset well data. In this case study, the DTTL method 13⅝″ casing shoe was determined to have a limit of 13.6 ppg equivalent mud weight at the beginning of the Reservoir. As best shown in  FIG. 4 , a 6.7 ppg oil-based mud is used below the 13⅜″ casing (LOT, calculations or offset well data of 13.6 ppge limit) in the DTTL method and supplied through a 5 inch drill string DS at 500 gallons per minute. At 13,500 feet the pore pressure is 12.5 ppge. With a surface back pressure is 4,800 psi (circulating) and 5,015 psi (static), a high pressure RCD, as discussed below in detail, will be required. 
     As is known in the art, the calculated formation pore pressure and fracture gradient are usually not exact, and margins of error must be considered in selecting casing set points. This uncertainty may prompt additional casing set points in the conventional and CBHP MPD methods that are avoided in the DTTL method. Additional casing set points create added expense and casing shoe issues. The DTTL method uses required amounts of surface back pressure to guard against these uncertainties in the formation. There is a reasonable probability that the conventional and CBHP MPD methods as applied to the formation shown in  FIG. 4  would result in a drilling program that ultimately exceeds budget (known in the art as authorization for expenditure “AFE”) due to extra casing sizes, extra casing strings, and non-productive time dealing with the loss portion of the kick-loss hazards, such as differential sticking of the drill string with potential twisting and severing of the string, loss of circulation with attendant drilling fluid cost, and well control issues. A kick in the kick-loss hazard zone results in having to shut in and circulate out the kick, including waiting to increase the weight of the drilling fluid. The DTTL method advantageously allows the operation to avoid many kick-loss hazards. The DTTL method allows for drilling with a lighter drilling fluid and staying further away from the loss portion of the kick-loss hazard zone. Since there is constant surface back pressure even when there is no circulation, the kick portion may be more easily compensated for and controlled using the DTTL method. 
     For the geologic formation depicted in  FIGS. 3 and 4 , the DTTL method achieves its objectives of using the lightest and less expensive drilling fluid, the highest rate of penetration (ROP), the slimmest casing program, and a deeper open hole for more access to the reservoir than either conventional or CBHP. The DTTL method allows for the formation fracture gradient to be focused on instead of the formation pore pressure. The drilling fluid may be selected as described above. When the EMW of the drilling fluid is less than the formation pore pressure, surface pressure is applied to prevent or limit influx into the wellbore when the mud pumps are on and drilling is occurring. When the mud pumps are off, an additional amount of surface back pressure is applied to offset the loss of Circulating Annular Friction Pressure (AFP). The DTTL method effectively broadens the drilling window by not using the formation pore pressure. The DTTL method is particularly helpful where the formation pore pressure is relatively unknown, such as in exploratory wells and sub-salt reservoirs, as are common in the Gulf of Mexico. 
       FIG. 5A  is a chart of depth in feet versus pressure equivalent in ppg for an exemplary prior art Gulf of Mexico deep water geologic prospect with a salt layer. A floating drilling rig may be used to drill the well. The drilling fluid weight for conventional drilling techniques in the salt layer is shown as greater than the salt overburden gradient and less than the salt fracture gradient. The prior art drilling fluid program is complicated by the need to continuously monitor and change the weight of the drilling fluid to stay within the drilling window. The left side of the chart shows the casing design for prior art conventional drilling techniques. The right side of the chart shows the casing design for prior art Drilling with Casing (“DwC”). DwC is an enabling technology that can be a mitigant for managing shallow hazards. An objective of the technology is to set the first and possibly the second casing strings significantly deeper than with conventional drilling techniques. DwC addresses shallow geologic hazards, wellbore instability, and other issues that would otherwise require additional casing string sizes, ultimately limiting open hole size at total depth (“TD”). 
       FIG. 5B  shows the same geologic prospect as in  FIG. 5A . The pressure equivalent of the drilling fluid is shown as substantially constant at 14 ppg from a depth of around 6,900 feet (2103 meters) to about 13,000 feet (3962 meters) while DwC. The DTTL method is used beginning with 13,000 feet (3962 meters). The pressure equivalent of the drilling fluid of the DTTL method is shown as substantially constant from a depth of about 13,000 feet (3962 meters) to about 30,000 feet (9144 meters). The DTTL method simplifies the drilling fluids program by using a lighter weight drilling fluid than the conventional technique, and by requiring only one change of fluid weight after a depth of 30,000 feet (9144 meters), in comparison with continuous changes required by conventional techniques. The left side of the chart again shows the casing design for conventional drilling techniques. The right side of the chart shows the casing design for the DTTL method. Using the DTTL method, a 13⅝ inch casing shoe may be used at total depth of 31,000 feet (9449 meters), compared with a 9⅜ inch casing shoe at TD of 28,000 feet (8534 meters) for the conventional drilling method. The DTTL method provides for a larger hole and deeper total depth (TD). There are also two contingency casing strings available with the DTTL method. It is contemplated that the DTTL method could be used with DwC having a 13⅝″ casing. 
       FIG. 5C  is the same as  FIG. 5B , except that in the DTTL method one of the contingency casing strings has been removed, resulting in a 11⅞ inch casing shoe at TD of 31,000 feet (9449 meters). As can now be understood, sub-salt, the DTTL method advantageously achieves the largest and deepest open hole at total depth (TD) for production liners and expandable sand screens (ESS). The DTTL method is particularly beneficial beneath the transition zone in the reservoir. In conventional drilling, drilling fluid weight is typically increased to be safe in light of the margin of error in predicting the pore pressure. The prediction of sub-salt formation pore pressures and formation fracture pressures has been shown on a number of deepwater wells to be in a range of error of as much as 2 to 3 ppge. This much error in predicting the actual drilling window plays a continuous role in the design of a conventional casing and fluids program. The worst case scenario must always be planned for long in advance to obtain a permit to drill from the MMS, in procurement decisions, in logistics of delivery considerations, in requirements for deck space for various casing sizes, and for other contingencies. This has an adverse affect on the cost of the well. If the well is sub salt, then seismographic imaging may be blurred by the plastic nature of the salt dome. Accurate prediction of the drilling window may be difficult. This may result in estimating on the high side when designing the fluids program, which may explain why loss circulation and the resulting well control issues often arise in many drilling programs when the bit penetrates through the base of salt in the Gulf of Mexico. The MMS requires EMW to be at least 0.5 ppge above formation pore pressure, which is a relative unknown. Sub salt prospects in the Gulf of Mexico include Atwater Valley, Alaminos Canyon, Garden Banks, Keathley Canyon, Mississippi Banks, and Walker Ridge. 
     There are other uncertainties in the open hole below the last casing seat that complicate conventional and CBHP MPD casing and fluids programs. These include compressibilities, solubilities, mechanical, thermal, and fluid transport characteristics of each formation, natural and/or operationally induced wellbore communicating fracture systems, undisturbed states prior to drilling sand, and time-dependent behaviors after being penetrated by the wellbore. With the DTTL method, surface equipment pressure rating may be advantageously used to compensate for the relative unknown, such as the range of error. With the DTTL method, the driller may tool up at the surface to deal with downhole uncertainties, rather than complicating the downhole casing and fluids programs to handle the worst case scenario of each. As discussed above, the DTTL method also advantageously increases the contingency for additional casing sizes, if needed. Failed drilling programs sometimes occur because the conventional casing program has no margin for contingency if the geo-physics or rock mechanics (i.e. wellbore instability) are different than planned. As can now be understood, the DTTL method achieves a simplified and lower cost well construction casing program. The DTTL method is applicable for land, shallow water, and deep water prospects. The DTTL method allows for a higher safety factor than prior art conventional methods. The MMS requires at least a 200% safety factor on pressure ratings of all surface equipment. The DTTL method gets to TD with the deepest and largest open-hole possible for reservoir access. Simply stated, the DTTL method is faster, cheaper and better than the conventional or CBHP MPD methods. 
     High Pressure Rotating Control Device 
       FIG. 6  is a prior art pressure rating graph for the prior art Weatherford Model 7800 RCD that shows wellbore pressure in pounds per square inch (psi) on the vertical axis, and RCD rotational speed in revolutions per minute (rpm) on the horizontal axis. The maximum allowable wellbore pressure without exceeding operational limits for the prior art RCD is 2500 psi for rotational speeds of 100 rpm or less. The maximum allowable pressure decreases for higher rotational speeds. Weatherford also manufactures an active seal RCD, RBOP 5K RCD with 7 inch ID, which has a maximum allowable stripping pressure of 2500 psi, maximum rotating pressure of 3500 psi, and maximum static pressure of 5000 psi. The pressure sharing RCDs shown in  FIGS. 7 to 17B  allow for a much higher pressure rating both in the static and dynamic conditions than the prior art RCDs. These pressure sharing RCDs will allow a large number of tool joints to be stripped out under high pressure conditions with greater sealing element performance capabilities. 
     While pressure sharing RCD systems are shown in  FIGS. 7 to 17B , embodiments other than those shown are also contemplated. Turning to  FIG. 7 , RCD, generally indicated at  100 , has an inner member  102  rotatable relative to an outer member  104  about bearing assembly  106 . A first sealing element  110  and a second sealing element  120  are attached so as to rotate with inner member  102 . Sealing elements ( 110 ,  120 ) are passive stripper rubber seals. First cavity  132  is defined by inner member  102 , drill string DS, first sealing element  110 , and second sealing element  120 . A first sensor  130  is positioned in first cavity  132 . A second sensor  140  is positioned in housing  122  and a third sensor  141  is positioned in diverter housing  123 . Sensors ( 130 ,  140 ,  141 ), like all other sensors in all embodiments shown in  FIGS. 7 to 17B , may at least measure temperature and/or pressure. Additional sensors and different measured values, such as rotation speed RPM, are also contemplated for all embodiments shown in  FIGS. 7 to 17B . It is contemplated that sensors fabricated to tolerate for high pressure/high temperature geothermal drilling, with methane hydrates may be used in the cavities. Sensors ( 130 ,  140 ,  141 ), like all other sensors in all embodiments shown in  FIGS. 7 to 17B , may be hard wired for electrical connection with a programmable logic controller (“PLC”), such as PLC  154  in  FIG. 7 . It is also contemplated that the connection for all sensors and all PLCs shown in all embodiments in  FIGS. 7 to 17B  may be wireless or a combination of wired and wireless. Sensors may be embedded within the walls of components and fitted to facilitate easy removal and replacement. 
     PLC  154  is in electrical connection with a positive displacement pump  152 . It is also contemplated that the connection for all pumps and all PLCs shown in all embodiments in  FIGS. 7 to 17B  may be wired, wireless or a combination of wired and wireless and the pumps could be positive displacement pumps. Pump  152  is in fluid communication with fluid source  150 . The fluid source  150  could include fluid from take off lines TO, as shown in  FIGS. 1 and 2 . Pump  152  is in fluid communication with first cavity  132  through influent line  134  and a sized influent port  135  in inner member  102 . Optional effluent line  136  is in fluid communication with first cavity  132  through a sized effluent port  137  in inner member  102 . If desired, line  136 , or any other line discussed herein, could include a sized orifice or a valve to control flow. Based upon information received from sensors ( 130 ,  140 ,  141 ), PLC  154  may signal pump  152  to communicate a change in the pressurized fluid to first cavity  132  to provide a predetermined fluid pressure P 2  to first cavity  132  to change the differential pressure between the fluid pressure P 1  in the housing  122  and the predetermined fluid pressure P 2  in first cavity  132  on first sealing element  110 . It is contemplated that the predetermined fluid pressure P 2  may be changed to be greater than, less than, or equal to P 1 . It is contemplated that the cavity  132  could hold pressure P 2  that is in the range of 60-80% of the pressure P 1  below element  110 . However, any reduction of differential pressure will be beneficial and an improvement. The predetermined fluid pressure P 2  may be calculated by PLC  154  using a number of variables, such as pressure and temperature readings from sensors  140 ,  141 . These variables could be weighted, based on location of the sensor. As is now understood fluid may be circulated in, into and out of first cavity  132  or bullheaded. Likewise, fluid may be circulated, into and out of in all cavities of all embodiments shown in  FIGS. 7 to 17B  or bullheaded. 
     For all embodiments of the invention, the PLC, like PLC  154  in  FIG. 7 , may allow adjustable calculations of differential pressure sharing and supplying RCD cavity fluid. As will be discussed in detail below, a choke valve may receive from the PLC set points and the ratio of the shared pressure determined by the wellbore pressure in keeping with the pressure rating of the RCD. During operations, the commands of the PLC to the pressure sharing choke valve may be variable, such as to change the ratio of sharing to compensate for a sealing element that may have failed. The PLC may send hydraulic pressure to adjust the choke valve. The PLC may also signal the choke valve electrically. It is contemplated that there may be a dedicated hydraulic pump and manifold system to control the choke valve. It is further contemplated that a proportional relief valve may be used, and may be controllable with the PLC. 
     As can now be understood, RCD  100  and the pressure sharing RCD system of  FIG. 7  allow for pressure sharing to reduce the differentiated pressure applied to the first sealing element  110  exposed directly to the wellbore pressure in the housing  122 . The pressure differential across first sealing element  110 , which for a prior art RCD would be substantially the wellbore pressure in the housing  122 , may be reduced so that some of the pressure is shared with second sealing element  120 . In a similar manner, all embodiments in  FIGS. 8 to 17B  provide for pressure sharing to reduce the pressure differential across the first sealing element that is exposed directly to the wellbore pressure. Other sealing elements may be used to further “share” some of the pressure with the first sealing element. This is accomplished by pressurizing the additional cavities in those embodiments. When the cavity pressure is different than the pressure across the sealing element immediately below, then there will be pressure sharing with that sealing element. When the cavity pressure is greater than the pressure that the sealing element immediately below is subjected to, there may be flushing or “burping” through the sealing element via counteracting the sealing element&#39;s stretch-tightness and the cavity pressure below the sealing element. 
     Returning to  FIG. 7 , an optional first upper conduit  142  and second lower conduit  146  allow for pressurized flow of fluids, shown with arrows ( 144 ,  145 ,  148 ) to cool first sealing element  110 . The pressurized flow of fluids ( 144 ,  145 ,  148 ) may also shield first sealing element  110  from cuttings in the drilling fluid and hot returns from the wellbore in housing  122 . It is contemplated that RCD  100 , as well as all other RCD embodiments shown in  FIGS. 8 to 17B , may have a pressure rating substantially equal to a BOP stack pressure rating. 
     It is contemplated for all embodiments that the fluid to a cavity may be a liquid or a gas, including, but not limited to, water, steam, inert gas, drilling fluid without cuttings, and nitrogen. A cooling fluid, such as a refrigerated coolant or propylene glycol, may reduce the high temperature to which a sealing element may be subjected. It may lubricate the throat and the nose of the passive sealing element, and flush and clean the sealing surfaces of any scaling element that would otherwise be in contact with the tubular, such as a drill string. It may also cool the RCD inner member, such as inner member  102  in  FIG. 7 , and assist in removing some frictional heat. A nitrogen pad in a cavity that can be “burped” into the below wellbore may be beneficial when drilling in sour formations. It is contemplated for all embodiments that a gas may be injected into a cavity through a gas expansion nozzle or a refrigerant orifice. 
     It is also contemplated that a single pass of a gas may be made into a cavity at a pressure that is greater, such as by 200 psi, than the pressure below the lower sealing element of the cavity. Alternatively, a single pass of chilled liquid or cuttings free drilling fluid may be made into a cavity at a greater pressure than the pressure below the lower sealing element of the cavity. Single-pass fluids that “burp” downward through the lower sealing element of the cavity may be deposited into the annulus returns via the lowest sealing element. A single-pass fluid, such as cuttings free drilling fluid, that burps downward may provide lubrication and/or cooling between the annular sealing element and drill string, as well as off-setting some of the pressure below. This may increase sealing element life. 
     It is contemplated that first sealing element  110 , as well as all sealing elements in all other embodiments shown in  FIGS. 7 to 17B , may be allowed to pass a cavity fluid, including, but not limited to, nitrogen. Returning to  FIG. 7 , second sealing element  120  may be removed and/or replaced from above while leaving first sealing element  110  in position in the housing  122 . Removal of either sealing element may be necessary for inspection, repair, or replacement. Alternatively, RCD  100  may be removed using latch  139  of single latching mechanism  141 , and sealing elements ( 110 ,  120 ) thereafter removed. Single and double latching mechanisms for use with RCD docketing stations are proposed in US Pub. Nos. US 2006/0144622A1 US 2008/0210471A1, which are hereby incorporated by reference for all purposes in their entirety and assigned to the assignee of the present application. It is contemplated that all embodiments may use latching mechanisms and a docketing station, such as proposed in the &#39;622 and &#39;471 publications. 
     Sealing Elements 
     As is known, passive sealing elements, such as first sealing element  110  and second sealing element  120 , may each have a mounting ring MR, a throat T, and a nose N. The throat is the transition portion of the stripper rubber between the nose and the metal mounting ring. The nose is where the stripper rubber seals against the tubular, such as a drill string, and stretches to pass an obstruction, such as tool joints. The mounting ring is for attaching the sealing element to the inner member of the RCD, such a inner member  102  in  FIG. 7 . At high differential pressure, the throat, which unlike the nose does not have support of the tubular, may extrude up towards the inside diameter of the mounting ring. This may typically occur when tripping out under high pressure. A portion of the throat inside diameter may be abraded off, usually near the mounting ring, leading to excessive wear of the sealing element. For use with the DTTL method, it is contemplated that the throat profile may be different for each tubular size to minimize extrusion of the throat into the mounting ring, and/or to limit the amount of deformation and fatigue before the tubular backs up the throat. For the DTTL method, it is contemplated that the mounting ring will have an inside diameter most suitable for pressure containment for each size of tubular and the obstruction outside diameter. U.S. Pat. No. 5,901,964 proposes a stripper rubber sealing element having enhanced properties for resistance to wear. 
     It is contemplated that first sealing element  110  and second sealing element  120 , as well as all sealing elements in any other embodiment shown in  FIGS. 8 to 17B , may be made in whole or in part from SULFRON® material, which is available from Teijin Aramid BV of the Netherlands. SULFRON® materials are a modified aramid derived from TWARON® material. SULFRON material limits degradation of rubber properties at high temperatures, and enhances wear resistance with enough lubricity, particularly to the nose, to reduce frictional heat. SULFRON material also is stated to reduce hysteresis, heat build-up and abrasion, while improving flexibility, tear and fatigue properties. It is contemplated that the stripper rubber sealing element may have para aramid fibers and dust. It is contemplated that longer fibers may be used in the throat area of the stripper rubber sealing element to add tensile strength, and that SULFRON material may be used in whole or in part in the nose area of the stripper rubber sealing element to add lubricity. The &#39;964 patent, discussed in the Background of the Invention, proposes a stripper rubber with fibers of TWARON® material of 1 to 3 millimeters in length and about 2% by weight to provide wear enhancement in the nose area. It is contemplated that the stripper rubber may include 5% by weight of TWARON to provide stabilization of elongation, increase tensile strength properties and resist deformation at elevated temperatures. Para amid filaments may be in a pre-form, with orientation in the throat for tensile strength, and orientation in the nose for wear resistance. TWARON and SULFRON are registered trademarks of Teijin Aramid BV of the Netherlands. 
     It is further contemplated that material properties may be selected to enhance the grip of the scaling element. A softer elastomer of increased modulus of elasticity may be used, typically of a lower durometer value. An elastomer with an additive may be used, such as aluminum oxide or pre-vulcanized particulate dispersed in the nose during manufacture. An elastomer with a tackifier additive may be used. This enhanced grip of the sealing element would be beneficial when one of multiple sealing elements is dedicated for rotating with the tubular. 
     It is also contemplated that the sealing elements of all embodiments may be made from an elastomeric material made from polyurethane, HNBR (Nitrile), Butyl, or natural materials. Hydrogenated nitrile butadiene rubber (HNBR) provides physical strength and retention of properties after long-term exposure to heat, oil and chemicals. It is contemplated that polyurethane and HNBR (Nitrile) may preferably be used in oil-based drilling fluid environments 160° F. (71° C.) and 250° F. (121° C.), and Butyl may preferably be used in geothermal environments to 250° F. (121° C.). Natural materials may preferably be used in water-based drilling fluid environments to 225° F. (107° C.). It is contemplated that one of the stripper rubber sealing elements may be designed such that its primary purpose is not for sealability, but for assuring that the inner member of the RCD rotates with the tubular, such as a drill string. This sealing element may have rollers, convexes, or replacement inserts that are highly wear resistant and that press tightly against the tubular, transferring rotational torque to the inner member. It is contemplated that all sealing elements for all embodiments in  FIGS. 7 to 17B  will comply with the API-16RCD specification requirements. Tripping out under high pressure is the most demanding function of annular sealing elements. 
     The sized port  135  to first cavity  132  in RCD  100  in  FIG. 7  may be used for circulating a coolant or lubricant and/or pressurizing the cavity  132  with inert gas and/or pressurizing the cavity  132  with different sources of gas or liquids. Likewise, the access to all of the cavities in all embodiments shown in  FIGS. 8 to 17B  may be used for circulating or flushing with a coolant or lubricant and/or pressurizing the cavity with inert gas and/or pressurizing the cavity with different sources of gas or liquids. The pressure sharing capabilities of the embodiment in  FIG. 7  allow the RCD  100  to have a higher pressure rating than prior art RCDs. The pressure sharing RCD system embodiment shown in  FIG. 7 , as well as the embodiments shown in  FIGS. 8 to 17B , allow for higher pressure ratings and may be used with the DTTL method discussed above. In addition to using the high pressure RCDs in the DTTL method, the RCDs in all embodiments disclosed herein are desirable when a higher factor of safety is desired for the geologic prospect. The RCDs in all embodiments disclosed herein allow for enhanced well control. Some formation pressure environments are relatively unknown, such as sub-salt. High pressure RCDs allow for higher safety for such prospects. “Dry holes” have resulted in the past from not knowing the formation pore pressure, and grossly overweighting the drilling fluid to be safe, thereby masking potentially acceptable pay zones at higher oil and gas market prices. 
     Turning to  FIG. 8 , RCD, generally indicated at  162 , has an inner member  164  rotatable relative to an outer member  168  about bearing assembly  166 . RCD  162  is latchingly attached with latch  171  to housing  173 . A first sealing element  160  and a second sealing element  170  are attached to and rotate with inner member  164 . First sealing element  160  is an active sealing element. As with other active sealing elements proposed herein, the active sealing element  160  is preferably engaged on a drill string DS, as shown on the left side of the vertical break line BL, when drilling, and deflated, as shown at the right side of break line BL, to allow passage of a tool joint of drill string DS when tripping in or out. It is also contemplated that the PLC in all the embodiments could receive a signal from a sensor that a tool joint is passing a sealing element and pressure is then regulated in each cavity to minimize load across all the sealing elements. Second sealing element  170  is a passive stripper rubber sealing element. First cavity  185  is defined by inner member  164 , drill string DS, first sealing element  160 , and second sealing element  170 . A first sensor  172  is positioned in first cavity  185 . A second sensor  174  is positioned in diverter housing  188 . Sensors ( 172 ,  174 ) may measure at least temperature and/or pressure. Sensors ( 172 ,  174 ) are in electrical connection with PLC  176 . PLC  176  is in electrical connection with pump  180 . Pump  180  is in fluid communication with fluid source  182 . Pump  180  is in fluid communication with first cavity  185  through influent line  184  and sized influent port  181  (though shown blocked) in inner member  164 . Effluent line  186  is in fluid communication with first cavity  185  though sized effluent port  183  in inner member  164 . Based upon information received from sensors ( 172 ,  174 ), PLC  176  may signal pump  180  to communicate a pressurized fluid to first cavity  185  to provide a predetermined fluid pressure P 2  to first cavity  185 . The differential pressure change is between the fluid wellbore pressure P 1  in the housing  188  and the predetermined fluid pressure P 2  in first cavity  185  on first sealing element  160 . It is contemplated that P 2  may be greater than, less than, or equal to P 1 . 
     Active sealing element  160  can be in fluid communication with a pump (not shown) in electrical connection with PLC  176 . The activation of fluid communication between all active sealing elements ( 160 ,  190 ,  461 ,  466 ,  540 ,  654 ,  720 ) by all PLCs in all embodiments in  FIGS. 8, 9, 13A, 13C, 14B, 16A, and 17B  may be hard wired, wireless or a combination of wired and wireless. Fluid can be supplied or evacuated through port  185  to activate/deflate sealing element  160 . 
     A hydraulic power unit (HPU), comprising an electrically driven variable displacement hydraulic pump, can be used to energize the sealing element. The pump can be controlled via an integrated computer controller within the unit. The computer monitors the input from the control panel and drives the pump system and hydraulic circuits to control the RCD. The HPU requires an external 460 volt power supply. This is the only power supply required for the system. The HPU has been designed for operation in Class 1, Division 1 hazardous situation. 
     The control system has been designed to allow operation in an automated manner. Once the job conditions have been set on the control panel, the hydraulic power unit will automatically control the RCD to meet changes in well conditions as they happen. This reduces the number of personnel required on the drill floor during the operation and provides greater safety. 
     In  FIG. 8 , the means for accessing the first cavity  185  allows for pressure sharing and/or circulating coolant or inert gas. Second sealing element  170  may be removed and/or replaced from the above while leaving first sealing element  160  in position in the housing  173 . Alternatively, RCD  162  may be removed from housing  173  using latch  171  to obtain access to the sealing elements ( 160 ,  170 ). For the embodiment shown in  FIG. 8 , as well as all other embodiments of the invention, a data information gathering system, such as DIGS, available from Weatherford may be used with the PLC to monitor and reduce relative slippage of the sealing elements with the tubular, such as drill string DS. It is contemplated that real time revolutions per minute (RPM) of the sealing elements may be measured. If one of the sealing elements is on an independent inner member and is turning at a different rate than another sealing element, then it may indicate slippage of one of the sealing elements with tubular. Also, the rotation rate of the sealing elements can be compared to the drill string DS measured at the top drive (not shown) or at the rotary table in the drilling floor F. 
     For all embodiments in  FIGS. 7 to 17B , it is contemplated that passive sealing elements and active sealing elements may be used interchangeably. The selection of the RCD system and the number and type of sealing elements may be determined in part from the maximum expected wellbore pressure. It is contemplated that passive sealing elements may be designed for maximum lubricity in the sealing portion. Less frictional heat may result in longer seal life, but at the expense of tubular rotational slippage due to the torque required to rotate the inner member of the RCD. It is contemplated that active sealing elements may be designed with friction enhancing additives for rotational torque transfer, perhaps only being energized if rotational slippage is detected. It is contemplated that one of the annular sealing elements, active or passive, may be dedicated to a primary function of transferring rotational torque to the inner member of the RCD. If the grip of the active sealing elements are enhanced, they may be energized whenever slippage is noticed, with enough closing pressure to assure rotation. The active sealing elements may have modest closing pressure to conserve their life, and have minimal differential pressure across the seal. For all embodiments, it is contemplated that the active sealing elements may allow tripping out under pressure by, among other things, deflating the active sealing element. 
     Turning to  FIG. 9 , RCD, generally indicated at  191 , has an inner member  192  rotatable relative to an outer member  196  about bearing assembly  194 . A first sealing element  190 , a second sealing element  200 , and a third sealing element  210  are attached to and rotate with inner member  192 . First sealing element  190  is an active sealing element shown engaged on a drill string DS. Second sealing element  200  and third sealing element  210  are passive stripper rubber sealing elements. First cavity  198  is defined by inner member  192 , drill string DS, first sealing element  190 , and second sealing element  200 . Second cavity  202  is defined by inner member  192 , drill string DS, second sealing element  200 , and third sealing element  210 . 
     A first sensor  208  is positioned in first cavity  198 . A second sensor  204  is positioned in first conduit  205 , which is in fluid communication with diverter housing  206 . PLC  222  is in electrical connection with first pump  220 . First pump  220  is in fluid communication with fluid source  234 . First pump  220  is in fluid communication with first cavity  198  through first influent line  224  and sized first influent port  225  in inner member  192 . First effluent line  226  is in fluid communication with first cavity  198  through sized first effluent port  227  in inner member  192 . A third sensor  218  is positioned in first influent line  224 . A fourth sensor  212  is positioned in first effluent line  226 . A fifth sensor  238  is positioned in second cavity  202 . PLC  222  is in electrical connection with second pump  228 . Second pump  228  is also in fluid communication with fluid source  234 . Second pump  228  is in fluid communication with second cavity  202  through second influent line  230  and sized second influent port  217  in inner member  192 . Second effluent line  232  is in fluid communication with second cavity  202  through sized second effluent port  219  in inner member  192 . A sixth sensor  216  is positioned in second influent line  230 . A seventh sensor  214  is positioned in second effluent line  232 . Active sealing element  190  pump (not shown) can be in electrical connection with PLC  222 . Fluid can be supplied or evacuated to active sealing elements chamber  190 A to activate/deflate sealing element  190 . Sensors ( 204 ,  208 ,  212 ,  214 ,  216 ,  218 ,  238 ) may at least measure temperature and/or pressure. Sensors ( 204 ,  208 ,  212 ,  214 ,  216 ,  218 ,  238 ) are in electrical connection with PLC  222 . Other sensor locations are contemplated for this and all other embodiments as desired. 
     Based upon information received from sensors ( 204 ,  208 ,  212 ,  214 ,  216 ,  218 ,  238 ), PLC  222  may signal first pump  220  to communicate a pressurized fluid to first cavity  198  to provide a predetermined fluid pressure P 2  to first cavity  198  to reduce the differential pressure between the fluid wellbore pressure P 1  in the diverter housing  206  and the predetermined fluid pressure P 2  in first cavity  198  on first sealing element  190 . It is contemplated that P 2  may be greater than, less than, or equal to P 1 . PLC  222  may also signal second pump  228  to communicate a pressurized fluid to second cavity  202  to provide a predetermined fluid pressure P 3  to second cavity  202  to reduce the differential pressure between the fluid pressure P 2  in the first cavity  198  and the predetermined fluid pressure P 3  in second cavity  202  on second sealing element  200 . It is contemplated that P 3  may be greater than, less than, or equal to P 2 . Active sealing element  190  may be pressurized to increase sealing with drill string DS if the PLC  222  determines leakage between the tubular and active sealing element  190 . Third sealing element  210  may be removed from above while leaving second sealing element  200  in position. Second sealing element  200  may also be removed from above while leaving first sealing element  190  in position. Alternatively, RCD  191  may be removed from single latching mechanism  223  by unlatching latch  221  to obtain access to the sealing elements ( 190 ,  200 ,  210 ). 
     In  FIG. 10 , RCD, generally indicated at  245 , has an inner member  242  rotatable relative to an outer member  246  about bearing assembly  244 . A first sealing element  240  and a second sealing element  250  are attached to and rotate with inner member  242 . Sealing elements ( 240 ,  250 ) are passive stripper rubber sealing elements. First cavity  248  is defined by inner member  242 , tubular or drill string DS, first sealing element  240 , and second scaling element  250 . Pressure regulator, such as choke valve  268 , is in fluid communication with first cavity  248  through influent line  269 B and sized influent port  271  in inner member  242 . A first sensor  256  is positioned in influent line  269 B. A second probe sensor  254  is positioned in diverter housing  252 . Sensors ( 254 ,  256 ) may at least measure temperature and/or pressure. Pressure regulator or choke valve  268 , like all pressure regulators or choke valves in all embodiments shown in  FIGS. 10, 11, 12A, 12B, 13A, 13B, 14A, 14B, 15A, 15B, 15C, 16A, 16B, and 17A  can be in electrical connection with a PLC, such as PLC  260  in  FIG. 10 . As discussed above, these regulators can be manual, semi automatic or automatic and hydraulic or electronic. The electrical connection may be hard wired, wireless or a combination of wired and wireless. PLC  260  is in electrical connection with first pump  262 . First pump  262  is in fluid communication with fluid source  264 . First pump  262  is in fluid communication with first cavity  248  through pressure regulator or choke valve  268  and influent lines  269 A,  269 B through sized influent port  271  in inner member  242 . Effluent line  270  is in fluid communication with first cavity  248  through sized effluent port  273  in inner member  242 . It is contemplated that in applicable (not an electronic choke valve) embodiments, a PLC will transmit hydraulic pressure to adjust the choke valve, e.g. setting the choke valve. Therefore, a dedicated hydraulic pump and manifold system is contemplated to control the choke valve. 
     Based upon information received from sensors ( 254 ,  256 ), PLC  260  may signal first pump  262  to communicate a pressurized fluid to first cavity  248  to provide a predetermined fluid pressure P 2  to first cavity  248  to reduce the differential pressure between the fluid wellbore pressure P 1  in the diverter housing  252  and the predetermined fluid pressure P 2  in first cavity  248  on first sealing element  240 . It is contemplated that P 2  may be greater than, less than, or equal to P 1 . Second pump  258  is in fluid communication with fluid source  264  and electrical connection with PLC  260 . PLC  260  may signal second pump  258  to send pressurized fluid through first conduit  272  into diverter housing  252 . First conduit  272  and second conduit  276  allow for pressurized flow of fluids, shown with arrows ( 274 ,  278 ), to cool and clean/flush first sealing element  240 . The pressurized flow ( 274 ,  275 ,  278 ) also shields first sealing element  240  from cuttings in the drilling fluid and hot returns in the diverter housing  252  from the wellbore. The same or a similar system may be used for all other embodiments. Other configurations of pressure regulators or choke valves, accumulators, pumps, sensors, and PLCs are contemplated for  FIG. 10  and for all other embodiments shown in  FIGS. 7 to 17B . 
     Turning to  FIG. 11 , RCD, generally indicated at  282 , has an inner member  284  rotatable relative to an outer member  288  about bearing assembly  286 . A first sealing element  280 , a second sealing element  290 , and a third sealing element  300  are attached to and rotate with inner member  284 . Sealing elements ( 280 ,  290 ,  300 ) are passive stripper rubber sealing elements. First cavity  292  is defined by inner member  284 , tubular or drill string DS, first sealing element  280 , and second sealing element  290 . Second cavity  295  is defined by inner member  284 , tubular or drill string DS, second sealing element  290 , and third sealing element  300 . 
     A first sensor  296  is positioned in first cavity  292 . A second sensor  298  is positioned in the diverter housing  294 . First PLC  302  is in electrical connection with first pump  304 . First pump  304  is in fluid communication with first fluid source  322 . First pump  304  is in fluid communication with first cavity  292  through first pressure regulator, such as choke valve  306 , first influent lines  308 A,  308 B, and first sized influent port  309  in inner member  284 . First effluent line  310  is in fluid communication with first cavity  292  through first sized effluent port  311  in inner member  284 . A third sensor  326  is positioned in first effluent line  310 . First pressure regulator  306  is in fluid communication with diverter housing  294  through first regulator line  316 . A fourth sensor  314  is positioned in first regulator line  316 . 
     First PLC  302  is in electrical connection with second pump  324 . Second pump  324  is in fluid communication with fluid source  322 . Second pump  324  is in fluid communication with second cavity  295  through second pressure regulator  320 , second influent lines  321 A,  321 B, and second sized influent port  323  in inner member  284 . Second effluent line  330  is in fluid communication with second cavity  295  through second effluent port  327 . Fifth sensor  328  is positioned in second effluent line  330 . Second pressure regulator  320  is in fluid communication with first influent line  308 B through second regulator line  318 . Sixth sensor  312  is positioned in second regulator line  318 . Sensors ( 296 ,  298 ,  312 ,  314 ,  326 ,  328 ) may at least measure temperature and/or pressure. Though sensors  326  and  328  are shown in electrical connection with second PLC  336 , sensors ( 296 ,  298 ,  312 ,  314 ,  326 ,  328 ) can be in electrical connection with first PLC  302 . Based upon information received from sensors ( 296 ,  298 ,  312 ,  314 ,  326 ,  328 ), first PLC  302  may signal first pump  304  to communicate a pressurized fluid to first cavity  292  to provide a predetermined fluid pressure P 2  to first cavity  292  to reduce the differential pressure between the fluid pressure P 1  in the diverter housing  294  and the predetermined fluid pressure P 2  in first cavity  292  on first sealing element  280 . It is contemplated that P 2  may be greater than, less than, or equal to P 1 . First PLC  302  may also signal second pump  324  to communicate a pressurized fluid to second cavity  295  to provide a predetermined fluid pressure P 3  to second cavity  295  to reduce the differential pressure between the fluid pressure P 2  in the first cavity  292  and the predetermined fluid pressure P 3  in second cavity  295  on second sealing element  290 . It is contemplated that P 3  may be greater than, less than, or equal to P 2 . 
     Third sealing element  300  may be threadedly removed from above while leaving second sealing element  290  in position. Second sealing element  290  may be threadedly removed from above while leaving first sealing element  280  in position. Alternatively, RCD  282  may be unlatched from single latching mechanism  291  by unlatching latch  293  and removed for access to the sealing elements ( 280 ,  290 ,  300 ). 
     Second PLC  332  is in electrical connection with sensors  326 ,  328 , first solenoid valve  336  and second solenoid valve  338  and third pump  334 . Third pump  334  is in fluid communication with second fluid source  340  and lines  310 ,  330 . First accumulator  341  is in fluid communication with line  310 , and second accumulator  343  is in fluid communication with line  330 . When first pressure regulator  306  is closed, PLC  332  may signal first valve  336  to open and third pump  334  to move fluid from second fluid source  340  through line  310  into first cavity  292 . Likewise, when second pressure regulator  320  is closed, second PLC  332  may signal second valve  338  to open and third pump  334  to move fluid from second fluid source  340  through line  330  into second cavity  295 . It is contemplated that both pressure regulators  306 ,  320  may be closed and both valves  336 ,  338  open. It is contemplated that the functions of second PLC  332  may be performed by first PLC  302 . Valves or orifices may be placed in lines  310 ,  330  to ensure that the flow moves into first cavity  292  and second cavity  295  rather than away from them. It is contemplated that the system of third pump  334 , second fluid source  340 , and valves  336 ,  338  may be used when cuttings free fluid different from fluid source  322 , such as a gas or cooling fluid in a geothermal application, is desired. 
     As now can be understood, a “Bare Bones” RCD differential pressure sharing system could use an existing dual sealing element design RCD, such as shown in  FIG. 10 , with the cavity between the sealing elements having communication with the annulus returns under the bottom sealing element via a high-pressure line, such as line  316  shown in  FIG. 11 . Also, a cuttings filter could be positioned immediately outside the RCD in the annulus returns line to filter the annulus returns fluid. An off-the-shelf pressure relief valve could be substituted in place of the PLC and adjustable choke valve, e.g., choke valve  306 . This substituted pressure relief valve may be pre-set to open to expose the top sealing element to full wellbore pressure when the bottom sealing element senses a predetermined amount of pressure. The top sealing element may handle some of the wellbore pressure when tripping out drill string. A reduction of differential pressure would significantly improve overall performance of the dual sealing element design RCD and meet API 16 RCD “stripping-out-under-dynamic pressure rating” guidelines. When the wellbore pressure subsides, the cuttings-free mud of higher pressure in the cavity can be burped down past (flushing) the sealing surface of the bottom sealing element. Also, the next tool joint passing thru will further aid in reducing any bottled up pressure in the cavity. 
     Turning to  FIGS. 11A and 11B , pressure compensation mechanisms ( 350 ,  370 ) of the RCD  282  allow for maintaining a desired lubricant pressure in the bearing assembly at a predetermined level higher than the pressures surrounding the mechanisms ( 350 ,  370 ). For example, the upper and lower pressure compensation mechanisms provide 50 psi additional pressure over the maximum of the wellbore pressure in the diverter housing  294 . Similar pressure compensation mechanisms are proposed in U.S. Pat. No. 7,258,171 (see &#39;171 patent  FIGS. 26A to 26F ), which is hereby incorporated by reference for all purposes in its entirety and is assigned to the assignee of the present invention. It is contemplated that similar pressure compensation mechanisms may be used with all embodiments shown in  FIGS. 7 to 17B . Although only three sealing elements ( 280 ,  290 ,  300 ) are shown in  FIG. 11 , it is contemplated that there may be more or less and different types of sealing elements. For all embodiments shown in  FIGS. 7 to 17B , it is contemplated that there may be more or less and different types of sealing elements than shown to increase the pressure capacity or provide other functions, e.g. rotation, of the pressure sharing RCD systems. 
     In  FIGS. 12A and 12B , second RCD, generally indicated at  390 A, is positioned with third housing  454  over first RCD, generally indicated at  390 B, so as to be aligned with tubular or drill string DS. The combined RCD  390 A and RCD  390 B is generally indicated as RCD  390 . First RCD  390 B has a first inner member  392  rotatable relative to a first outer member  396  about first bearing assembly  394 . A first sealing element  382  and a second sealing element  384  are attached to and rotate with inner member  392 . Sealing elements ( 382 ,  384 ) are passive stripper rubber sealing elements. Second RCD  390 A has a second inner member  446 , independent of first inner member  392 , rotatable relative to a second outer member  450  about second bearing assembly  448 . A third sealing element  386  and a fourth sealing element  388  are attached to and rotate with second inner member  446 . Sealing elements ( 386 ,  388 ) are also passive stripper rubber sealing elements. 
     In first RCD  390 B, first cavity  398  is defined by first inner member  392 , tubular or drill string DS, first sealing element  382 , and second sealing element  384 . Between first RCD  390 B and second RCD  390 A, second cavity  452  is defined by the inner surface of third housing  454  sealed with first RCD  390 B and second RCD  390 A, tubular or drill string DS, second sealing element  384 , and third sealing element  386 . Third cavity  444  is in second RCD  390 A, and is defined by second inner member  446 , tubular or drill string DS, third sealing element  386 , and fourth sealing element  388 . 
     First pressure regulator or choke valve  412 , second pressure regulator or choke valve  424 , and third pressure regulator or choke valve  434  are in fluid communication with each other and the wellbore pressure in diverter housing  400  through first regulator line  408  (via influent lines  410 A,  428 A,  436 A) and second regulator line  407 . Pressure regulators ( 412 ,  424 ,  434 ) are in electrical connection with PLC  404 . A first sensor  406  is positioned in second regulator line  407 . A second sensor  420  is positioned in first conduit  422  extending from diverter housing  400 . First pressure regulator  412  is in fluid communication with first cavity  398  through first influent line  410 B and first sized influent port  415  in first inner member  392 . A third sensor  414  is positioned in first influent line  410 B. First effluent line  416  is in fluid communication with first cavity  398  through first sized effluent port  417  in first inner member  392 . A fourth sensor  418  is positioned in first effluent line  416 . Second pressure regulator  424  is in fluid communication with second cavity  452  through second influent line  428 B and second sized influent port  433  in third housing or member  454 . A fifth sensor  426  is positioned in second influent line  428 B. Second effluent line  430  is in fluid communication with second cavity  452  through second sized effluent port  437  in third housing or member  454 . A sixth sensor  432  is positioned in second effluent line  430 . Third pressure regulator  434  is in fluid communication with third cavity  444  through third influent line  436 B and third sized influent port  441  in second inner member  446 . A seventh sensor  438  is positioned in third influent line  436 B. Third effluent line  440  is also in fluid communication with third cavity  444  through third sized effluent port  443  in second inner member  446 . An eighth sensor  442  is positioned in third effluent line  440 . A ninth probe sensor  402  is positioned in diverter housing  400 . 
     The nine sensors ( 402 ,  406 ,  414 ,  418 ,  420 ,  426 ,  432 ,  438 ,  442 ) may at least measure temperature and/or pressure. Sensors ( 402 ,  406 ,  414 ,  418 ,  420 ,  426 ,  432 ,  438 ,  442 ) are in electrical connection with PLC  404 . The connection may be hard wired, wireless or a combination of wired and wireless. Based upon information received from sensors ( 402 ,  406 ,  414 ,  418 ,  420 ,  426 ,  432 ,  438 ,  442 ), PLC  404  may signal pressure regulators ( 412 ,  424 ,  434 ) so as to provide desired respective pressures (P 2 , P 3 , P 4 ) in the first cavity  398 , second cavity  452 , and third cavity  444 , respectively, in relation to each other and the wellbore pressure P 1 . Fourth sealing element  388  may be removed from above while leaving third sealing element  386  in position. Removal of second RCD  390 A allows for removal of first RCD  390 B with second sealing element  384  and first sealing element  382 . Alternatively, after the second RCD  390 A is removed, second sealing element  384  may be removed from above while leaving first sealing element  382  in position. Alternatively to, or in some combination with the above, RCDs ( 390 A,  390 B) may be removed for access to all of the sealing elements. Second RCD  390 A is latchingly attached with third housing  454  by double latch mechanism  427 . Double latch mechanism upper inner latch  421  may be unlatched to remove RCD  390 A. Double latch mechanism lower outer latch  423  may be used to unlatch double latch mechanism  427  from third housing  454  with or without the RCD  390 A. First RCD  390 B may be unlatched from single latch mechanism  431  using second housing latch  429 . A single and double latch mechanism is proposed in greater detail in U.S. Pat. No. 7,487,837. Third housing  454  is bolted with second housing  453 , and second housing  453  is bolted with first or diverter housing  400 . Although only two independent RCDs ( 390 A,  390 B) are shown in  FIGS. 12A and 12B , it is contemplated that there may be more or less RCDs and more or less and different types of sealing elements. As can be understood from  FIGS. 12A and 12B , more than two RCDs, may be stacked in series to create more cavities and more potential for pressure sharing, thereby increasing the pressure rating of the stacked combined RCD, such as RCD  390 . 
     Turning to  FIGS. 13A, 13B and 13C , RCD, generally indicated as  460 , is positioned clamped or bolted in housings ( 518 ,  520 ,  522 ) over independent active sealing element  461 , which is shown engaged on tubular or drill string DS. RCD  460  has a common inner member  470  rotatable relative to a first outer member  474  and second outer member  475  about first bearing assemblies  472  and second bearing assemblies  477 . A first sealing element  462 , second sealing element  464 , third sealing element  466 , and fourth sealing element  468  are attached to and rotate with inner member  470 . Sealing elements ( 462 ,  464 ,  468 ) are passive stripper rubber sealing elements. Third sealing element  466  is an active sealing element, and is shown engaged on tubular or drill string DS. 
     First cavity  476  is defined by second housing or member  516 , third housing or member  518 , tubular or drill string DS, independent active sealing element  461 , and first sealing element  462 . Within RCD  460 , second cavity  478  is defined by inner member  470 , tubular or drill string DS, first sealing element  462 , and second scaling element  464 . Third cavity  480  is defined by inner member  470 , tubular or drill string DS, second sealing element  464 , and third sealing element  466 . Fourth cavity  490  is defined by inner member  470 , tubular or drill string DS, third sealing element  466 , and fourth sealing element  468 . 
     First pressure regulator or choke valve  498 , second pressure regulator or choke valve  500 , third pressure regulator or choke valve  502 , and fourth pressure regulator or choke valve  504  are in fluid communication with each other and the wellbore pressure P 1  through first regulator line  496  (via influent lines  508 A,  510 A,  512 A,  514 A) and second regulator line  497 . Pressure regulators ( 498 ,  500 ,  502 ,  504 ) are in electrical connection with PLC  506 . A first probe sensor  491  is positioned in the diverter housing  515 . A second sensor  492  is positioned in first cavity  476 . First pressure regulator  498  is in fluid communication with first cavity  476  through first influent line  508 B and first sized influent port  509  in inner member  470 . A third sensor  530  is positioned in second cavity  478 . Second pressure regulator  500  is in fluid communication with second cavity  478  through second influent line  510 B and second sized influent port  511  in inner member  470 . A fourth sensor  532  is positioned in third cavity  480 . Third pressure regulator  502  is in fluid communication with third cavity  480  through third influent line  512 B and third sized influent port  513  in inner member  470 . A fifth sensor  534  is positioned in fourth cavity  490 . Fourth pressure regulator  504  is in fluid communication with fourth cavity  490  through fourth influent line  514 B and fourth sized influent port  517  in inner member  470 . 
     Sensors ( 491 ,  492 ,  530 ,  532 ,  534 ) may at least measure temperature and/or pressure. Sensors ( 491 ,  492 ,  530 ,  532 ,  534 ) are in electrical connection with PLC  506 . Based upon information received from sensors ( 491 ,  492 ,  530 ,  532 ,  534 ), PLC  506  may signal pressure regulators ( 498 ,  500 ,  502 ,  504 ) so as to provide desired pressures (P 2 , P 3 , P 4 , P 5 ) in the first cavity  476 , second cavity  478 , third cavity  480 , and fourth cavity  490 , respectively, in relation to each other and the wellbore pressure P 1 . Pumps (not shown) for active sealing elements ( 461 ,  466 ) are in electrical connection with PLC  506 . Either one of active sealing elements ( 461 ,  466 ) or both of them may be pressurized to reduce slippage with the tubular or drill string DS if the PLC  506  indicates rotational difference between RCD  460  and independent sealing elements  461 . Fourth sealing element  468  may be removed from above without removing any sealing element below it. Third sealing element  466  may thereafter be removed without removing the sealing elements below it, and second sealing element  464  may be removed without removing first sealing element  462 . Alternatively, RCD  460  may be removed by unlatching first latch member  473  and second latch member  479 . After RCD  460  is removed, latch member  462  can be unlatched and independent sealing element  461  may be removed. 
     First or diverter housing  515  and second housing  516  are bolted together, as are third housing  518  and fourth housing  520 . However, second housing  516  and third housing  518  are clamped together with clamp  519 A, and fourth housing  520  and fifth housing  522  are clamped with clamp  519 B. Other alternative configurations and attachment means, as are known in the art, are contemplated. Clamps  519 A and  519 B may be an automatic clam shell clamping means, such as proposed in U.S. Pat. No. 5,662,181, which is incorporated herein by reference for all purposes in its entirety and is assigned to the assignee of the present invention. It is contemplated that a clamp like clamps  519 A and  519 B may be used in all embodiments, including where bolts are used to connect housings. Clamps allow for the housings, such as fifth housing  522  in  FIG. 13A , to be remotely disassembled so as to obtain access to or remove a sealing element, such as sealing element  464  in  FIG. 13B . Likewise clamp  519 A can be unclamped to obtain access to or remove independent active sealing element  461 . 
     As with other active sealing elements proposed herein, the active sealing elements  466 ,  461  are preferably engaged on a drill string DS when drilling and deflated to allow passage of a tool joint of drill string DS when tripping in or out. It is also contemplated that the PLC in all the embodiments could receive a signal from a sensor that a tool joint is passing a sealing element and pressure is then regulated in each cavity to inflate or deflate the respective active sealing element to minimize load across all the respective active sealing elements. As now can be better understood, the pressure regulators  498 ,  500 ,  502  and  504  can be controlled by PLC  506  to reduce wear on selected sealing elements. For example, when tripping out, the PLC automatically, or the operator could manually, deflate the active sealing elements  461 ,  466  so that cavity  476  pressure P 2  would be equal to wellbore pressure P 1 . PLC  506  could then signal pressure regulator  500  to increase the pressure P 3  in cavity  478  so that pressure P 3  is equal to or greater than pressure P 2 . With pressure P 3  greater than P 2 , it is contemplated that passive stripper rubber sealing element  462  would open/expand with less wear when a tool joint engages the nose of the sealing element  462  to begin to pass therethrough or to be stripped out. Furthermore, the pressure P 4  in cavity  480  could be controlled by pressure regulator  502  so that both pressures P 4  and P 5 , since active scaling element  466  is deflated, would be equal to or greater than pressure P 3  to reduce wear on passive stripper rubber sealing element  464 . In this case, passive sealing element  468  would be exposed to the higher pressure differential of atmospheric pressure resulting from pressures P 3  and P 4 . In other words, sealing element  468  would be the sacrificial sealing element to enhance the life and wearability of the remaining sealing elements  461 ,  462 ,  464 ,  466 . 
     Pressure relief solenoid valve  494  is sealingly connected with conduit  493  that is positioned across from conduit  497 . Pressure relief valve  494  and conduit  493  are in fluid communication with diverter housing  515 . Valve  494  may be pre-adjusted to a setting that is lower than the weakest subsurface component that defines the limit of the DTTL method, such as the casing shoe LOT or the formation fracture gradient (FIT). In the event that the wellbore pressure P 1  exceeds the limit (including any safety factor), then valve  494  may open to divert the returns away from the rig floor. In other words, this valve opening may also occur if the surface back pressure placed on the wellbore fluids approaches the weakest component upstream. Alternatively, fluid could be moved through open valve  494  through conduit  493  and across housing  515  to conduit  497  to cool and clean independent sealing element  461 . 
     Turning to  FIGS. 14A and 14B , RCD, generally indicated as  588 , is latched with third housing  568 , above independent active sealing element  540 , which is shown engaged on tubular or drill string DS. Third housing  568  is bolted with second housing  566 , and second housing  566  is bolted with first or diverter housing  564 . RCD  588  has an inner member  552  rotatable relative to an outer member  556  about bearing assembly  554 . A first sealing element  542  and second sealing element  544  are attached to and rotate with inner member  552 . First sealing element and second sealing element ( 542 ,  544 ) are passive stripper rubber sealing elements. 
     First cavity  548  is defined by second housing or member  566 , tubular or drill string DS, independent active sealing element  540 , and first sealing element  542 . Within RCD  588 , second cavity  550  is defined by inner member  552 , tubular or drill string DS, first sealing element  542 , and second sealing element  544 . First pressure regulator or choke valve  570  and second pressure regulator or choke valve  574  are in fluid communication with each other and the diverter housing  564  through first regulator line  578  (via influent lines  572 A,  576 A) and second regulator line  580 . Pressure regulators ( 570 ,  574 ) are also in fluid communication with an accumulator  586 . Accumulator  586 , as well as all other accumulators as shown in all other embodiments in  FIGS. 14A to 17B , may accumulate fluid pressure for use in supplying a predetermined stored fluid pressure to a cavity, such as first cavity  548  and second cavity  550  in  FIGS. 14A and 14B . Accumulators may be used with all embodiments to both compensate or act as a shock absorber for pressure surges or pulses and to provide stored fluid pressure as described or predetermined. Pressure surges may occur when the diameter of the drill string DS moved through the sealing element changes, such as for example the transition from the drill pipe body to the drill pipe tool joint. The change from the volume of the drill pipe body to the tool joint in the pressurized cavity may cause a pressure surge or pulse of the pressurized fluid for which the accumulator may compensate. Pressure regulators ( 570 ,  574 ) are in electrical connection with PLC  584 . A first sensor  558  is positioned in the diverter housing  564 . A second sensor  560  is positioned in first cavity  548 . First pressure regulator  570  is in fluid communication with first cavity  548  through first influent line  572 B and first sized influent port  573  in second housing  566 . A third sensor  562  is positioned in second cavity  550 . Second pressure regulator  574  is in fluid communication with second cavity  550  through second influent line  576 B and second sized influent port  577  in inner member  552 . 
     Sensors ( 558 ,  560 ,  562 ) may at least measure temperature and/or pressure. Sensors ( 558 ,  560 ,  562 ) are in electrical connection with PLC  584 . Based upon information received from sensors ( 558 ,  560 ,  562 ), PLC  584  may signal pressure regulators ( 570 ,  574 ) so as to provide desired pressures (P 2 , P 3 ) in the first cavity  548  and second cavity  550 , respectively, in relation to each other and the wellbore pressure P 1 . Solenoid valve  582  is positioned between the juncture of first regulator line  578  and second regulator line  580  and valve line  587 . Solenoid valve  582  is in electrical connection with PLC  584 . Based upon information received from sensors ( 558 ,  560 ,  562 ), PLC  584  may signal pressure solenoid valve  582  to open to relieve drilling fluid wellbore pressure from diverter housing  564  and signal the regulators ( 570 ,  574 ) to open/close as is appropriate. The pump (not shown) for independent active sealing element  540  is in electrical connection with PLC  584 . Pressure to chamber  540 A can be increased or decreased by PLC  584  to compensate for slippage, for example of sealing element  540  relative to rotation of inner member  552 . Third sealing member  544  may be removed from above without removing the sealing members below it, and second sealing member  542  may be removed after removing RCD  588 . First independent active sealing member  540  may be removed from above after removal of RCD  588 . A single latching mechanism having latch member  568 A is shown for removal of RCD  588  while a double latching mechanism having latch members  541 A,  541 B is provided for sealing element  540 . 
     In  FIGS. 15A, 15B and 15C , RCD, generally indicated as  590 , is positioned in a unitary diverter housing  591 . Tubular or drill string DS is positioned in RCD  590 . RCD  590  has a common inner member  600  rotatable relative to a first outer member  604 , second outer member  606  and third outer member  610  about a first bearing assembly  602 , second bearing assembly  608  and third bearing assembly  612 . A first sealing element  592 , second sealing element  594 , third sealing element  596 , and fourth sealing element  598  are attached to and rotate with inner member  600 . Sealing elements ( 592 ,  594 ,  596 ,  598 ) are passive stripper rubber sealing elements. 
     First cavity  618  is defined by inner member  600 , tubular or drill string DS, first sealing element  592 , and second sealing element  594 . Second cavity  620  is defined by inner member  600 , tubular or drill string DS, second sealing element  594 , and third sealing element  596 . Third cavity  622  is defined by inner member  600 , tubular or drill string DS, third sealing element  596 , and fourth sealing element  598 . 
     First pressure regulator or choke valve  630 , second pressure regulator or choke valve  634 , and third pressure regulator or choke valve  638  are in fluid communication with each other and the wellbore pressure P 1  in the lower end of diverter housing  591  through first regulator line  642  (via influent lines  632 A,  636 A,  640 A) and second regulator line  644 . Pressure regulators ( 630 ,  634 ,  638 ) are in electrical connection with PLC  646 . A first probe sensor  616  is positioned in the lower end of diverter housing  591 . A second sensor  624  is positioned in first cavity  618 . First pressure regulator  630  is in fluid communication with first cavity  618  through first influent line  632 B and first sized influent port  633  in inner member  600 . A third sensor  626  is positioned in second cavity  620 . Second pressure regulator  634  is in fluid communication with second cavity  620  through second influent line  636 B and second sized influent port  637  in inner member  600 . A fourth sensor  628  is positioned in third cavity  622 . Third pressure regulator  638  is in fluid communication with third cavity  622  through third influent line  640 B and third sized influent port  641  in inner member  600 . 
     Sensors ( 616 ,  624 ,  626 ,  628 ) may at least measure temperature and/or pressure. Sensors ( 616 ,  624 ,  626 ,  628 ) are in electrical connection with PLC  646 . Other sensor configurations are contemplated for  FIGS. 15A-15C  and for all other embodiments. Based upon information received from sensors ( 616 ,  624 ,  626 ,  628 ), PLC  646  may signal pressure regulators ( 630 ,  634 ,  638 ) so as to provide desired pressures (P 2 , P 3 , P 4 ) in the first cavity  618 , second cavity  620 , and third cavity  622 , respectively, in relation to each other and the wellbore pressure P 1 . Fourth sealing member  598  may be removed from above without removing sealing members below it using latch  600 A, third sealing member  596  may also be removed without removing the sealing members below it using latch  600 B. Once the fourth sealing element is removed, the second sealing member  594  may be removed without removing first sealing member  592 . First sealing member  592  may be removed with inner member  600  using latch  600 C. 
     The pressure regulators  630 ,  634 ,  638  could be controlled by PLC  646  so that the two lower stripper rubber sealing elements  592 ,  594  would experience high wear. In this case, pressure P 2  would be less than, perhaps one half of, the pressure P 1  and pressure P 3  would be less than, perhaps one-quarter of, pressure P 1 . This high differential pressure across sealing elements  592 ,  594  would cause the sealing elements  592 ,  594  to experience higher wear when the drill string DS and its tool joints are tripped out of the well. As a result, pressure P 4  in cavity  622  could be regulated at less than one-quarter of the pressure P 1  so that the differential pressure across passive sealing elements  596 ,  598  is reduced or mitigated. In summary, upon tripping out sacrificial passive stripper rubber sealing elements  592 ,  594  would experience higher wear and protected passive stripper rubber sealing elements  596 ,  598  would experience less wear, thereby increasing their wearability for when drilling ahead. 
     Turning to  FIGS. 16A and 16B , RCD, generally indicated as  651 , is positioned above diverter housing  666 . Tubular or drill string DS is positioned in RCD  651 . RCD  651  has a common inner member  656  rotatable relative to a first outer member  660  about a first bearing assembly  658  and second bearing assembly  664 . A first sealing element  650 , second sealing element  652 , and third sealing element  654  are attached to and rotate with inner member  656 . First sealing element  650  and second sealing element  652  are passive stripper rubber sealing elements. Third sealing element  654  is an active sealing element. First cavity  668  is defined by inner member  656 , tubular or drill string DS, first sealing element  650 , and second sealing element  652 . Second cavity  670  is defined by inner member  656 , drill string DS, second sealing element  652 , and third sealing element  654 . 
     First pressure regulator or choke valve  678  and second pressure regulator or choke valve  696  are in fluid (via influent lines  680 A,  698 A) communication with each other and the wellbore pressure P 1  in diverter housing  666  through first regulator line  692  and second regulator line  694 . Pressure regulators ( 678 ,  696 ) are in electrical connection with PLC  690 . First accumulator  672 , second accumulator  674  and third accumulator  676  are in fluid communication with first regulator line  692  and the wellbore pressure P 1 . Accumulators ( 672 ,  674 ,  676 ) operate as discussed above. Solenoid valve  671  is in fluid communication with first regulator line  692 , second regulator line  694 , and accumulator  672  and operates as discussed above. A first probe sensor  710  is positioned in the diverter housing  666  for measuring wellbore pressure P 1  and temperature. A second sensor  688  is positioned in first influent line  680 B. First pressure regulator  678  is in fluid communication with first cavity  668  through first influent line  680 B and first-sized influent port  682  in inner member  656 . First effluent line  686  is in fluid communication with first cavity  668  through first-sized effluent port  684  in inner member  656 . Second pressure regulator  696  is in fluid communication with second cavity  670  through second influent line  698 B and second sized influent port  702  in inner member  656 . A third sensor  700  is positioned in second influent line  698 B. Second effluent line  706  is in fluid communication with second cavity  670  through second sized effluent port  704  in inner member  656 . 
     Sensors ( 688 ,  700 ,  710 ) may at least measure temperature and/or pressure. Sensors ( 688 ,  700 ,  710 ) are in electrical connection with PLC  690 . Based upon information received from sensors ( 688 ,  700 ,  710 ), PLC  690  may signal pressure regulators ( 678 ,  696 ) so as to provide desired pressures (P 2 , P 3 ) in the first cavity  668  and second cavity  670 , respectively, in relation to each other and the wellbore pressure P 1 . Pump (not shown) for active sealing element  654  is in electrical connection with PLC  690 . PLC  690  may also signal solenoid valve  671  to open or close as discussed above in detail. 
     In  FIGS. 17A and 17B , RCD, generally indicated as  726 , is latched with fourth housing  757 , over independent active sealing element  720 , which is shown engaged on tubular or drill string DS. Fourth housing  757  is bolted with third housing  754 , third housing  754  is bolted with second housing  753 , and second housing  753  is latched using latch  753 A with first or diverter housing  751 . RCD  726  has an inner member  734  rotatable relative to an outer member  738  about bearings  736 . A first sealing element  722  and second sealing element  724  are attached to and rotate with inner member  734 . Sealing elements ( 722 ,  724 ) are passive stripper rubber sealing elements. 
     First cavity  730  is defined by third housing or member  754 , tubular or drill string DS, independent active sealing element  720 , and first sealing element  722 . Within RCD  726 , second cavity  732  is defined by inner member  734 , tubular or drill string DS, first sealing element  722 , and second sealing element  724 . First pressure regulator or choke valve  748  and second pressure regulator or choke valve  756  are in fluid communication with each other and the wellbore pressure P 1  in diverter housing  751  through first regulator line  744  (via influent lines  750 A,  758 A) and second regulator line  746 . Pressure regulators ( 748 ,  756 ) are also in fluid communication with an accumulator  762 . Pressure regulators ( 748 ,  756 ) are in electrical connection with PLC  768 . A first sensor  763  is positioned in the diverter housing  751 . A second sensor  764  is positioned in first cavity  730 . First pressure regulator  748  is in fluid communication with first cavity  730  through first influent line  750 B and first sized influent port  752  in third housing  754 . A third sensor  766  is positioned in second cavity  732 . Second pressure regulator  756  is in fluid communication with second cavity  732  through second influent line  758 B and second sized influent port  760  in inner member  734 . 
     Sensors ( 763 ,  764 ,  766 ) may at least measure temperature and/or pressure. Sensors ( 763 ,  764 ,  766 ) are in electrical connection with PLC  768 . Based upon information received from sensors ( 763 ,  764 ,  766 ), PLC  768  may signal pressure regulators ( 748 ,  756 ) so as to provide desired pressures (P 2 , P 3 ) in the first cavity  730  and second cavity  732 , respectively, in relation to each other and the wellbore pressure P 1 . Accumulator  762  is in fluid communication with first regulator line  744  and therefore the wellbore pressure P 1 . Solenoid valve  742  is positioned between the juncture of first regulator line  744  and second regulator line  746  in valve line  741 . Solenoid valve  742  is in electrical connection with PLC  768 . Based upon information received from sensors ( 763 ,  764 ,  766 ), PLC  768  may signal solenoid valve  742  as discussed above. Pump (not shown) for active sealing element  720  is also in electrical connection with PLC  768 . The active sealing element  720  may be activated, among other reasons, to compensate for rotational differences of the drill string DS with the passive sealing elements. Stabilizer  740  for drill string DS is positioned below independent active sealing element  720 . Drill string stabilizer  740  may be used to retrieve active sealing element  720  after the RCD  726  is removed. It is contemplated that a stabilizer to remove sealing elements may be used with all embodiments of the invention. 
     Not only may the pressure between a pair of active/passive sealing elements be adjusted, but also for a configuration in which an RCD is used within a riser, the pressure above the uppermost sealing element may be controlled—for example, by selecting the density and/or the level of fluid within the riser above the RCD. Depending upon the location of the RCD within the riser (i.e., towards the top, in the middle, towards the bottom, etc.), the selection of fluid type, density and level within the riser above the RCD may have a significant effect upon the pressure differential experienced by the uppermost seal of the RCD. Hence, the annular space within the riser above an RCD presents an additional “cavity”, the pressure within which may also be controlled to a certain extent. 
     A drilling operation utilizing an RCD may comprise several “phases”, each phase presenting different demands upon the integrity and longevity of an RCD active or passive sealing element. Such phases may include running a drill string into the wellbore, drilling ahead while rotating the drill string, drilling ahead while not rotating the drill string (i.e., when a mud motor is used to rotate the drill bit), drilling ahead across a geological boundary into a zone exhibiting higher or lower pressure, reciprocation of the drill string, pulling a drill string out of the wellbore, etc. Each of these phases places a different demand upon the sealing elements of an RCD. For example, running a drill string into the wellbore may not be particularly detrimental to the downwardly and inwardly taper of passive stripper rubber sealing elements; however, such a configuration may be very detrimental when the drill string is pulled out of the wellbore and successive upset tool joints are forced upwards past each sealing element. 
     The pressures within each cavity may be controlled during any phase of the drilling operation, such that adjustment of pressures within one or more cavities may be tailored to each phase of the drilling operation. Furthermore, the pressures within each cavity may be changed occasionally or regularly while a single phase of the drilling operation is proceeding to spread or “even out” the demand placed upon one or more sealing elements. 
     For example, in operating a multi-seal RCD, the pressures within one or more cavities may be adjusted such that one particular sealing element experiences a relatively high differential pressure, and thereby is considered the “main” sealing element. This would be the case if one or more additional sealing elements within the RCD were to be employed as a “reserve” or protected sealing element, ready to be used as the new “main or sacrificial” sealing element should the original “main or sacrificial” sealing element fail. An operator may not wish to place such a demand on any one sealing element for a prolonged period, and therefore may periodically choose to adjust the pressures within the cavities of the RCD such that other sealing elements within the RCD are utilized as the “main or sacrificial” sealing element, even though the integrity of the original “main” sealing element may still be good. In this way, a periodic assessment of the integrity of each sealing element may be performed while the RCD is in operation, and the risk of failure of any one sealing element may be reduced. 
     Additionally, adjustment of the pressures within the cavities may be made according to which of the above phases of the drilling operation are being conducted. For example, in a multi-seal RCD, one or more sealing elements may be primarily employed to contain the wellbore pressure during the drilling phase—i.e., while the bit is rotating at the bottom of the wellbore, and the open hole section is being extended. When it is desired to pull the drill string out of the wellbore, it may be preferred that one or more other sealing elements be selected for the duty of primary pressure containment. This is particularly relevant for those embodiments which include both active and passive sealing elements. It may be desired to use an active sealing element only while drilling is progressing, with little or no demand being placed upon the passive sealing elements. When pulling the drill string out of the wellbore, the active sealing element may be de-activated or deflated, and so the remaining passive sealing elements are selected to contain the wellbore pressure. Similarly, for those embodiments employing only multiple passive sealing elements, the pressures within each cavity may be adjusted such that selected sealing element(s) primarily withstand wellbore pressure during the drilling phase, whereas other sealing element(s) primarily withstand wellbore pressure while pulling the drill string out of the wellbore. In this scenario, the material and configuration of the material used in each sealing element may be selected such that those identified for primary use while pulling the drill string out of the wellbore may be constructed of a more abrasion-resistant material than those sealing elements selected for primary use while drilling. 
     In a further embodiment, the instantaneous differential pressure experienced by a sealing element may be controlled specifically to coincide with the passage of an article, for example, a tool joint of a drill string, through the sealing element. For example, while pulling a drill string out of a wellbore though multiple passive sealing elements, many tool joints are forced through the sealing elements, which is most detrimental to the integrity and life of the sealing elements if this occurs simultaneously while the sealing elements themselves are subject to withstanding the pressure within the wellbore. Therefore, an operator may choose to adjust the differential pressure experienced by a particular sealing element to coincide with the passage of a tool joint through that sealing element. The pressure within one or more cavities may be adjusted such that the pressure above a sealing element is slightly less than, equal to, or greater than the pressure below the sealing element when the tool joint is being raised through the sealing element. When the tool joint has passed through a sealing element and is about to be passed through a second sealing element, the pressures within each cavity may be adjusted again such that the conditions under which the tool joint passed though the first sealing element are replicated for the second sealing element. In this way, the pulling out of successive tool joints past each sealing element need not be as detrimental to the sealing elements as it would have been had this pressure control not been employed. 
     It should be noted that for all situations described above in which the pressures within the cavities are adjusted according to the phase of the drilling operation, or the timing of events, or according to operator selection, the monitoring and adjustment may be accomplished using manual control, using pre-programmed control via one or more PLCs, using programmed control to react to a sensor output (again via a PLC), or by using any combination of these. 
     The foregoing disclosure and description of the invention are illustrative and explanatory thereof, and various changes in the details of the illustrated apparatus and system, and the construction and method of operation may be made without departing from the spirit of the invention.