BACKGROUND OF THE INVENTION The present invention relates generally to methods and apparatus for drilling subsea wells. More specifically, the present invention relates to methods and apparatus for drilling subsea wells using a dual pressure gradient system in the annulus whereby the returns in the upper portion of the annulus have a lower density than the returns in the lower portion of the annulus.

The drilling of wells to find and recover hydrocarbons is sometimes carried out offshore, where recent advances in drilling technology have increased the water depths in which drilling is taking place. There are currently exploration wells being drilled in water as deep as 10,000 feet. As the water depth increases, the cost and technical difficulty of drilling these wells also increases.

A drilling fluid is typically used when drilling a well. This fluid has multiple functions, one of which is to provide pressure in the open wellbore in order to prevent the influx of fluid from the formation. Thus, the pressure in the open wellbore is typically maintained at a higher pressure than the fluid pressure in the formation pore space (pore pressure). The influx of formation fluids into the wellbore is called a kick. Because the formation fluid entering the wellbore ordinarily has a lower density than the drilling fluid, a kick will potentially reduce the hydrostatic pressure within the well and allow an accelerating influx of formation fluid. If not properly controlled, this influx is known as a blowout and may result in the loss of the well, the drilling rig, and possibly the lives of those operating the rig. Therefore, when formation fluid influx is not desired (almost always the case), the formation pore pressure defines a lower limit for allowable wellbore pressure in the open wellbore, i. e. uncased borehole.

The open wellbore extends below the lowermost casing string, which is cemented to the formation at, and for some distance above, a casing shoe. In an open wellbore that extends into a porous formation, deposits from the drilling fluid will collect on wellbore wall and form a filter cake. The filter cake forms an important barrier between the formation fluids contained in the permeable formation at a certain pore pressure and the wellbore fluids that are circulating at

a higher pressure. Thus, the filter cake provides a buffer that allows wellbore pressure to be maintained above pore pressure without significant losses of drilling fluid into the formation.

In order to maximize the rate of drilling, it is desirable to maintain the wellbore pressure at a level above, but relatively close to, the pore pressure. As wellbore pressure increases, drilling rate will decrease, and if the wellbore pressure is allowed to increase to the point it exceeds the formation fracture pressure (fracture pressure), a formation fracture can occur.

Once the formation fractures, returns flowing in the annulus may exit the open wellbore thereby decreasing the fluid column in the well. If this fluid is not replaced, the wellbore pressure can drop and allow formation fluids to enter the wellbore, causing a kick and potentially a blowout.

Therefore, the formation fracture pressure defines an upper limit for allowable wellbore pressure in an open wellbore. Typically, the formation immediately below the casing shoe has the lowest fracture pressure in the open wellbore, and therefore it is the fracture pressure at this depth that controls the maximum annulus pressure.

The fracture pressure is determined in part by the overburden acting at a particular depth of the formation. The overburden includes all of the rock and other material that overlays, and therefore must be supported by, a particular level of the formation. In an offshore well, the overburden includes not only the sediment of the earth but also the water above the mudline. The density of the earth, or sediment, provides an overburden gradient of approximately 1 psi per foot. The density of seawater provides an overburden gradient of approximately 0.45 psi/ft. The pore pressure at a given depth is determined in part by the hydrostatic pressure of the fluids above that depth. These fluids include fluids within the formation below the seafloor/mudline plus the seawater from the seafloor to the sea surface. A formation fluid gradient of 0.465 psi/ft is often considered normal. The typical seawater pressure gradient is about 0.45 psi/ft.

In surface and shallow water wells the differential in gradient between the seawater (or groundwater) and the earth often creates a pore pressure profile and fracture pressure profile that provide a sufficient range of pressure to allow the use of conventional drilling techniques.

Figure 1 shows a schematic representation of pore pressure PP and fracture pressure FP. The pressure developed in the wellbore is essentially determined by the hydrostatic pressure of the wellbore fluid, along with pressure variations due to fluid circulation and/or pipe movement.

For any given open hole interval, the region of allowable pressure lies between the pore pressure profile, and the fracture pressure profile for that portion of the well between the deepest casing shoe and the bottom of the well.

Clean drilling fluid is circulated into the well through the drill string and then returns to the surface through the annulus between the wellbore wall and the drill string. In offshore drilling operations, a riser is used to contain the annulus fluid between the sea floor and the drilling rig located on the surface. The pressure developed in the annulus is of particular concern because it is the fluid in the annulus that acts directly on the uncased borehole.

The fluid flowing through the annulus, typically known as returns, includes the drilling fluid, cuttings from the well, and any formation fluids that may enter the wellbore. The drilling fluid typically has a fairly constant density and thus the hydrostatic pressure in the wellbore vs. depth can typically be approximated by a single gradient starting at the top of the fluid column.

In offshore drilling situations, the top of the fluid column is generally the top of the riser at the surface platform.

The pressure profile of a given drilling fluid varies depending upon whether the drilling fluid is being circulated (dynamic) or not being circulated (static). These two pressure profiles are represented by the static pressure SP and dynamic pressure DP profiles on Figure 1. In the dynamic case, there is a pressure loss as the returns flow up the annulus between the drill string and wellbore wall. This pressure loss adds to the pressure of the drilling fluid in the annulus.

Thus, this additional pressure must be taken into consideration to ensure that drilling is maintained in an acceptable pressure range between the pore pressure and fracture pressure profiles.

Because the dynamic pressure DP is higher than the static pressure SP, it is the dynamic pressure at the highest point in the uncased wellbore, i. e. the lowermost casing shoe, that is limited by the fracture pressure FP at depth D1. Correspondingly, the lower static pressure SP must be maintained above the pore pressure PP at the deepest point D2 in the open wellbore.

Therefore, the range of allowable pressures for a certain length of uncased wellbore L1, as shown in Figure 1, is limited by the dynamic pressure DP reaching fracture pressure FP at the casing shoe depth D1 and the static pressure SP reaching pore pressure PP at the bottom of the well D2. Once depth D2 is reached, an additional string of casing may then be installed to allow drilling to progress deeper. The shallowest point in the uncased wellbore is then at depth D2. The limiting fracture pressure FP is greater at depth D2 compared to that at depth D1, therefore the allowable wellbore pressure is increased.

As drilling progresses, the length and depth of open hole interval below the casing shoe increases, resulting in a greater potential to exceed the formation fracture pressure. Various factors contribute to this greater potential. One important factor is typically the requirement to

increase the mud density as the pore pressure gradient increases with depth. Another important factor is the increase (with depth) of the maximum pressure that can be generated during well control operations. Before the potential to exceed the fracture pressure reaches an unacceptable level, another string of casing must be set, thereby allowing drilling to progress deeper. The process is repeated until the desired total depth is reached.

Figure 2 represents the typical pore pressure profile PP and fracture pressure profile FP for a well located in deep water (greater than 5000 feet). The pore pressure profile PP and fracture pressure profile FP are closer together in deep water because of the significant amount of overburden from the water depth, thus reducing the acceptable range of pressures for drilling at a particular depth. Because the two profiles are closer together, the range of available pressures for a certain depth is reduced. This range is even further reduced in most drilling practices that include a factor of safety to avoid wellbore pressures approaching the limits of desired operation.

An initial maximum drilling fluid density is chosen such that the dynamic pressure 10 will not exceed the fracture pressure at point 12, which is the shallowest point in the open hole.

This maximum drilling fluid density is used to define the point 16 where the static pressure profile 14 intersects the pore pressure profile. This forms a region 18 of allowable pressure and indicates a depth 20 above which a string of casing should be set. Once this casing is set, the maximum density of the drilling fluid may be increased such that the dynamic pressure 22 will not exceed the fracture pressure at point 24, which is now the shallowest point in the open hole.

This new maximum drilling fluid density is then used to define the point 28 where the static pressure profile 26 intersects the pore pressure profile. This now defines a second region 30 of allowable pressure and a depth 32 above which casing should be set. This continues until the desired wellbore total depth is reached. The distance that can be drilled before needing to set a casing string, i. e. between depths 20 and 32, is known as a drilling interval.

The reduced range of allowable pressures in deep water drilling translates into a shorter drilling interval and an increased number of casing strings when using single-gradient drilling in deep water. The increased number of casing strings increases the cost and complexity of a deep-water well. Additionally, each successive casing string decreases the size of the wellbore and limits the size of any equipment that has to pass through that region of the well, including the drill bit for the next section of borehole. Therefore, it is desired to drill as far as possible in the region between the pore pressure profile and the fracture pressure profile and minimize the number of casing strings needed in a well. One way to extend the drilling interval is to cause

the slope of wellbore pressure profile to approach the slopes of the pore pressure profile and fracture pressure profile, which allows the wellbore pressure to be maintained in the range of allowable pressure to a greater depth, hence a longer drilling interval.

One method used in drilling wells in deep water depths is dual-gradient drilling. Dual- gradient drilling techniques seek to adjust the density of the column of fluid contained in the wellbore. Typical single-gradient drilling technology seeks to control wellbore pressure using a column of substantially constant-density drilling fluid from the bottom of the well back to the rig. In contrast, dual-gradient drilling seeks to control wellbore pressure by using a lower density fluid, about the same density as seawater, from the rig to the seafloor and then uses a higher density drilling fluid within the actual formation, i. e. between the seafloor and the bottom of the well. Dual-gradient drilling techniques, in effect, simulate the drilling rig being located on the seafloor and therefore avoid some of the problems associated with deep-water drilling.

Referring now to Figure 3, the objective of dual-gradient drilling is to shift the drilling fluid pressure gradients from the profiles shown in Figure 2 to dual gradient profiles as shown in Figure 3. In general, dual gradient pressure profiles have a first gradient that extends from a surface platform and a second, greater gradient extending from lower in the annulus, such as from the mud line down into the well. For example, an initial maximum dual-gradient drilling fluid density is chosen such that the dynamic pressure 34 will not exceed the fracture pressure at point 36, which is the shallowest point in the open hole. This maximum drilling fluid density is used to define the point 40 where the static pressure profile 38 intersects the pore pressure profile. This forms a region 42 of allowable pressure and indicates a depth 44, above which a string of casing should be set.

Once this casing is set, the maximum density of the drilling fluid may be increased such that the dynamic pressure 46 will not exceed the fracture pressure at point 48, which is now the shallowest point in the open hole. This new maximum drilling fluid density is then used to define the point 52 where the static pressure profile 50 intersects the pore pressure profile. This now defines a second region 54 of allowable pressure and a depth 56 above which casing should be set. This continues until the desired wellbore total depth is reached. It can be seen that the dual-gradient fluid allows the drilling fluid gradients in the lower portion of the annulus to more closely follow the pore pressure profile PP and fracture pressure profile FP. Thus, when compared to Figure 2, a greater well depth can be drilled with the same number of casing strings or the same depth can be reached with fewer casing strings.

There are currently several dual-gradient drilling techniques being developed in the industry. Each approach addresses the means of directing the fluids in the system to the surface in similar but mechanically different ways. One technique is to separate at least a portion of the drilling fluid from the riser annulus at the seafloor. That fluid is either returned to the surface through a separate line or processed at the seafloor. Another technique involves pumping the returns back to the surface from the seafloor. Most often these techniques involve placing pumping and fluid cleaning equipment at the seafloor to process the fluid or provide the force needed to return the fluid to the surface or recirculate through the wellbore. These systems are faced with the technological challenges of operating a submerged high rate pump located in a remote, inhospitable location (the sea floor) and the difficulty of the required high rate pumping of the drilling fluid laden with drill cuttings.

Another method of decreasing the pressure at the bottom of the riser is to inject a less dense fluid, typically a gas, at the bottom of the riser, resulting in a mixture of decreased density in the riser. With conventional existing drilling systems, the volume of gas required can be impractical for conventionally sized risers, and a conventional low-pressure drilling riser system is not designed to control multi-phase (gas, liquid, and solids) returns. Some of these systems involve allowing seawater to flow into the wellbore to decrease the density of the fluid in the annulus. This adds additional difficulty in then removing the seawater from the drilling fluid once it reaches the surface.

Thus, there remains a need in the art for methods and apparatus for drilling wells in deep-water using dual-gradient drilling concepts. Therefore, the embodiments of the present invention are directed to methods and apparatus for utilizing dual-gradient drilling concepts that seek to overcome the limitations of the prior art.

SUMMARY OF THE PREFERRED EMBODIMENTS Accordingly, there are provided herein methods and apparatus for drilling subsea wells in deep water using dual-gradient drilling techniques. The preferred embodiments of the present invention are characterized by a drilling system utilizing a coiled tubing drill string, a high pressure riser, and a system for injecting a gas into the high pressure riser. The preferred drill string also includes a downhole pressure sensing device for monitoring wellbore pressure. The embodiments of the present invention act to reduce the cost and complexity of a dual-gradient drilling system, thereby increasing the efficiency and/or feasibility of deep-water drilling applications.

One preferred embodiment includes a high pressure riser extending from a drilling platform at the surface to the seafloor or mud line. The base of the riser is connected to a wellhead that is anchored to the seafloor. Pressure control equipment is preferably disposed on the upper end of the riser at the drilling platform. A bottom hole assembly (BHA) is run on a coiled tubing drill string through the riser and into the subsea formation. The BHA preferably includes a pressure sensing device that can be used in transmitting real-time downhole pressure data to the surface. A riser injection system is provided to inject a lower density fluid into the riser annulus in order to reduce the density of the returns in the riser annulus and therefore reduce the hydrostatic pressure within the wellbore annulus.

In the preferred embodiments, an inert gas, such as nitrogen, is injected into the riser during circulation. This results in the desired dual-gradient condition, i. e. the average density of the fluid in the riser is lower than the average density of the fluid in the wellbore below the sea floor. During this circulation and the injection process, the wellbore pressure can be monitored by the downhole pressure sensor preferably integrated into the bottom hole assembly. Using this pressure information feedback, the rate of gas injection can be varied to result in a wellbore pressure that stays within the range of allowable pressure within the open wellbore. The high-pressure riser, with pressure control equipment, preferably including a choke, at the top, can be used to control the pressure of the returns and the expansion of gas within the riser by holding back-pressure at the top of the riser.

As previously discussed, as the drilling fluid circulation rate is increased, the wellbore pressure will tend to increase due to flowing friction. Thus, in the preferred embodiments, the gas injection rate in the riser can be increased, resulting in decreased hydrostatic pressure to counteract the friction pressure in order to keep the wellbore pressure below the formation fracture pressure. Conversely, as the drilling fluid circulation rate is decreased, the above process is reversed in order to keep the wellbore pressure above the formation pore pressure.

Constant real-time information on wellbore pressure at the bottom hole assembly enables this process to be controlled to a level of precision not possible with previous approaches.

One aspect of the current invention is to utilize a simpler method of decreasing the pressure at the bottom of the riser, when compared with using a pump at the seafloor. The preferred embodiments also provide a more practical method of using gas injection to control the fluid density in the riser, as compared with methods that have neither a high pressure riser nor a capability for real time bottom hole pressure measurement. Yet another aspect of the preferred embodiments is a more effective and precise method of controlling wellbore pressure

in order to maintain the pressure between formation pore pressure and formation fracture pressure.

Another aspect of the current invention is a method that monitors fluid flowing into and out of the well to detect potential well problems. The drilling fluid and injected fluid put into the annulus are monitored and compared to the fluids that leave the well. If the total flow rate of fluid into the well exceeds the flow rate leaving the well, then fluid is being lost in the well.

If the total flow rate of fluid into the well is less than the flow rate leaving the well, the formation fluid is flowing into the well. Both of these conditions can lead to a loss of well control.

Thus, the present invention comprises a combination of features and advantages that enable it to substantially reduce the complexity and cost associated with using dual-gradient drilling techniques in deep-water wells. These and various other characteristics and advantages of the present invention will be readily apparent to those skilled in the art upon reading the following detailed description of the preferred embodiments of the invention and by referring to the accompanying drawings.

BRIEF DESCRIPTION OF THE DRAWINGS For a more detailed understanding of the preferred embodiments, reference is made to the accompanying Figures, wherein: Figure 1 is a graphical representation of pressure vs. depth profiles in a surface or shallow-water well; Figure 2 is a graphical representation of pressure vs. depth profiles in a deep-water well drilled using single-gradient techniques; Figure 3 is a graphical representation of pressure vs. depth profiles for a deep-water well drilled using dual-gradient drilling techniques; and Figure 4 is a schematic representation of one embodiment of a drilling system constructed in accordance with the present invention.

DETAILED DESCRIPTION OF THE PREFERRED EMBODIMENTS In the description that follows, like parts are marked throughout the specification and drawings with the same reference numerals, respectively. The drawing figures are not necessarily to scale. Certain features of the invention may be shown exaggerated in scale or in somewhat schematic form and some details of conventional elements may not be shown in the interest of clarity and conciseness. The present invention is susceptible to embodiments of different forms. There are shown in the drawings, and herein will be described in detail,

specific embodiments of the present invention with the understanding that the present disclosure is to be considered an exemplification of the principles of the invention, and is not intended to limit the invention to that illustrated and described herein. It is to be fully recognized that the different teachings of the embodiments discussed below may be employed separately or in any suitable combination to produce the desired results.

In particular, various embodiments of the present invention provide a number of different methods and apparatus for drilling a subsea well using dual-gradient drilling. The concepts of the invention are discussed in the context of a drilling system employing composite coiled tubing in deep-water applications but the use of the concepts of the present invention is not limited to composite coiled tubing or deep-water drilling and may find application in wells at shallower water-depths and with any type of drill string that provides the desirable features.

In the context of the current description, an open wellbore should be taken to mean the uncased, exposed wellbore below the lowermost casing string. Returns refer to the fluid flowing towards the surface through the annulus between the drill string and the wellbore or riser wall. The returns generally include drilling fluid, cuttings, possibly formation fluids, and any other fluids injected into the annulus. Slimhole drilling includes those boreholes having a diameter of 6 1/2"or less, regardless of length of interval. Boreholes with a diameter between 6 1/2"and 8 1/2"may also be considered slimhole if they have a very long interval.

Referring now to Figure 4, a schematic representation of a subsea well 110 being drilled from a surface platform 120 is depicted. Subsea well 110 includes a wellhead 116 from which extends a cased wellbore portion 112 that leads to an uncased, open wellbore portion 114. Surface platform 120 supports drill string 130, pressure control equipment 140, telemetry equipment 150, injection equipment 160, and riser 170.

A bottom hole assembly (BHA) 132 is suspended from the end of drill string 130 and includes drill bit 134 and pressure sensor 136. Pressure sensor 136 is adapted to provide real- time pressure data from the bottom of well 110. This data can be relayed to telemetry equipment 150 located at surface platform 120. Pressure sensor 136 may preferably be a strain gage pressure transducer, such as series 211-36-760-04 as manufactured by Paine Electronics, or other type of downhole pressure transducer.

Drill string 130 is preferably a coiled tubing string capable of two-way communication by transmitting electric signals to and from surface platform 120 and BHA

132. Drill string 130 may also be constructed of any other acceptable tubular material capable of relaying signals between BHA 132 and surface platform 120. One exemplary coiled tubing string is a composite coiled tubing string with embedded electrical conductors, <BR> <BR> as disclosed in U. S. Patent 6,296, 066, titled"Well System, "and hereby incorporated herein by reference for all purposes. An exemplary telemetry system is disclosed in U. S. Patent 6,348, 876, hereby incorporated herein by reference. Any other telemetry system could be used including an MWD system or an electric-coil (E-coil) system.

Riser 170 forms the conduit between pressure control equipment 140 and wellhead 116 for the circulation of drilling fluids. Riser 170 preferably connects to wellhead 116 by way of a lower marine riser package (not shown). Riser 170 is a high-pressure riser capable of withstanding the full operating pressure of the well. The preferred riser 170 can have an inside diameter as small as 5 to 5 1/2", or smaller. The present invention is not limited to any particular diameter. However, a small diameter is preferred to reduce the annulus and thus the volume flow rate required for the injection fluid. The preferred drill string 130 is also relatively small diameter, such as a 3 1/8"tubing string or smaller.

A 5 to 5-1/2 inch riser provides a substantial reduction in cross-sectional area and volume compared to that of a conventional 18-3/4 inch low pressure riser. The quantity and flow rate of fluids required to decrease the density of the returns in a larger diameter riser would require very large pumping packages at the surface. A standard offshore drilling installation may not have available room to support this equipment. Therefore, the use of a small diameter riser is an important feature in being able to minimize the size of equipment required to support subsea fluid injection. For example, risers with inside diameters smaller than eight inches should have a sufficiently small annular area to allow the use of relatively compact pumping packages, separators, and other surface equipment. However, it should be appreciated that a small diameter riser requires the use of a even smaller diameter drilling system. It should also be appreciated that any size riser can be used as long as sufficient subsea fluid injection can be supported.

Riser 170 is equipped with a riser injection line 172 preferably extending from the surface to the bottom of the riser near the mud line 108. Injection line 172 leads from injection equipment 160 to riser 170. Injection line 172 does not have to enter the riser at the bottom of the riser and may enter the riser annulus 175 any where along the riser between mud line 108 and the surface 106. It is most efficient to have the injection point 176 as low as possible into riser 170.

Riser 170 may also have a pressure transducer 174 at mud line 108. If real-time pressure data from the bottom of the wellbore is unreliable or unavailable, it may also be desired to have a sensor 174 in the riser annulus 175 proximate to injection point 176 in order to measure the resulting reduction of hydrostatic pressure due to the injection of a gas into the riser 170 through injection line 172. Sensor 174 could also be used to determine the pressure at the bottom of the well by measuring the pressure at the mud line and calculating the pressure at the bottom of the well.

The desired dual-gradient drilling condition can be established by injecting a lower density fluid from injection equipment 160, through injection line 172 and into riser 170.

Check valves (not shown) are preferably on either end of injection line 172. Check valves operate as one way valves and allow fluid to flow in only one direction and do not require any positive action to actuate. A preferred fluid is an inert gas, such as nitrogen. Other gases and liquids, having densities less than the returns flowing through the riser annulus 175, may also be used. The injection fluid could be any fluid with a lighter density whether it be air, nitrogen or some other fluid. A gas is preferred because the injection fluid will need to be separated from the returns and particularly the drilling fluid, once it reaches the surface.

In order to change the single gradient drilling fluid to a dual gradient drilling fluid returning to the surface, an injector hose is attached at injection point 176 to riser annulus 175.

Nitrogen, or some other acceptable fluid, is bubbled into riser annulus 175 to reduce the overall density of the drilling fluid above the injection point 176. Thus, a heavier density drilling fluid may be used below injection point 176 and a lighter density drilling fluid above injection point 176. Alternative light-weight fluids may include water, oil, diesel, and other drilling fluid additives. Nitrogen, or some other inert gas, is a preferred fluid because of ease of separation at the surface and non-reactivity with hydrocarbons in the wellbore.

Injection equipment 160 is preferably located on surface platform 120 and requires a minimal amount of deck space. Preferable injection equipment 160 has a footprint of about 15 x 20 feet. The preferred nitrogen injection equipment employs a standard membrane unit rather than using bottled nitrogen. Injection equipment 160 is preferably able to pump gas at a pressure of 6,000 psi at a rate of 100 to 300 cubic feet per minute.

The pressure of the gas being injected into the riser annulus 175 is preferably equal to or slightly greater than the pressure in the riser annulus at the gas injection point 176. At a water depth of 10,000 feet, the nitrogen itself has an appreciable weight, i. e. density, of about 2.2 pounds per gallon. The pressure of the nitrogen at the injection equipment would be very close

to the pressure in riser annulus 175 at the gas injection point 176. The nitrogen pressure at the injection equipment 160 minus the friction pressure in the injection line, plus the hydrostatic head of the nitrogen would equal the pressure in the riser annulus 175 at the gas injection point 176.

Pressure control equipment 140 preferably includes a high-pressure stripper 142 and a flowline 144 having a choke 146. During operation, stripper 142 can be closed so as to maintain an elevated back-pressure on riser annulus 175. Drilling returns are removed from riser annulus 175 through flowline 144 and choke 146 to reduce their pressure. Once the injected nitrogen, or other injected fluid, is removed from the drilling fluid, the drilling fluid can be cleaned and recirculated through the well.

Although the embodiments of the present invention are described as being used to decrease the fluid density in the riser annulus, it may also in certain cases be desirable to decrease the annulus fluid density within the wellbore below the mudline. It is also considered that injection of fluids into the annulus could take place through a conduit disposed inside the riser or directly into the lower marine riser package and not actually through the wall of the riser.

An alternative embodiment may include disposing the pressure control equipment at the sea floor. A small subsea blowout preventer may be used, rather than a surface blowout preventer, with a low pressure, small diameter riser extending to the surface.

In the preferred embodiments, the pressure at the bottom of the well is continuously monitored. Upon detecting a variance in the bottom hole pressure, counteractive measures can be taken to adjust the wellbore pressure by changing the density of the returns in riser annulus 175 by either adding or reducing the quantity of nitrogen, or other light fluid, injected into the riser annulus. The wellbore pressure may also be adjusted by changing the density of the drilling fluid that is pumped into the well. This monitoring and adjusting may be done automatically through the use of software or manually by the operator. The preferred embodiments provide real-time, continuous monitoring of bottom hole pressure.

In order to maximize drilling efficiency and maintain control of the well, it is important to monitor the fluids being put into, and coming out of, the well. For example, the fluid pressure and the amount of fluid being injected into riser annulus 175 is monitored, preferably at injection system 160. The pumping of drilling fluid is monitored by the pumping equipment.

Further, the density and rate of the returns may also be monitored. Of course the bottom hole

pressure is also measured to ensure that the down hole pressure for drilling is being maintained between the pore pressure and the fracture pressure.

The density of the drilling fluid and the rate at which the drilling fluid is being pumped through the drill string is easily measured at the surface. The fluid injection rate into riser annulus 175 as well as the density and flow rate of the returns coming out of the well are also known or measured. Therefore, the mass flow rate through the well can be represented by: where QD and PD are, respectively, the flow rate and density of the drilling fluid entering the well, Qu and are, respectively, the flow rate and density of the injected fluid entering the riser, Vs and/3 are, respectively, the volume of the system and the average density of the contents <BR> <BR> of the system. , and QR and pR are, respectively, the flow rate and density of the mixture of drilling fluid and injected fluid exiting the well. When coiled tubing that is full of drilling fluid is run in to or pulled out of the well, or when new hole volume is added by drilling, the volume of the system changes. The rate of change of the system volume will immediately affect the volume flowrate of returns, and therefore the mass flowrate of returns, and is accounted for in <BR> <BR> the term Vs. When injected fluid flowrates or densities change, or when the fraction of<BR> dt volume occupied by drilled cuttings changes, the average density of the system contents may change. The rate of change of the average density of the system contents will affect the mass flowrate of returns, and is accounted for in the term. dt In slimhole drilling, close control of drilling fluid volume is critical because a small loss or gain of fluid volume translates into a great height of wellbore. As long as the mass flow rate of fluids into the well minus the the rate of change of mass within the system equals the mass flow rate of fluids exiting the well, the well is under control. If this balance is maintained, the well is under control because a balanced mass flow rate indicates that no drilling fluid is passing into the formation and no formation fluid is entering the wellbore. If mass flowrate out is greater than mass flowrate in minus the rate of change of mass within the system, then formation fluids are entering the well, i. e. a kick. If mass flowrate out is less than mass flowrate in minus the rate of change of mass within the system, then mud is being lost into the formation i. e. is being lost in the well. Monitoring the mass flow rates into and out of the well provides an alternative to the traditional liquid level monitoring techniques of the prior art.

Controlling the density of the drilling fluid in the drill string and the density of the combined drilling and injected fluids in the riser is critical to maintaining the desired conditions for dual-gradient drilling. If there is a pressure sensor available at the mud line 108, that sensor can be used to provide real-time feedback of the pressure at the mud line. This pressure data can be used as input data to a control system that varies the amount of fluid injected into the riser to keep the pressure at the mud line 108 within a desired range. Similarly, a pressure sensor at or near the bottom of the well and providing in real-time, pressure data to the surface can be used in the same manner to maintain the pressure at the bottom of the wellbore within a desired range.

The embodiments set forth herein are merely illustrative and do not limit the scope of the invention or the details therein. It will be appreciated that many other modifications and improvements to the disclosure herein may be made without departing from the scope of the invention or the inventive concepts herein disclosed. Because many varying and different embodiments may be made within the scope of the present inventive concept, including equivalent structures or materials hereafter thought of, and because many modifications may be made in the embodiments herein detailed in accordance with the descriptive requirements of the law, it is to be understood that the details herein are to be interpreted as illustrative and not in a limiting sense.