STATEMENT REGARDING FEDERALLY SPONSORED RESEARCH OR DEVELOPMENT
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. FIG. 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 FIG. 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 FIG. 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.
FIG. 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 FIG. 3, the objective of dual-gradient drilling is to shift the drilling fluid pressure gradients from the profiles shown in FIG. 2 to dual gradient profiles as shown in FIG. 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 FIG. 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.