APPARATUS AND METHOD FOR SUBSEA WELL DRILLING AND CONTROL

Abstract

A subsea assembly suitable for subsea drilling and intervention operations includes a dual blowout preventer system having an upper blowout preventer located between a drill floor and a high pressure riser string, and a lower blowout preventer located below the riser string and above a wellhead. The dual blowout preventer system is adapted to enable advanced drilling and intervention operations such as managed pressure drilling, underbalanced drilling, dual gradient drilling, or through tubing rotary drilling, and slim hole drilling in an offshore deepwater environment.

Description

BACKGROUND

Priority

The present application claims the benefit of U.S. Non-Provisional Application Ser. No. 12/958,802, entitled “ASSEMBLY AND METHOD FOR SUBSEA WELL DRILLING AND INTERVENTION” filed Dec. 2, 2010 which claims priority to U.S. Provisional Patent Application Ser. No. 61/265,805, entitled “SUBSEA WELL DRILLING AND INTERVENTION METHOD AND APPARATUS,” filed on Dec. 2, 2009, naming Gavin Humphreys as inventor, both of which are hereby incorporated by reference in their entirety.

Field of the Invention

The invention relates to subsea equipment and assemblies of equipment used in offshore deepwater drilling, completion, production, and intervention operations and the location and recovery of hydrocarbons. In all such operations it is considered essential that the well operator maintains control of the well and its contents.

Background of the Invention

The search for recoverable hydrocarbons has been the subject of substantial commercial interest and activity for many years. Historically, drilling for and recovery of hydrocarbons has been limited by the technology available to operating and service companies who were actively looking for recoverable hydrocarbons on land or in relatively shallow water. As technology has improved, the geographic and temperate limitations typically associated with oil and gas exploration have gradually been reduced or removed altogether.

The expansion of hydrocarbon exploration to deepwater locations has presented severe obstacles to the oil and gas industry, obstacles that continue to be overcome by new technology. As oil and gas exploration goes into deeper and deeper water the problems associated with the safe, economical, and environmentally satisfactory operation of drilling, completion, production, and intervention operations have been compounded. In executing any of these operations it is critical that control of the well and its contents be maintained. There is a continuing need for solutions to the problems that are encountered in deepwater drilling, problems that are not typically encountered in land based drilling or in drilling in shallow water, which for purposes of this application is defined as 1000 feet of water depth or less. For the convenience of the reader, the following alphabetical chart is provided explaining the meaning of abbreviations used throughout this application:

API American Petroleum Institute

BOP Blowout preventer

DGD Dual gradient drilling

IADC International Association of Drilling Contractors

ID Inner diameter

LBOP Lower blowout preventer

LRP Lower riser package

MPD Managed pressure drilling

MW Megawatts

OD Outer diameter

PMCD Pressurized mud cap drilling

RCH Rotating control head

ROV Remotely operated vehicle

SG Specific gravity

TD Total depth/arrival at the desired well depth and location

TTRD Through tubing rotational drilling

UBD Underbalanced drilling

UBOP Upper blowout preventer

VBR Variable bore rams

One particular need has been the design and testing of the equipment necessary to connect the drilling vessel at the surface to the wellhead at the ocean floor. The pressures that such equipment must be designed to handle are enormous and the risks associated with the failure of such equipment are catastrophic. In virtually every deepwater subsea well at least one blowout preventer (sometimes referred to herein as a “BOP”) is installed at the ocean floor to seal the drill pipe or annulus during emergency situations, typically caused by hydrocarbons from formations being drilled, in which unanticipated hydrocarbons are not contained by the drilling or casing equipment. In some instances, two or more blowout preventers are stacked on one another at the wellhead location. It is important in the design of subsea drilling equipment that the equipment is designed to keep formation gases, which are rapidly expandable as well as flammable, out of the riser or the floating support structure.

As an alternative protective measure, some deep water drilling vessels have installed a blowout preventer at the surface to maintain well control but seldom have both a subsea BOP and surface BOP been installed together.

What is common to both systems is a Lower Riser Package (“LRP”) that is installed below the riser string and above the subsea BOP or LBOP that houses the termination of control umbilicals to the subsea devices and has a hydraulic activated connector that will enable the LRP to be disconnected in the event of an emergency.

However, what has not been addressed is the specific design of the equipment that connects two such blowout preventers, one at the ocean floor and one at the surface. This invention addresses and provides a solution to a long felt need for a subsea assembly that provides safety not only at the ocean floor and at the surface but also between those two points in deepwater operations.

What must be understood to truly appreciate this invention is the fact that normally what is called a marine riser is used to connect the ocean floor blowout preventer to the surface structure, whether the surface structure includes a second blowout preventer or not. Such a marine riser is not suitable to withstand the pressures associated with emergency situations such as experienced during a “pressure kick” or “pressure surge” if such pressures are not neutralized by one or both blowout preventers. In such situations the well operator loses control of the well and its contents. The apparatus and method of this invention provide improved control of the well and its contents during unanticipated pressure conditions.

One important advantage of the subsea assembly of this invention is the ability to activate shear rams in the subsea BOP to secure the well prior to disconnecting at the LRP in the event of an emergency. While such shear ram activation would only occur during extreme situations, it provides a measure of safety to the floating support structure and the individuals on such a structure and helps prevent the escape of flammable fluids into the floating support structure during emergency situations. The escape of such flammable fluids inevitably leads to fire and explosions.

Furthermore, it must be understood that under certain circumstances advanced drilling techniques are used in deep water drilling that may increase the risks associated with formation based pressures between the ocean floor and the surface. These advanced drilling techniques include managed pressure drilling, underbalanced drilling, through tube rotary drilling, and dual gradient drilling. The apparatus and methods associated with this invention enhance the ability to use such advanced drilling techniques without exposing the operators or environment to undue risks.

Description of the Related Art

Exploration for and recovery of hydrocarbons often requires the placement of drilling equipment in an offshore location. In shallow waters, the rigs and production facilities can be placed on freestanding offshore platforms. As the water becomes deeper, however, use of such platforms becomes impractical. As a result, floating structures, such as drill ships, must be used.

As the desire to drill at greater water depths increases (e.g., to at least 10,000 ft. water depth), floatable support structures have become larger due to the amount of pipe and other logistical support required to drill at such depths. In order to facilitate drilling in deep water locations, drill ships have been specifically designed to be self contained drilling structures that contain most, if not all, of the equipment necessary to carry out deep water drilling, completion, production, and intervention procedures. The dimensions of many such drill ships are such that they are difficult to navigate through canals and other confined locations. In addition, the physical size and vertical height of the drilling structure, such as a single drilling derrick, double drilling derrick with two drilling centers, hydraulic ram drilling structures, or other type of hoisting tower on the ship also limits the locations in which it can travel. For example, large drillships may not be able to travel through such waterways as the Suez or Panama Canals due to width and depth constraints of the canals, and likewise may not be able to travel under the bridge in the Bosphorous (mouth of the Black sea) due to the height of their drilling derricks or hoisting tower on the drillship. It is often necessary to travel around such waterways, which greatly increases the travel costs and time.

In addition, conventional deepwater rigs cannot efficiently perform some advanced drilling operations. For example, in recent years, Managed Pressure Drilling (“MPD”) and it's derivative, Underbalanced Drilling (“UBD”), Dual Gradient Drilling (“DGD”),and through tubing rotational drilling (“TTRD”) utilizing MPD or UBD have become increasingly more relevant to drilling wells that were previously deemed un-drillable or to drill wells where subsurface pore pressures and fracture gradients have converged requiring drilling with tailored drilling fluid weights supported by surface back pressure to drill through very tight pore pressure-fracture pressure windows.

As technically defined by the IADC, Managed pressure drilling is “an adaptive drilling process used to precisely control the annular pressure profile throughout the wellbore. The objectives are to ascertain the downhole pressure environment limits and to manage the annular hydraulic pressure profile accordingly.” In more conventional terms, MPD means that drillers maintain bottomhole pressure equal to or greater than the formation pore pressure by tailoring the density of drilling fluids and drilling with controlled back pressure between the seals of the RCH and the MPD choke manifold. When the bottom hole pressure gets too high, a portion of the drilling fluid can be lost to the formation, which damages the porosity of the formation (known as “skin”) as well as being a very expensive if loss of drilling fluid is substantial. The solution is that casing must be set to isolate the formation from the drilling fluid. This results in more strings of casing and more expense to the driller, all of which can be avoided by managing the pressure of the drilling fluid throughout the wellbore.

As opposed to MPD, UBD is a procedure used to drill oil and gas wells where the pressure in the wellbore is intentionally kept lower that the fluid pressure in the formation being drilled. This results in formation fluids flowing into the wellbore and up to the surface. Among the advantages of using UBD techniques are an increase in the rate of drilling penetration caused by less hold down pressure at the bottom of the wellbore. Another advantage is a reduction in the loss of drilling fluid into the formation creating “skin”, but by far the greatest advantage is the ability to characterize a reservoir while drilling by analyzing the formations and the fluids and production rates contained within them at surface.

Yet another advanced drilling technique that is facilitated by the apparatus of this invention is referred to as dual gradient drilling. The IADC defines DGD as “the creation of multiple pressure gradients within select sections of the annulus to manage the annular pressure profile. Methods include use of pumps, fluids of varying densities, or combinations of these.”

One of the real advantages associated with the use of the advanced drilling techniques disclosed herein is the ability to extend the length of drilling sections before casing is required. By extending drilling sections, fewer casing sizes are required and less downtime from drilling is required for casing and cementing operations.

An obvious spin-off of reducing the number of casings in a well design, where the subsurface geology and pressure regime would allow and where these drilling technologies would be applied, would be slim hole drilling where the well could be drilled and smaller casing set while maintaining the same size completion string that is currently in use.

As will become evident from the description of the apparatus and method of this invention that follows, a critical requirement of all of the advanced drilling techniques is that the driller or well operator maintain control of the wellbore and its contents at all times. Such control is not always possible with conventional drilling equipment and methods.

The conventional deepwater rigs that utilize a single subsea blowout preventer on the seabed which is tied back to the drillship with a relatively low pressure marine riser that is not designed to withstand closed in internal pressure (designed for flow only) lack the pressure integrity in the riser to routinely carry out either MPD nor UBD due to the marine risers' lack of internal pressure integrity (typically a 21¼ inch deep water marine riser has a burst pressure at the time of manufacture of approximately 5,000 psi, which cannot be field tested during the riser's life-time). Never the less, the burst pressure of a deepwater riser varies from top to bottom when in situ and is always subject to the drilling fluid weight in the hole and the tension applied to the riser at the top.

Limited MPD, presssurised mudcap drilling (PMCD) can be performed where a rotating control head is installed onto a collapsed telescopic joint but it remains costly due the time it takes to rig up and rig down the MPD equipment. New technology is emerging where the RCH and flow spools are integrated into the marine riser string.

Although some pressurized interventions are being done from rigs, they involve dedicated intervention risers (typically slim completion/production riser for intervention with electric or slick wire-line, Coil Tubing, or through tubing rotary drilling (“TTRD”)) generally with increased costs as they are provided by a third party contractor to compliment the conventional drilling BOP system.

In view of the foregoing, a need exists for highly mobile floatable structures capable of drilling in deepwater environments. It would be advantageous if the structures were smaller than conventional floatable structures and cost substantially less to build and operate. In addition, there is a need for a floatable structure capable of utilizing drilling technologies such as MPD, UBD, DGD, and TTRD in deepwater environments.

SUMMARY OF THE INVENTION

Floatable structures used in deepwater drilling and intervention are provided as embodiments of the present invention. The systems and methods described herein allow operators to safely perform MPD, UBD, DGD , TTRD and slim hole drilling in deep water applications. In an exemplary embodiment, the floatable structure includes a dual BOP system comprising an upper blow out preventer (“UBOP”) and a lower blow out preventer (“LBOP”) with a Lower Riser Package (LRP) to enable a disconnect of the riser system from the LBOP in the event of an emergency or bad weather. The UBOP is located between the drill floor of the floating support structure and above a high pressure riser string, while the LRP and LBOP are located below the high pressure riser string and above a wellhead. The high pressure riser utilizes a slim design with the same pressure rating as the UBOP and the LRP/LBOP combination.

The UBOP, LBOP, and high pressure riser combine to form a unique riser system that has the same high pressure integrity from top to bottom, essentially forming an extension of the wellbore to surface. In addition, because of the high pressure integrity of the riser almost all applications of MPD, UBD, TTRD and slim hole drilling (utilizing expandables as an option) allows wells being drilled using the technology of the present invention to be designed to effectively reduce the number of casing strings by using MPD or UBD drilling technology.

BRIEF DESCRIPTION OF THE DRAWINGS

FIG. 1 is a diagram of a dual BOP system made in accordance with an exemplary embodiment of the present invention; and

FIG. 2 is a diagram of a slim hole casing design when expandables may be run in accordance with an exemplary methodology of the present invention.

FIG. 3 is a side view of a section of high pressure riser used in the combination of this invention.

FIG. 4 is a cross section of the high pressure riser of this invention taken at line A-A of FIG. 3.

FIG. 5 is a cross section of the high pressure riser of this invention taken at line B-B of FIG. 3.

DESCRIPTION OF ILLUSTRATIVE EMBODIMENTS

Illustrative embodiments and methodologies of the invention are described below as they might be employed to allow users to perform advanced drilling and intervention operations in deep water environments. In the interest of clarity, not all features of an actual implementation or methodology are described in this specification. It will, of course, be appreciated that in the development of any such actual embodiment, numerous implementation-specific decisions must be made to achieve the developers' goals, such as compliance with system-related and business-related constraints, which will vary from one implementation to another. Moreover, it will be appreciated that such a development effort might be complex and time-consuming, but would nevertheless be a routine undertaking for those of ordinary skill in the art having the benefit of this disclosure. Further aspects and advantages of the various embodiments of the invention will become apparent from consideration of the following description and drawings.

Referring to FIG. 1, an exemplary embodiment of the present invention is illustrated. As shown in FIG. 1, a floatable structure includes a vessel (not shown), such as a drill ship, dual BOPs, and a high pressure riser system including a lower riser package coupled to and extending beneath the floor of the vessel. Dual BOP/high pressure riser system 5 comprises an upper blow out preventer 10 and a lower blow out preventer 20. A high pressure riser string 40 extends between the UBOP and the LBOP. As will be described in detail later, the drill ship may be a DrillSLIM™ or SLIMDRILL™ drill ship designed by Stena Drilling Ltd. of Scotland, U.K., which is the Assignee of the present invention.

In one preferred embodiment of this invention the subsea assembly includes an assembly 18, including rotating control head 19 connecting the floating support structure, the floor of which is shown as 35 in FIG. 1, to an UBOP 10, the UBOP 10 being operatively connected to a high pressure riser 40, and a lower riser package 80 connecting the high pressure riser 40 to the LBOP 20.

In one such preferred embodiment, the UBOP 10 is located below drill floor 35 and above high pressure riser string 40. LBOP 20 is located below high pressure riser string 40 and above a wellhead (not shown). A bag preventer (not shown) may also be located above UBOP 10. Extending below drill floor 35 is a diverter assembly 12 having a flex joint 14 coupled beneath it. Diverter assembly 12 may include, for example, 16 inch overboard lines to the port and starboard sides of the ship.

Flex joint 14 connects to slip joint assembly 16, which can be a triple barrel slip joint assembly having a 50 ft stroke. Assembly 18 is coupled beneath slip joint assembly 16 and includes a high pressure spacer joint with a load ring and Blafro flange, which is a flange designed to seal around the base of a high pressure riser that is extended through the rotary table where coil tubing BOPs are installed. This assembly, together with the high pressure riser 40, will enable coil tubing work to be performed in the well under high pressure conditions. As shown by FIG. 1, this exemplary embodiment includes a rotating control head (“RCH”) 19 in assembly 18, which is installed above the high pressure spacer joint to enable MPD and its derivative drilling techniques, DGD and UBD, to take place. In addition to MPD, DGD and UBD, other drilling techniques can be used with the present invention as will be apparent to those of skill in the art having the benefit of this disclosure.

A flexible line 21 is tied into an independent choke manifold 23, which may be located in the substructure of the drill ship or other floating support structure, to facilitate the application of MPD, DGD or UBD drilling technology, where continuous back-pressure is applied where applicable, and is totally independent from the main rig kill and choke lines.

Further referring to the exemplary embodiment of FIG. 1, UBOP 10 is coupled beneath assembly 18 and in one preferred embodiment includes at least three sets of rams, 25a, 25b, 25c, wherein at least two of the three sets of rams comprise variable bore rams (“VBR”) rated at 10K psi. In the alternative, rams 25a, 25b, and 25c include one 9⅝ inch casing ram (if the invention is used for slim hole drilling) and two 2⅞-5.5 inch VBR. In the most preferred embodiment of this invention one of rams 25a, 25b, or 25c may be a blind shear ram, but this is not necessarily mandatory, but subject to the user's intent and needs. UBOP 10 can also include, for example, a 13⅝ inch annular preventer rated at 5K psi. Upper stress joint 22 is coupled beneath UBOP 10 and connects to high pressure riser string 40, and may be a 13⅝ inch triple barreled telescopic joint with up to a 50 ft stroke. UBOP 10 also includes a choke/kill manifold with inlets from below the rotating elements of the RCH 19 and an independent choke manifold with self-adjusting chokes for MPD, DGD, TTRD, and UBD operations.

A rotating control device or rotating control head (“RCH”) 19 is a drill through device with a rotating seal that contacts and seals against the drill string for the purpose of controlling the pressure or fluid flow to the surface. Typically, the RCH 19 is a low pressure sealing device used in drilling operations utilizing any drilling fluid whose hydrostatic pressure is less than the formation pressure, to seal around the drill stem above the top of the BOP stack, in this case above the UBOP. An internal sealing element seals around the outside diameter of a tubular and rotates with the tubular. The tubular may be stripped through the RCH 19 while the tubular rotates or when the tubular, such as a drill string, casing, or coil tubing is not rotating. The internal seal may be passive or active. RCHs 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. In the invention of this disclosure, it is important that the RCH 19 be installed on top of the UBOP to ensure containment and control of drilling fluids by applying back-pressure while drilling.

A drilling riser is typically defined as a conduit that provides a temporary extension of a subsea hydrocarbon well to a surface drilling facility. Drilling risers are categorized into two types: marine drilling risers used with subsea blowout preventers and generally used by floating vessels; and tie-back drilling risers used with surface blowout preventers and are generally deployed from fixed platforms or very stable floating platforms such as a spar or tension leg platform. The assembly of this invention is unique in that it utilizes both an UBOP and a LBOP with an interconnecting high pressure riser to facilitate advanced drilling techniques as described herein.

High pressure riser string 40, as illustrated by FIGS. 3-5, may be a 13⅝ inch inner diameter (“ID”), high pressure 10K riser, having kill and choke lines from the seabed to the surface. Conventional drilling marine risers (generally utilized with a subsea BOP on the seabed) are designed to control drilling fluid flow and have sufficient burst pressure strength at the seabed to hold the pressure differential between the heaviest drilling mud inside the riser against seawater pressure outside the riser. A high pressure riser can also withstand these physical properties, but it can also be sealed up at the top of the riser and be subjected to up to 10,000 psi additional pressure in the event that an activity may require the riser to be pressured. High pressure riser string 40 may also include a design that includes a 10,000 psi burst rating, and also be able to comply with stringent dimensional requirements for handling and storage on the deck of the drill ship to keep the ship size to a minimum The subsea assembly of this invention, including the high pressure riser and the UBOP and LBOP are designed to maintain pressure integrity in the system, even during emergency situations. It is clearly preferred to keep formation gases out of the riser system altogether, however, if such gases bypass the LBOP and get into the high pressure riser of this invention, pressure integrity of the subsea assembly can be maintained while the gases are bled off before causing damage or explosions to the floating support structure.

Referring to FIG. 3 a section of a high pressure riser 40 that could be used in the assembly of this invention is shown. Due to the weight of the riser column in deep water drilling operations, which is substantially greater than a typical marine riser, a series of buoyancy modules 64 are used on the riser string 40 to reduce the absolute weight of the riser column, which must be hung off the floating support structure.

Referring now to FIGS. 4 and 5, the cross sectional details of the high pressure riser can be more readily understood. The riser itself is identified by reference number 61 and typically would be made of steel at a thickness of 1.25 inches. A typical marine riser would have a wall thickness of less than 1.00 inch and would not be rated to withstand the pressures necessary for deep water drilling using the advanced drilling techniques described above, namely, UBD, DGD, MPD, and other drilling techniques that involve potential pressure kicks from formation hydrocarbons. A series of hydraulic lines 62 and drilling fluid boost lines 63 are found outside of the riser 61 but within buoyancy modules 64 to transfer fluids along the length of the riser column.

By way of example, the high pressure riser 40 can be approximately 7,500 ft of 13⅝ inch ID×10K (120 joints) with two choke/kill lines which would allow for high pressure pumping outside riser string 40. The joints can be 65 ft long with high strength connectors, weigh +/−21T (dry), and have a 45 inch outer diameter (“OD”) with buoyancy. High pressure riser string 40 is kept in tension by a substructure mounted tensioner system, rated to 2.4 million lbs with 14.0 ppg (1.68 specific gravity (SG)) fluid inside the riser.

The high pressure riser system also has 10,000 psi kill and choke line (generally associated with subsea BOP control systems) to facilitate conventional seabed well control techniques or to monitor and control pressures below a sealed LBOP if the riser system is used as a lubricator while using MPD or UBD drilling technologies.

In further reference to the exemplary embodiment of FIG. 1, a lower riser package 80 is provided, the lower riser package 80 is designed to disengage the riser from the LBOP during emergency disconnect situations, and includes pods 81 for housing the hydraulics for actuating the disconnect apparatus, a connector 82, and a Mux cable 83. The Mux cable is well known to persons of ordinary skill in the art and commercially available from a number of well known vendors. In its broadest form, the Mux line provides and houses the hydraulic fluids and control signals necessary to operate the lower riser package during emergency situations. The Mux line is connected to the floating support structure and is typically attached to the exterior of the riser string.

LBOP 20 includes at least three sets of rams 30a, 30b, 30c, which can include, for example, one pipe ram to hang-off the drill pipe and two blind shear rams with fail safe closed connections to monitor pressure build up in the event the well is closed in on the blind rams. LBOP also includes an emergency disconnect and a wellhead connector. In the alternative, LBOP 20 may be comprised of super shear blind/shear rams in order to shear and seal on the 9⅝ inch casing and heavier drill pipe. LBOP 20 and the lower riser package 80 enable the well to be closed in at seabed level, and the high pressure riser string 40 to be disconnected.

In this exemplary embodiment, LBOP 20 and the lower riser package 80 are controlled by a multiplex system with acoustic backup including: duplicate umbilical control reels for approximately 7500 ft water depth and a modular emergency subsea accumulator pack (set on seabed) that is connected using a remotely operated vehicle (ROV). UBOP 10 can be controlled by a pilot hydraulic control system. The controls for both UBOP 10 and LBOP 20 can be adjacent to each other on the same panels. The hydraulic disconnect package or lower riser package 80 can include an inverted connector with acoustic control back up. Those ordinarily skilled in the art having the benefit of this disclosure realize these and a variety of other components may be utilized within the lower riser package 80 of the present invention.

Accordingly, through the use of LBOP 20, high pressure riser string 40, UBOP 10, and an RCH 19 designed into the riser system, the present invention provides the ability to utilize MPD, DGD, TTRD, and UBD in deepwater offshore applications. High pressure riser string 40 and UBOP 10 act as an extension of the wellbore for drilling operations facilitating MPD and UBD operations. As such, the riser system between UBOP 10 and LBOP 20 holds the same pressure as UBOP 10 and LBOP 20, thereby creating a deepwater drilling BOP and riser system that has the same high pressure integrity from top to bottom. Similarly, high pressure riser string 40 can act as a very long lubricator for pressurized well interventions by also using LBOP 20 and UBOP 10 together with an RCH for MPD, UBD, DGD and TTRD well intervention applications.

Referring to the exemplary embodiment of FIG. 2, the present invention provides the ability to drill a slimmed down well design where an expandable liner may be used as a contingency. The concept of DrillSLIM™ drilling technology has been developed to make the drilling of a well more efficient, and therefore less expensive. In its most basic form, drilling slim wellbores involves the use of the advanced drilling techniques disclosed in this application in order to extend the length of each sequential string of casing from what is considered the norm in deepwater well drilling. By using fewer casing strings, the telescopic cross section of a cased wellbore, as shown in FIG. 2, is minimized so that the desired casing size is maintained at TD or the production zone, but the number of increasingly large case strings necessary to arrive at TD is reduced, thereby saving time and expense.

Another form of a DrillSLIM™ wellbore drilling is generically described as an “expandable.” Again, in its most fundamental form, expandable technology involves inserting a relatively small diameter casing string into a wellbore, inserting a smaller diameter casing string through the first casing string and into the wellbore, and then using a swedge or other mechanical means to physically expand the smaller diameter casing to the same diameter as the casing string immediately above. The use of expandable technology in its most advanced form can result in the drilling of a deepwater well that is essentially a uniform diameter from the wellhead to the production zone.

An exemplary method of the present invention will now be described. Expandable liners, as understood in the art, are utilized in this exemplary methodology. The well of FIG. 2 is located at a water depth of approximately 7,500 ft, having a total depth (“TD”) of approximately 22,500 ft. Surface casing 42 and intermediate casing 44 are run and cemented prior to running the 13⅝ inch×10,000 psi dual BOP/high pressure riser system 5. Generally, intermediate casing 44 will be one API size smaller than the typical casing run before the placing of a BOP in a conventional well design. For example, intermediate casing 44 may be a 13⅜ inch casing string, while such casing would typically be a 20 inch casing string in a conventional well design.

After setting surface casing 42 and intermediate casing 44 (13⅜ inch), dual BOP/high pressure riser system 5 is run. Thereafter, the next hole section is drilled with a 12¼″ bit to section TD. In the event this TD cannot be achieved through some subsurface issues, then the 12¼″ hole section will be opened with a bi-centered bit or under-reamed to 16 inches/17½ inches. Then, solid expandable liner 48 is run and expanded to seal at the junction of shoe 46. In this exemplary embodiment, expandable liner 48 is an 11¾ inch OD solid expandable liner that when expanded has the same drift diameter as the previously set 13⅜ inch casing. This now makes the casing shoe depth of the present invention equivalent to that of a conventional casing design. Those skilled in the art having the benefit of this disclosure realize that in wells that only require four casing/liner strings to get to TD, or have a TD liner smaller than 7 inches, the use of expandable liner may not be necessary. Additionally, those same skilled persons realize other casing/liner types may be utilized with the present invention. Once expandable liner 48 is set, then all further drilling activity will be performed as understood in the art.

Further referring to the exemplary methodology of FIG. 2, in order to secure the 12¼ inch drift for expanded casing/liner, the expansion system and method must be taken into account to determine the necessary surface casing size, as would be understood by one skilled in the art having the benefit of this disclosure. The well can then be drilled with a 12¼ inch bit for a 9⅝ inch casing string 50 or a 9⅝ inch liner string (subject to well design criteria) at approximately 17,500 ft, for example, and finished using a 8½ inch hole and 7 inch production liner 52 at approximately 22,500 ft, for example. The sizes and methods used herein are exemplary in nature as would be understood by one skilled in the art having the benefit of this disclosure. For example, the systems and methods described herein can be used in water depths less than or greater than approximately 7,500 ft. Accordingly, the present invention allows the well to be designed to effectively reduce the number of casing strings by using MPD, DGD, TTRD or UBD drilling technology to continually monitor subsurface pore pressures and set casing in the appropriate subsurface pressure regime.

The drill ship or drilling semi-submersible with identical drilling technology functionality utilized with the present invention will now be described. The drill ship may include various types of equipment useful in deep water drilling. As previously stated, an exemplary drill ship is the 145-8×29-31 m DrillSLIM™. Use of DrillSLIM™, or similar designs, allows efficient movement around the world by the most direct routes (e.g., through the Suez and Panama Canals and under the Bosporus Bridge), which substantially reduces transit times and costs. The ship's hoisting tower arrangement mounted to a deck of the drill ship is specifically designed to telescope inward to ensure when collapsed the top of the hoist sheaves can pass under the bridges on the Panama and Suez canals and under the Bosphorous bridge into the Black Sea while the drill ship is in transit draft. The hoisting tower would include sufficient racking capacity for a full drill string for water depths of at least about approximately 7,500 ft. As an example using approximately 7,500 ft water depth as a basis, the heaviest load of 355 tons (T) occurs when the approximately 7,500 ft of riser, two sets of BOP's, ancillary and travelling equipment are run. A 500 ton hoist rating can be used to allow some margin of safety. The hoisting tower would further include hoisting capacity to hoist double drill pipe joints for use in drilling wells in water depths of at least approximately 7,500 ft; a hoisting capacity to hoist casing for use in drilling wells in water depths of at least approximately 7,500 ft; or combinations thereof.

In addition, the drill ship can also include active pit tank capacity to fully displace a largest hole volume over to another mud or brine system for use in drilling wells in water depths of at least approximately 7,500 ft; full mud treatment and cuttings containment, with the ability to mix new mud and brine simultaneously, for use in drilling wells in water depths of at least approximately 7,500 ft; liquid and dry bulk storage for use in drilling wells in water depths of at least approximately 7,500 ft; deck space and services for electric and slick line, cementing, well testing, well simulation, coiled tubing, MPD/UBD operations, drill cutting operations, or combinations thereof for use in drilling wells in water depths of at least approximately 7,500 ft; or combinations thereof. The floatable structure may further include various combinations of the types of equipment described herein.

For example, the active pit system can be 6,460 bbls (1027 m³) plus five treatment tanks of 60 bbls (9.5 m³) each. The active pits can be split in half for two independent mud/brine systems with two independent automated mud/brine mixing facilities for concurrent operations. Liquid storage can include 9,749 bbls (1,550 m³) of drill water, 2,139 bbls (340 m³) of base oil, and 1,572 bbls (250 m³) of brine. Three conventional triplex pumps with approximately 7,500 psi fluid ends can provide for all downhole pumping operations. Solids control can be provided by four linear motion shale shakers, a desander, a desilter, a degasser, and space for two contractor supplied centrifuges. Solids disposal can be via one double self cleaning screw conveyor feeding into a big bag turntable station. Dry bulk storage can include six×60 m³ tanks, (one bentonite, three barite and two cement) with three×6 m³ surge tanks. The cement unit can be contractor supplied and also provide pressure testing and emergency pumping services. Those ordinarily skilled in the art having the benefit of this disclosure realize other types of equipment can be used with the present invention, such as those used in controlling mud and solids, as well as cement systems.

The exemplary drill ship may further include hoisting and handling equipment. A single hoisting tower with a ram type hoist having a clear working height of 120 ft for drilling, along with a top drive and double joints of range two drill pipe, can be included. Dead line compensation can be included for drill string motion compensation. The hoisting tower can further include a hydraulic racking system with setback for 22,500 ft of 5 inch drill pipe and drill collars. A remote operated iron roughneck can be provided on the drill floor 35 for tubular make-up and break-out. A skidding and trolley system below the substructure can be provided for handling and storing the two×13⅝ inch BOP stacks and up to two subsea Xmas trees. Additionally, at moon pool level, there can be a retractable dummy riser spider trolley to hang off the BOP while the load ring and telescopic joints are installed.

The exemplary drill ship described herein can further include three hydraulic knuckle boom cranes: a compensated crane rated to 120 T in port/60 T offshore for handling BOP equipment, Xmas trees, and for construction activities; a 20 T rated crane to serve the aft deck and mud treatment deckhouse; and a 25 T rated crane for loading tubulars from the quay to the riser racks. The systems and methods described herein can also include two horizontal catwalks, one forward for riser transport and one aft for drill pipe/casing both at drill floor 35 elevation. One gantry crane can be installed on the riser storage area and one gantry crane over the aft pipe storage area. A tubular handling overhead crane and a vertical pipe elevator can be installed in the pipe hold in the hull. Other types of hoisting and handling equipment that can be used in the present invention will be apparent to those of skill in the art having the benefit of this disclosure.

The exemplary drill ship described herein will also include rotating equipment. For example, rotating the drill string can be a 500 tons AC motor driven top drive. A conventional 49½ inch rotary table can be fitted for tubular support and can be driven by a hydraulic motor for limited rotational capability. Other suitable types of rotating equipment will be apparent to those of skill in the art having the benefit of this disclosure.

The exemplary drill ship described herein further includes drilling tools. In an aspect, for example, approximately 22,500 ft each of 5 inch and 3½ inch high grade drill pipe, and ten each of 8 inch, 6½ inch and 4¾ inch drill collars, all with handling and fishing tools can be included. The types and amounts of drilling tools included will vary depending upon the needs of each system as will be apparent to those of skill in the art having the benefit of this disclosure.

The exemplary drill ship also includes utility systems. The electrical power system can include variable speed AC drives for the mud pumps and top drive, with a normal drilling load of 3.0 Megawatts (MW). The hoisting system can be hydraulically powered through a central HPU. The types and amounts of utility systems included in embodiments of the present invention will vary depending upon the needs of each system as will be apparent to those of skill in the art having the benefit of this disclosure.

The exemplary drill ship can be powered by six 4.7 MW main diesel electric alternator sets with propulsion from five fixed pitch, variable speed thrusters with a combined power of 17.3 MW. The thrusters can be configured for independent and integrated operation with the dynamically positioned vessel to IMO class 3. All systems can be designed and installed to ensure that adequate redundancy is maintained and that no single failure will result in loss of positional keeping or operational performance.

The exemplary drill ship can also have an endurance of sixty days (typically thirty days transit and thirty days dynamically positioned), and operations can be designed to be carried out without assistance from other vessels. The ship's service speed can be around fourteen knots. The heli-deck can be rated for S61, S92, EC225 & Super Puma helicopters. One 25 m burner boom can be mounted on the port stern for flaring operations.

Using embodiments of the present invention, smaller riser strings are used and less casing strings are necessary. As a result, smaller drill ships can be used, in less hostile geological and pore pressure regime environments where less casing is required, thereby cutting conventional operating costs in half and reducing well costs by half. Conventional dual activity drill ships have four drill crews (two well centers), while the drill ships constructed and used in accordance with embodiments of the present invention are expected to have only two drill crews (one well centre). The crew rate will be +/−70% of that of the larger drill ships. Furthermore, the all up day spread rate (including services and fuel) for the large drill ship are expected to be in the region of $750-$800,000/day, while the expectation for use of the systems and methods described herein is expected to be one-half to two-thirds that spread rate.

In addition, well intervention workovers into an existing subsea well to move the “drainage point” in the reservoir using TTRD technology to increase reserves base also becomes viable as the dual BOP/riser system 5 will enable an RCH to be installed at surface to facilitate MPD drilling technology, which is relevant when reservoir pore pressures are in decline causing convergences of the pore pressure-fracture gradient window. Without the high pressure riser of the present invention, this cannot be achieved using conventional subsea stack-marine riser systems.

An exemplary embodiment of the current invention provides a subsea assembly for use in the recovery of hydrocarbons located beneath the surface of a body of water, the assembly comprising an upper blow out preventer (UBOP) located beneath a vessel floor; a high pressure riser string located beneath the UBOP and a lower blow out preventer (LBOP) located beneath the riser string and operatively coupled to a wellhead. In an embodiment, the high pressure riser string has a pressure rating that is the same as a pressure rating of the UBOP and LBOP. In another embodiment, the pressure rating of the UBOP, riser string and LBOP is at least 10,000 psi. In the alternative, the assembly is adapted to perform at least one of a managed pressure drilling, underbalanced drilling, dual gradient drilling or through tubing rotary drilling operation. In a yet further embodiment, the riser string is sized for running casing having an API size less than or equal to 13⅜″. In some embodiments, the assembly further includes a rotating control head. The vessel may also be adapted to drill wells in water depths of at least 7,500 ft.

An exemplary embodiment of the present invention provides a subsea assembly for use in subsea operations, the assembly comprising a slip joint assembly located beneath a vessel floor; a rotating control head located beneath the slip joint assembly; an upper blow out preventer located beneath the rotating control head; an upper stress joint located beneath the UBOP; a high pressure riser string located beneath the upper stress joint; a lower stress joint located beneath the high pressure riser string; a lower blow out preventer located beneath the lower stress joint; and a wellhead located beneath the LBOP such that the burst strength of the UBOP, the high pressure riser string and the LBOP provide a uniform pressure containment ability from the top to the bottom of said subsea assembly. In another embodiment, the riser string has a pressure rating that is the same as a pressure rating of the UBOP and LBOP. In yet another embodiment, the assembly is used in an offshore deepwater environment. In the alternative, the assembly is adapted to perform at least one of a managed pressure drilling, underbalanced drilling, dual gradient drilling or through tubing rotary drilling operation. In yet another embodiment, the riser string is sized for running casing having an API size less than or equal to 13⅜″. The vessel may also have a length of no more than 148 meters and a width of no more than 28 meters. In yet another embodiment, the vessel is adapted to drill wells in water depths of at least 7,500 ft.

An exemplary subsea assembly, of the current invention, for use in the exploration for and recovery of hydrocarbons located beneath the surface of a body of water, connects a support structure to a deepwater subsea wellhead while the assembly is specifically configured to support DGD and UBD and related completion and production operations. In an embodiment, such a subsea assembly has an upper assembly, adjacent the floating structure, that includes a slip joint assembly, a rotating control head assembly; and an UBOP with a plurality of rams, a high pressure riser assembly connecting the UBOP to LBOP that is configured to permit DGD and UBD and a lower assembly having a LBOP with a plurality of rams, at least one of which is a shear ram and a wellhead, wherein the UBOP, the LBOP, and the high pressure riser assembly provide uniform burst strength characteristics to said subsea assembly from the upper assembly through and including the lower assembly. In another embodiment, the rotating control head includes a high pressure spacer joint, a load ring and a flange assembly. In yet a further embodiment, the upper assembly can additionally include a diverter assembly, a flex joint and a slip joint assembly.

An exemplary methodology of the present invention provides a method for use in a subsea operation, the method comprising the steps of (a) providing a slip joint assembly located beneath a vessel floor; (b) providing a rotating control head located beneath the slip joint assembly; (c) providing an upper blow out preventer (“UBOP”) located beneath the rotating control head; (d) providing an upper stress joint located beneath the UBOP; (e) providing a high pressure riser string located beneath the upper stress joint; (f) providing a lower stress joint located beneath the riser string; (g) a lower blow out preventer (“LBOP”) located beneath the lower stress joint; and (f) providing a wellhead located beneath the LBOP such that the burst strength of the UBOP, the high pressure riser string and the LBOP provide a uniform pressure containment ability from the top to the bottom of said subsea assembly.

In another methodology, step (e) further comprises the step of providing the riser string with a pressure rating that is the same as a pressure rating of the UBOP and LBOP. In yet another methodology, the method further comprises the step of performing the subsea operation in an offshore deepwater environment. In another methodology, the method further comprises the step of performing at least one of a managed pressure drilling, dual gradient drilling, underbalanced drilling, or through tubing rotary drilling operation. In another methodology, the method further comprises the step of tripping a liner having an API size less than or equal to 13⅜″ through the riser string. In yet another, the method further comprises the step of providing the vessel with a length of no more than 148 meters and a width of no more than 28 meters

Another exemplary embodiment of the present invention provides a subsea assembly for use in subsea operations, the assembly comprising an upper blow out preventer (“UBOP”) located beneath a vessel floor; a riser string located beneath the UBOP; and a lower blow out preventer (“LBOP”) located beneath the riser string and operatively coupled to a wellhead. In another embodiment, the riser string has a pressure rating that is the same as a pressure rating of the UBOP and LBOP. In yet another embodiment, a pressure rating of the UBOP, riser string, and LBOP is at least 10,000 psi. In another embodiment, the assembly is used in an offshore deepwater environment. In yet another embodiment, the assembly is adapted to perform at least one of a managed pressure drilling, underbalanced drilling, or through tubing rotary drilling operation. In yet another embodiment, the riser string is sized for running casing having an API size less than or equal to 13⅜″. An exemplary embodiment may also comprise a rotating control head. In another embodiment, the vessel has a length of no more than 148 meters and a width of no more than 28 meters. In yet another embodiment, the vessel is adapted to drill wells in water depths of at least 7,500 ft.

Another exemplary methodology of the present invention provides a method for use in subsea operations, the method comprising the steps of (a) providing a vessel having a floor; (b) providing an upper blow out preventer (“UBOP”) located beneath the floor; (c) providing a high pressure riser string located beneath the UBOP; (d) providing a lower blow out preventer (“LBOP”) located beneath the riser assembly; and (e) connecting the LBOP to a wellhead beneath the LBOP. In another methodology, the method further comprises the step of providing the riser string with a pressure rating that is the same as a pressure rating of the UBOP and LBOP. In yet another, the method further comprises the step of providing the UBOP, riser string, and LBOP with a pressure rating of at least 10,000 psi. In another methodology, the method further comprises the step of performing the subsea operations in an offshore deepwater environment. In yet another, the method further comprises the step of performing at least one of a managed pressure drilling, underbalanced drilling, dual gradient drilling, or through tubing rotary drilling operation. In another methodology, the method further comprises the step of tripping liner down the riser string, the liner having an API size less than or equal to 13⅜″. In yet another methodology, the method further comprises the step of locating a rotating control head beneath the UBOP. In another exemplary methodology, step (a) further comprises the step of providing the vessel with dimensions of no more than 148 meters in length and no more than 28 meters in width. In yet another, the method further comprises the step of drilling a well at a water depth of at least 7,500 ft.

All of the embodiments and methodologies of the present invention disclosed and claimed herein can be made and executed without undue experimentation in light of the present disclosure. While the invention is susceptible to various modifications and alternative forms, specific embodiments have been shown by way of example in the drawings and have been described in detail herein. However, it should be understood that the invention is not intended to be limited to the particular forms disclosed. For example, it will be apparent that certain components that are useful in drilling can be substituted for the components described herein, or additional components can be used to drill the deep water wells, while achieving the same or similar results. Accordingly, the intention is to cover all modifications, equivalents and alternatives falling within the spirit and scope of the invention as defined by the appended claims.

Claims

1. A subsea assembly for use in the recovery of hydrocarbons located beneath the surface of a body of water, said subsea assembly connecting a floating support structure to a deepwater subsea wellhead, said subsea assembly comprising:

(a) a rotating control head assembly functionally connected to said floating support structure;

(b) an upper blow out preventer located beneath and functionally connected to said rotating control head assembly;

(c) a high pressure riser string located beneath and functionally connected to said upper blowout preventer said high speed riser string providing pressure integrity to said subsea assembly;

(d) a lower riser package located beneath and functionally connected to said high pressure riser string; and

(e) a lower blowout preventer located beneath said lower riser package, said lower blowout preventer being functionally coupled to a wellhead.

2. An assembly as defined in claim 1, wherein the high pressure riser string has a pressure rating that is the same as a pressure rating of the upper blowout protector and the lower blowout preventer.

3. An assembly as defined in claim 2 wherein a pressure rating of the upper blowout preventer, the high pressure riser string, and the lower blowout preventer is at least 10,000 psi.

4. An assembly as defined in claim 1, wherein the subsea assembly is adapted to perform at least one of a managed pressure drilling, underbalanced drilling, dual gradient drilling or through tubing rotary drilling using said rotating control head assembly

5. An assembly as defined in claim 1, wherein the high pressure riser string is sized for running casing having an API size less than or equal to 13⅜″.

6. An assembly as defined in claim 1, wherein said floating support structure is adapted to drill wells in water depths of at least 7,500 ft.

7. A subsea assembly for use in the recovery of hydrocarbons located beneath the surface of a body of water, said subsea assembly connecting a floating support structure to a deep water subsea wellhead, said subsea assembly comprising:

(a) a slip joint assembly located beneath and functionally connected to said floating support structure;

(b) a rotating head assembly being functionally connected to said slip joint assembly;

(c) an upper blowout preventer located beneath said rotating control head assembly;

(d) a high pressure riser string located beneath and functionally connected to said upper stress joint;

(e) a lower riser package located beneath and functionally connected to said high pressure riser string;

(f) a lower blowout preventer located beneath and functionally connected to said lower riser package joint; and

(g) a wellhead located beneath the lower blowout preventer;

wherein the pressure rating of said upper blowout preventer, said high pressure riser string, and said lower blowout preventer provide a uniform pressure containment ability from the top to the bottom of said subsea assembly.

8. An assembly as defined in claim 7, wherein said high pressure riser string has a pressure rating that is the same as a pressure rating of said upper blowout preventer and said lower blowout preventer.

9. An assembly as defined in claim 7, wherein the assembly is adapted to perform at least one of a managed pressure drilling, underbalanced drilling, dual gradient drilling or through tubing rotary drilling operation using said rotating control head assembly.

10. An assembly as defined in claim 7, wherein the riser string is sized for running casing having an API size less than or equal to 13⅜″.

11. An assembly as defined in claim 7, wherein the vessel is adapted to drill wells in water depths of at least 7,500 ft.

12. A subsea assembly for use in the exploration for and recovery of hydrocarbons located beneath the surface of a body of water, said subsea assembly connecting a floating support structure to a deepwater subsea wellhead, said assembly being specifically configured to support dual gradient drilling and underbalanced drilling and related completion and production operations, said subsea assembly comprising:

(a) an upper assembly located adjacent to and functionally connected to said floating structure, said upper assembly including: (i) a slip joint assembly; (ii) a rotating control head assembly; and (iii) an upper blowout preventer, said upper blowout preventer including a plurality of rams;

(b) a high pressure riser assembly connecting said upper blowout preventer to a lower riser package, said high pressure riser assembly being configured to permit dual gradient drilling and underbalanced drilling operations and wherein the pressure rating of said high pressure riser assembly is substantially the same as the pressure rating of said upper blowout preventer;

(c) a lower riser package functionally connecting to said high pressure riser assembly to a lower blowout preventer, said lower riser package comprising apparatus for disconnecting said high pressure riser assembly from said lower blowout preventer when an emergency disconnect is required; and

(d) a lower blowout preventer functionally connected to said lower riser package;

wherein said upper blowout preventer, said lower blowout preventer, and said high pressure riser assembly provide uniform pressure rating characteristics of at least 10,000 psi to said subsea assembly from the upper assembly through and including said lower assembly.

13. The subsea assembly of claim 12 wherein said rotating control head assembly includes:

(a) a rotating control head;

(b) a high pressure spacer joint;

(c) a load ring, and

(d) a flange assembly.

14. The subsea assembly of claim 12 wherein said upper assembly includes:

(a) a diverter assembly,

(b) a flex joint, and

(c) a slip joint assembly.

15. A method for use in a subsea operation, the method comprising the steps of:

(a) providing a slip joint assembly located beneath a vessel floor;

(b) providing a rotating control head located beneath the slip joint assembly;

(c) providing an upper blowout preventer located beneath the rotating control head;

(d) providing an upper stress joint located beneath the upper blowout preventer;

(e) providing a high pressure riser string located beneath the upper stress joint;

(f) providing a lower stress joint located beneath the riser string;

(g) a lower blowout preventer located beneath the lower stress joint; and

(h) providing a wellhead located beneath the lower blowout preventer; wherein the pressure rating of said upper blowout preventer, said high pressure riser string, and said lower blowout preventer provide a uniform pressure containment ability from the top to the bottom of said subsea assembly.

16. A method as defined in claim 15, wherein step (e) further comprises the step of providing the high pressure riser string with a pressure rating that is the same as a pressure rating of said upper blowout preventer and said lower blowout preventer.

17. A method as defined in claim 15, further comprising the step of performing at least one of a managed pressure drilling, underbalanced drilling, dual gradient drilling or through tubing rotary drilling using said rotating control head assembly.

18. A method as defined in claim 15, further comprising the step of tripping a liner having an API size less than or equal to 13⅜″ through the riser string.