The present invention relates generally to marine riser systems and, in an embodiment described herein, more particularly provides an offshore universal riser system.
Risers are used in offshore drilling applications to provide a means of returning the drilling fluid and any additional solids and/or fluids from a borehole back to surface. Riser sections are sturdily built as they have to withstand significant loads imposed by weights they have to carry and environmental loads they have to withstand when in operation. As such, they have an inherent internal pressure capacity.
However, this capacity is not currently exploited to the maximum extent possible. Many riser systems have been proposed to vary the density of fluid in the riser but none have provided a universally applicable and easily deliverable system for varying types of drilling modes. They typically require some specific modification of the main components of a floating drilling installation, with the result that they are custom solutions with a narrow range of application due to costs and design limitations. For example, different drilling systems are required for different drilling modes such as managed pressure drilling, dual density or dual gradient drilling, partial riser level drilling, and underbalanced drilling.
An example of the most common current practice is illustrated by
Also depicted in
A ball joint BJ (also known as a flex-joint) provides for some angular displacement of the riser R from vertical. The conventional method interprets any pressure in the riser R due to flow of pressurized fluids from wellhead W as an uncontrolled event (kick) that is controlled by closing the BOP (blowout preventer) either by rams around the tubulars therein, or by blind rams if no tubulars are present, or by shear rams capable of cutting the tubulars.
It is possible for the kick to enter the riser R, and then it is controlled by closing the diverter D (with or without tubulars present) and diverting the undesired flow through diverter lines DL. In the '135 patent the concept of an annular blow out preventer used as a gas handler to divert the flow of gas from a well control incident is described. This allows diversion of gas in the riser R by closing around the tubulars therein, but not when drilling, i.e., rotating the tubular.
In
There are some modifications that can be made to the slip joint SJ, an example of which is described in U.S. Patent Application No. US2003/0111799A1, to produce a working rating to 750 psi. In practice, the limitation on the slip joint SJ seals has also led to an accepted standard in the industry of the diverter D, ball joint BJ (also sometimes replaced by a unit known as a flex-joint) and other parts of the system (such as valves on the diverter line DL) having a typical industry-wide rating of 500 psi working pressure.
The outer barrel OB of the slip joint SJ (telescopic joint) also acts as an attachment point for a tension system that serves to keep the riser R in tension to prevent it from buckling. This means that a leak in the slip joint SJ seals involves significant downtime in having to lift the entire riser R from the subsea BOP (blowout preventer) stack in order to service the slip joint SJ. In practice this has meant that no floating drilling installation service provider or operating company has been willing to take the risk to continuously operate with any pressure in the riser R for the conventional system (also depicted in
U.S. Patent Application No. 2005/0061546 and U.S. Pat. No. 6,913,092 have addressed this problem by proposing the locking closed of the slip joint SJ, which means locking the inner barrel IB to the outer barrel OB, thus eliminating movement across the slip joint seal. The riser R is then effectively disconnected from the ball joint BJ and diverter D as shown in
The riser R is closed by the addition of a rotating blowout preventer 70 on top of the locked closed slip joint SJ. This effectively decouples the riser R from any fixed point below the rotary table RT.
Also depicted in
This method has been used and allowed operations with a limit of 500 psi internal riser pressure, with the weak point still being the slip joint seals. However, decoupling the riser R from the fixed rig floor F means that it is only held by the tensioner system T1 and T2.
This means that the top of the riser R is no longer self centralizing. This causes the top of an RCD 80 (rotating control device) of the blowout preventer 10 to be off center as a result of ocean currents, wind or other movement of the floating structure. This introduces significant wear on the sealing element(s) of the RCD 80, which is detrimental to the pressure integrity of the riser system.
Also, the riser system of
Furthermore, the installation and operation requires personnel to perform tasks around the RCD 80, a hazardous area with the relative movement between the floating structure S to the top of the riser R. All of the equipment does not fit through the rotary table RT and diverter housing D, thus making installation complex and hazardous. As a result, use of the system of
A summary of the evolution for the art for drilling with pressure in the riser is shown in
In order to reduce costs, the industry moved towards the idea of using a SBOP (surface blowout preventer) with a floating drilling installation (for example, U.S. Pat. No. 6,273,193 as illustrated in
In attempting to take the concept of a SBOP and high pressure riser further into more environmentally harsh areas, a subsea component for disconnection (known as an environmental safeguard ESG system) and securing the well in case of emergency was re-introduced, but not as a full subsea BOP. This is shown in
In trying to plan for substantially higher pressures as experienced in underbalanced drilling where the formation being drilled is allowed to flow with the drilling fluid to surface, the industry has favored designs utilizing an inner riser run within the typical 21 inch marine riser as described in U.S. Patent Application 2006/0021755 A1. This requires a SBOP as shown in
Drawbacks of the systems and methods described above include that they require substantial modification of the floating drilling installation to enable the use of SBOP (surface blowout preventers) and the majority are limited to benign sea and weather conditions. Thus, they are not widely implemented since, for example, they require the floating drilling installation to undergo modifications in a shipyard.
Methods and systems as shown in U.S. Pat. Nos. 6,230,824 and 6,138,774 attempt to dispense totally with the marine riser. Methods and systems described in U.S. Pat. Nos. 6,450,262, 6,470,975, and U.S. Patent Application 2006/0102387A1 envision setting an RCD device on top of the subsea BOP to divert pressure from the marine riser, as does U.S. Pat. No. 7,080,685 B2. All of these patents are not widely applied as they involve substantial modifications and additions to existing equipment to be successfully applied.
A problem with the foregoing systems that utilize a high pressure riser or a riserless setup is that one of the primary means of delivering additional fluids to the seafloor, namely the booster line BL that is a typical part of the conventional system as depicted in
There is also an evolution in the industry to move from conventional drilling to closed system drilling. These types of closed systems are described in U.S. Pat. Nos. 6,904,981 and 7,044,237, and require the closure and (by consequence) the trapping of pressure inside the marine riser in floating drilling installations. Also, the introduction of a method and system to allow continuous circulation as described in U.S. Pat. No. 6,739,397 allows a drilling circulation system to be operated at constant pressure as the pumps do not have to be switched off when making or breaking a tubular connection. This allows the possibility of drilling with a constant pressure downhole, which can be controlled by a pressurized closed drilling system. The industry calls this Managed Pressure Drilling.
With the conventional method of
With the method of U.S. Pat. No. 6,913,092 (as depicted in
The systems mentioned earlier in U.S. Pat. Nos. 6,904,981 and 7,044,237 discuss closing the choke on a pressurized drilling system, and using manipulation of the choke to control the backpressure of the system, in order to control the pressure at the bottom of the well. This method works in principle, but in field applications of these systems, when drilling in a closed system, the manipulation of the choke can cause pressure spikes that are detrimental to the purpose of these inventions, i.e., precise control of the bottom hole pressure.
Also, a peculiarity of a floating drilling installation is, that when a connection is made, the top of the pipe is held stationary in the rotary table (RT in
When the system is closed by the addition of an RCD as shown in
Development of RCD's (rotating control devices) originated from land operations where typically the installation was on top of the BOP (blowout preventer). This meant that usually there was no further equipment installed above the RCD. As access was easy, almost all of the current designs have hydraulic connections for lubricating and cooling bearings in the RCD, or for other utilities. These require the external attachment of hoses for operation.
Although some versions have progressed from surface type to being adapted for use on the bottom of the sea (such as described in U.S. Pat. No. 6,470,975), they fail to disclose a complete system for achieving this. Some systems (such as described in U.S. Pat. No. 7,080,685) dispense with hydraulic cooling and lubrication, but require a hydraulic connection to release the assembly.
Furthermore, the range of RCD's and alternatives available means that a custom made unit to house a particular RCD design is typically required (such as described in U.S. Pat. No. 7,080,685). The '685 patent provides only for a partial removal of the RCD assembly, leaving the body on location.
Many ideas have been tried and patents have been filed, but the field application of technology to solve some of the shortcomings in the conventional set-up of
These needs include, but are not limited to: the capability to pressurize the marine riser to the maximum pressure capacity of its members; the capability to be safely installed using normal operational practices and operated as part of a marine riser without any floating drilling installation modifications as required for surface BOP operations or some subsea ideas; providing full-bore capability like a normal marine riser section when required; providing the ability to use the standard operating procedures when not in pressurized mode; maintaining the weather (wind, current and wave) operating window of the floating drilling installation; providing a means for damping the pressure spikes caused by heave resulting in surge and swab fluctuations; providing a means for eliminating the pressure spikes caused by movement of the rotatable tubulars into and out of a closed system; and providing a means for easily modifying the density of fluid in the riser at any desired point.
In carrying out the principles of the present invention, a riser system and associated methods are provided which solve one or more problems in the art. One example is described below in which the riser system includes modular internal components which can be conveniently installed and retrieved. Another example is described below in which the riser system utilizes rotating and/or non-rotating seals about a drill string within a riser, to thereby facilitate pressurization of the riser during drilling.
The systems and methods described herein enable all the systems shown in
In order to reduce, or even optimally remove pressure spikes (negative or positive from a desired baseline) from within a pressurized riser, a damping system is provided. A beneficial damping system in an incompressible fluid system includes the introduction of a compressible fluid in direct contact with the incompressible fluid. This could be a gas, e.g., Nitrogen.
An improved annular seal device for use in a riser includes a latching mechanism, and also allows hydraulic connections between the annular seal device and pressure sources to be made within the riser, so that no hoses are internal to the riser. The latching mechanism may be substantially internal or external to the riser.
The present specification provides a more flexible riser system, in part by utilizing a capability to interface an internal annular seal device with any riser type and connection, and providing adapters that are pre-installed to take the annular seal device being used. These can also have wear sleeves to protect sealing surfaces when the annular seal device is not installed. If an annular seal design is custom made for installation into a particular riser type, it may be possible to insert it without an additional adapter. The principle being that it is possible to remove the entire annular seal device to provide the full bore requirement typical of that riser system and install a safety/wear sleeve to positively isolate any ports that are open and provide protection for the sealing surfaces when the annular seal device is not installed.
In one aspect, a riser system is provided which includes a valve module which selectively permits and prevents fluid flow through a flow passage extending longitudinally through a riser string, and wherein a first anchoring device releasably secures the valve module in the flow passage.
In another aspect, a method of pressure testing a riser string is provided which includes the steps of: installing a valve module into an internal longitudinal flow passage extending through the riser string; closing the valve module to thereby prevent fluid flow through the flow passage; and applying a pressure differential across the closed valve module, thereby pressure testing at least a portion of the riser string.
In yet another aspect, a method of constructing a riser system includes the steps of: installing a valve module in a flow passage extending longitudinally through a riser string, the valve module being operative to selectively permit and prevent fluid flow through the flow passage; and installing at least one annular seal module in the flow passage, the annular seal module being operative to prevent fluid flow through an annular space between the riser string and a tubular string positioned in the flow passage.
A drilling method is also provided which includes the steps of: connecting an injection conduit externally to a riser string, so that the injection conduit is communicable with an internal flow passage extending longitudinally through the riser string; installing an annular seal module in the flow passage, the annular seal module being positioned in the flow passage between opposite end connections of the riser string; conveying a tubular string into the flow passage; sealing an annular space between the tubular string and the riser string utilizing the annular seal module; rotating the tubular string to thereby rotate a drill bit at a distal end of the tubular string, the annular seal module sealing the annular space during the rotating step; flowing drilling fluid from the annular space to a surface location; and injecting a fluid composition having a density less than that of the drilling fluid into the annular space via the injection conduit.
Another drilling method is provided which includes the steps of: connecting a drilling fluid return line externally to a riser string, so that the drilling fluid return line is communicable with an internal flow passage extending longitudinally through the riser string; installing an annular seal module in the flow passage, the annular seal module being positioned in the flow passage between opposite end connections of the riser string; conveying a tubular string into the flow passage; sealing an annular space between the tubular string and the riser string utilizing the annular seal module; rotating the tubular string to thereby rotate a drill bit at a distal end of the tubular string, the annular seal module sealing the annular space during the rotating step; flowing drilling fluid from the annular space to a surface location via the drilling fluid return line, the flowing step including varying a flow restriction through a subsea choke externally connected to the riser string to thereby maintain a desired downhole pressure.
Yet another drilling method includes the steps of: installing a first annular seal module in an internal flow passage extending longitudinally through a riser string, the first annular seal module being secured in the flow passage between opposite end connections of the riser string; sealing an annular space between the riser string and a tubular string in the flow passage utilizing the first annular seal module, the sealing step being performed while the tubular string rotates within the flow passage; and then conveying a second annular seal module into the flow passage on the tubular string.
A further aspect is a method which includes the steps of: installing multiple modules in an internal flow passage extending longitudinally through a riser string, the modules being installed in the flow passage between opposite end connections of the riser string; inserting a tubular string through an interior of each of the modules; and then simultaneously retrieving the multiple modules from the flow passage on the tubular string.
Another drilling method includes the steps of: sealing an annular space between a tubular string and a riser string; flowing drilling fluid from the annular space to a surface location via a drilling fluid return line; and injecting a fluid composition having a density less than that of the drilling fluid into the drilling fluid return line via an injection conduit.
Yet another drilling method includes the steps of: installing an annular seal module in an internal flow passage extending longitudinally through a riser string, the annular seal module being secured in the flow passage between opposite end connections of the riser string; then conveying another annular seal module into the flow passage; and sealing an annular space between the riser string and a tubular string in the flow passage utilizing the multiple annular seal modules.
Another drilling method includes the steps of: installing an annular seal module in an internal flow passage extending longitudinally through a riser string, the annular seal module being secured in the flow passage between opposite end connections of the riser string; then conveying on a tubular string at least one seal into the annular seal module; and then sealing an annular space between the riser string and the tubular string in the flow passage utilizing the seal, the sealing step being performed while a drill bit on the tubular string is rotated.
These and other features, advantages, benefits and objects will become apparent to one of ordinary skill in the art upon careful consideration of the detailed description of representative embodiments of the invention hereinbelow and the accompanying drawings, in which similar elements are indicated in the various figures using the same reference numbers.
a-e are schematic elevation views of typical conventional riser systems used for floating drilling installations;
f is a schematic elevation view of a riser system and method embodying principles of the present invention as incorporated into the system of
g is a schematic elevation view of an alternate configuration of a riser system and method embodying principles of the present invention as incorporated into a DORS (deep ocean riser system);
a is a schematic view of fluid flow in a prior art concept of conventional drilling;
b is a schematic view of a concept of closed system drilling embodying principles of the present invention;
It is to be understood that the various embodiments of the present invention described herein may be utilized in various orientations, such as inclined, inverted, horizontal, vertical, etc., and in various configurations, without departing from the principles of the present invention. The embodiments are described merely as examples of useful applications of the principles of the invention, which is not limited to any specific details of these embodiments.
In the following description of the representative embodiments of the invention, directional terms, such as “above”, “below”, “upper”, “lower”, etc., are used for convenience in referring to the accompanying drawings. In general, “above”, “upper”, “upward” and similar terms refer to a direction toward an upper end of a marine riser, and “below”, “lower”, “downward” and similar terms refer to a direction toward a lower end of a marine riser.
In the drawings, and 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. Specific embodiments are described in detail and are shown in the drawings, 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 desired results.
Any use of any form of the terms “connect,” “engage,” “couple,” “attach” or any other term describing an interaction between elements is not meant to limit the interaction to direct interaction between the elements and may also include indirect interaction between the elements described. The various characteristics mentioned above, as well as other features and characteristics described in more detail below, will be readily apparent to those skilled in the art upon reading the following detailed description of the embodiments, and by referring to the accompanying drawings.
An offshore universal riser system (OURS) 100 is disclosed which is particularly well suited for drilling deepwater in the floor of the ocean using rotatable tubulars. The riser system 100 uses a universal riser section which may be interconnected near a top of a riser string below the slip joint in a subsea riser system. The riser system 100 includes: a seal bore to take an inner riser string (if present) with a vent for outer riser, a nipple to receive pressure test adapters, an inlet/outlet tied into the riser choke line, kill line or booster line(s) as required, one or more integral Blow Out Preventers as safety devices, outlet(s) for pressurized mud return with a valve(s), an optional outlet for riser overpressure protection, one or more seal bores with adapters that can accept a variety of RCD designs, a provision for locking said RCD(s) in place, a seal bore adapter to allow all RCD utilities to be transferred from internal to external and vice versa. Externally, the universal riser section includes all the usual riser connections and attachments required for a riser section. Additionally the riser system 100 includes provision for mounting an accumulator(s), provision for accepting instrumentation for measuring pressure, temperature and any other inputs or outputs, e.g., riser level indicators; a line(s) taking pressurized mud to the next riser section above or slip joint; Emergency Shut Down system(s) and remote operated valve(s); a hydraulic bundle line taking RCD utilities and controls; an electric bundle line for instrumentation or other electrical requirements. A choking system may also be inserted in the mud return line that is capable of being remotely and automatically controlled. The riser system 100 may also have a second redundant return line if required. As part of the system 100, when desired, an injection system 200 including a lower riser section coupled with a composite hose (or other delivery system) for delivery of fluids may be included with an inlet to allow injection of a different density fluid into the riser at any point between the subsea BOP and the top of the riser. This allows the injection into the riser of Nitrogen or Aphrons (glass spheres), or fluids of various densities that will allow hydrostatic variations to be applied to the well, when used in conjunction with a surface or sub surface choke.
There is flexibility in the riser system 100 to be run in conjunction with conventional annular pressure control equipment, multiple RCDs, adapted to use with 13⅜ high pressure riser systems or other high pressure riser systems based in principle on the outlines in
A refined and more sensitive control method for MPD (Managed Pressure Drilling) will be achieved by the riser system 100 with the introduction of Nitrogen in to the riser below the RCD. This will be for the purpose of smoothing out surges created by the heave of the floating drilling installation due to the cushioning effect of the Nitrogen in the riser as well as allowing more time for the choke manipulation to control the bottom hole pressure (BHP) regime. It has been demonstrated on many MPD jobs carried out on non-floating drilling installations, that having a single phase fluid makes it more difficult to control the BHP with the choke manipulation. On a floating drilling installation any surge and swab through the RCD has a more direct effect on the BHP with the monophasic system as it is not possible to compensate with the choke system. With the riser system 100, the choke(s) can be controlled both manually and/or automatically with input from both surface and or bottom hole data acquisition.
The riser system 100 allows Nitrified fluid drilling that is still overbalanced to the formation, improved kick detection and control, and the ability to rotate pipe under pressure during well control events.
This riser system 100 allows a safer installation as there is no change in normal practice when running the riser system and all functions remain for subsea BOP control, emergency unlatch, fluid circulation, and well control.
The riser system 100 includes seal bore protector sleeves and running tool(s) as required, enabling conversion from a standard riser section to full riser system 100 use.
The riser system 100 also may include the addition of lines on the existing slip joint which can be done: (1) permanently with additional lines and gooseneck(s) on slip joint, and hollow pipes for feeding through hydraulic or electrical hoses; or (2) temporarily by strapping hoses and bundles to the slip joint if acceptable for environmental conditions.
A system is disclosed for drilling deepwater in the floor of the ocean using rotatable tubulars. This consists of the riser system 100 and injection system 200. The two components can be used together or independently.
Referring to
The riser system 100 acts as a passive riser section during normal drilling operations. When pressurized operations are required, components are inserted into it as required to enable its full functionality. The section of riser used for riser system 100 may be manufactured from a thicker wall thickness of tube.
Referring to
As illustrated in
The section 30 may also include adapters B1 and B2 for enabling pressure tests of the riser and pressure testing the components installed during installation, operation and trouble shooting.
The section 30 may also include adapters C1, C2, and C3, which allow insertion of BOP (Blow Out Preventer) components and RCD (Rotating Control Devices). A typical riser system 100 will have at least one RCD device installed with a back-up system for safety. This could be a second RCD, an annular BOP, a Ram BOP, or another device enabling closure around the rotatable tubular 32. In the configuration shown in
The riser system 100 has several outlets to enable full use of the functionality of the devices A, B, and C1-C3. These include outlet 33 which allows communication to the annulus between the inner and outer riser (if installed), inlet/outlet 40 which allows communication into the riser below the safety device installed in C1, outlet 41 which is available for use as an emergency vent line if such a system is required for a particular use of the riser system 100, outlet/inlet 44 which would be the main flow outlet (can also be used as an inlet for equalization), outlet 45 which can be used to provide a redundant flow outlet/inlet, outlet 54 which can be used as an alternative outlet/inlet and outlet 61 which can be used as an inlet/outlet. The particular configuration and use of these inlets and outlets depends on the application. For example, in managed pressure drilling, outlets 44 and 45 could be used to give two redundant outlets. In the case of mud-cap drilling, outlet 44 would be used as an inlet tied into one pumping system and outlet 45 would be used as a back-up inlet for a second pumping system. A typical hook-up schematic is illustrated in
The details for the devices are now given to allow a fuller understanding of the typical functionality of the riser system 100. The riser system 100 is designed to allow insertion of items as required, i.e., the clearances allow access to the lowermost adapter to insert items as required, with increases in clearance from bottom to top.
Device A is the inner riser adapter and may be specified according to the provider of the inner riser system. On the lhs (left hand side) item 34 is the adapter that would be part of the riser system 100. This would have typically a seal bore and a latch recess. A protector sleeve 35 would usually be in place to preserve the seal area. On the rhs (right hand side) the inner riser is shown installed. When the inner riser 36 is run, this sleeve 35 would be removed to allow latching of the inner riser 36 in the adapter 34 with the latch and seal mechanism 37. The exact detail and operation depends on the supplier of the inner riser assembly. Once installed, the inner riser provides a sealed conduit eliminating the pressure weakness of the outer riser section 30. The riser system 100 may be manufactured to a higher pressure rating so that it could enable the full or partial pressure capability of the inner riser system. An outlet 33 is provided to allow monitoring of the annulus between inner riser 36 and outer riser 30.
Devices B1 and B2 are pressure test adapters. Normally in conventional operations the riser is never pressure tested. All pressure tests take place in the subsea BOP stack. For pressurized operations, a pressure test is required of the full riser system after installation to ensure integrity. For this pressure test, adapter B2 is required which is the same in principle as the description here for pressure test adapter B1. The riser system 100 includes an adapter 38 for the purpose of accepting a pressure test adapter 39. This pressure test adapter 39 allows passage of the maximum clearance required during the pressurized operations. It can be pre-installed or installed before pressurized operations are required. When a pressure test is required, an adapter 39a is attached to a tubular 32 and set in the adapter 39 as illustrated in the rhs of
Device C1 is a safety device that can be closed around the rotatable tubular 32, for example but not being limited to an annular BOP 42, a ram BOP adapted for passage through the rotary table, or an active RCD device like that depicted in C2. The device C1 can be installed internally like C2 and C3 or it can be an integral part of the riser system 100 as depicted in
Device C2 schematically depicts an active RCD. An adapter 46 is part of the riser system 100 to allow installation of an adapter 47 with the required seal and latch systems that are designed for the particular RCD being used in the riser system 100. Both 46 and 47 have ports to allow the typical supply of hydraulic fluids required for the operation of an active RCD. A seal protector and hydraulic port isolation and seal protector sleeve 48 are normally in place when the active RCD 50 is not installed as shown on the lhs. When the use of the active RCD 50 is required, the seal protector sleeve 48 is pulled out with a running tool attached to the rotatable tubular 32. Then the active RCD 50 is installed as shown on the rhs. A hydraulic adapter manifold 51 provides communication from the hydraulic supply (not shown) to the RCD. Schematically, two hydraulic conduits are shown on the rhs. Conduit 52 supplies hydraulic fluid to energize the active element 49 and hydraulic conduit 53 typically supplies oil (or other lubricating fluid) to the bearing. A third conduit may be present (not shown) which allows recirculation of the bearing fluid. Depending on the particular type of active RCD, more or fewer hydraulic conduits may be required for other functions, e.g., pressure indication and/or latching functions.
Device C3 schematically depicts a passive RCD 58 with two passive elements 59 and 60 as is commonly used. An adapter 57 is installed in the riser system 100. It is possible to make adapters that protect the sealing surface by bore variations and in such a case for a passive head requiring no utilities (some require utilities for bearing lubrication/cooling) no seal protector sleeve is required. In this case the passive RCD 58 can be installed directly into the adapter 57 as shown on rhs with the sealing elements 59 and 60 continuously in contact with the tubular 32. This schematic installation also assumes that the latching mechanism for the RCD 58 is part of the RCD and activated/deactivated by the running tool(s).
The riser system 100 may also include other items attached to it to make it a complete package that requires no further installation activity once installed in the riser. These other items may include instrumentation and valves attached to the outlets/inlets 33, 40, 41, 44, 45, 54, 61. These are described in conjunction with
Referring to
Outlet 41 is connected to a safety device 104 that allows for pressure relief back to the floating drilling installation through line 95. This safety device 104 may be a safety relief valve or other suitable system for relieving pressure.
Devices C1, C2, and C3 are connected through their individual control pods 301, 302, and 303 respectively to a central electro-hydraulic control system 304 that also includes accumulators. It has an electric line 89 and a hydraulic line 90 back to the floating drilling installation. In concept, the usage of the different connections is similar so the following description for items 40, 111, 112, 113, 114, and 119 is the same as for: 44, 118, 117, 115, 116 and 119; and for 45, 124, 123, 122, 121 and 120; as well as for 54, 131, 132, 133, 134 and 120.
How many of these sets of connections and valves are installed is dependent on the planned operation, number of devices (C1, C2, and C3) installed, and the degree of flexibility required. A similar set of items can be connected to outlet 61 if required.
Taking outlet/inlet 40 as a typical example of the above listed sets, an instrument adapter or sensor 111 which can measure any required data, typically pressure and temperature, is attached to the line from outlet 40. The flow then goes through this line via a choking system 112 that is hydraulically or otherwise controlled, then through two hydraulically controlled valves 113 and 114 of which at least one is fail closed. The flow can then continue up line 88 back to the floating drilling installation. Flow can also be initiated in reverse down this line 88 if required. A similar line 194 is provided connected to outlet/inlet 45.
Sensor 111 can monitor parameters (such as pressure and/or temperature, etc.) in the interior of the riser section 30, riser string 84 or riser string 206 (described below) below the annular BOP 42 or the valve module 202 described below (see
As depicted,
The control systems 55 described above are depicted in further detail in
Control system 119 is connected to electric line 186 and hydraulic supply line 87 for controlling actuation of valves 113, 114, 115, 116 and chokes 112, 117. Control system 119 also receives data signals from sensors 111, 118. Control signals from the surface may be multiplexed on the electric line 186, and data signals from the sensors 111, 118 may also be multiplexed on the electric line 186.
If outlet 44 is used for return flow of drilling fluids during drilling, then choke 117 may be used to regulate back pressure in the riser string 84 for managed pressure drilling to maintain a desired constant or selectively varying downhole pressure (for example, a bottomhole pressure at the drill bit depicted in
Control system 120 is connected to electric line 192 and hydraulic supply line 93 for controlling actuation of valves 121, 122, 133, 134 and chokes 123, 132. Control system 120 also receives data signals from sensors 124, 131. Control signals from the surface may be multiplexed on the electric line 192, and data signals from the sensors 124, 131 may also be multiplexed on the electric line 192.
If outlet 45 or 54 is used for return flow of drilling fluids during drilling, then choke 123 or 132 may be used to regulate back pressure in the riser string 84 for managed pressure drilling to maintain a desired constant or selectively varying downhole pressure (for example, a bottomhole pressure at the drill bit depicted in
Control system 304 is connected to electric line 89 and hydraulic supply line 90 for controlling operation of the control pods 301, 302, 303. The control pods 301, 302, 303 include valves, actuators, accumulators, sensors for actuating and monitoring operation of the various modules (e.g., annular BOP 42, active RCD 50, passive RCD 58, valve module 202 and/or annular seal modules 222, 224, 226) which may be installed in the riser section 30 or riser string 84 or 206.
Any of the subsea control systems 119, 120, 304 can be replaced by means of a subsea remotely operated vehicle 320 (see
Variable density fluid is injected down conduit 11 to the injection system 200 and the detailed description for this operation is described more fully below.
The injection system 200 consists of a riser section (usually a shorter section called a pup) which has an inlet, and a composite hose system, or other suitable delivery mechanism to allow injection of different density fluids into the riser at any point between the subsea BOP and the top of the riser system 100.
The injection system 200 can be used independently of or in conjunction with the riser system 100 on any floating drilling installation to enable density variations in the riser. In managed pressure or underbalanced drilling operations, the injection system 200 may be used to inject a fluid composition 150 into the riser string 84 which has less density than the drilling fluid 81 returned from the wellbore during drilling.
The injection system 200 allows the injection into the riser of a fluid composition 150 including, for example, Nitrogen or Aphrons (hollow glass spheres), or fluids of various densities which will allow hydrostatic variations to be applied to the well, when used in conjunction with a surface or sub surface choke. As described previously, the injection system 200 is a conduit through which a Nitrogen cushion could be applied and maintained to allow more control of the BHP by manipulation of the surface choke, density of fluid injected, and injection rate both down the drill string and into the annulus through the injection system 200.
The injection system 200 externally includes all the usual riser connections and attachments required for a riser section. Additionally, the injection system 200 includes provision for mounting an accumulator(s) (shown), provision for accepting instrumentation for measuring pressure, temperature, and any other inputs or outputs. Emergency shut down system(s) remote operated valve(s), a hydraulic bundle line supplying hydraulic fluid, hydraulic pressure and control signals to the valve, and choke systems may also be included on the injection system 200.
The injection system 200 may be based solely on a hydraulic system, a hydraulic and electric bundle line for instrumentation or other electrical control requirements, or a full MUX (Multiplex) system. A choking system may also be inserted in the fluid injection conduit (shown) that is remotely and automatically controlled.
A riser section 1, which may be a riser pup, of the same design as the riser system with the same end connections 16 as the riser system is the basis of the injection system 200. This riser section 1 includes a fluid injection connection 2 with communication to the inside of the riser section 1. This connection 2 can be isolated from the riser internal fluid by hydraulically actuated valves 3a and 3b fitted with hydraulic actuators 4a and 4b. The injection rate can be controlled both by a surface control system 19 (pump rate and/or choke) and subsea by a remotely operated choke 14. As added redundancy, one or more non-return valve(s) 8 may be included in the design. The conduit to supply the injection fluid from surface to the injection system 200 is shown as a spoolable composite conduit 11, which can be easily clamped to the riser or subsea BOP guidelines (if water depth allows and they are in place). Composite pipe and spooling systems as supplied by the Fiberspar Corporation are suitable for this application. The composite conduit 11 is supplied on a spoolable reel 12. The composite conduit 11 can be easily cut and connectors 13 fitted in-situ on the floating drilling installation for the required length. The operating hydraulic fluid for the actuators 4a and 4b of subsea control valves 3a and 3b and hydraulic choke 14 can be stored on the injection system 200 in accumulators 5 and 15, respectively. They can be individual, independent accumulator systems or one common supply system with electronic control valves as supplied in a MUX system. The fluid to the accumulators 5, 15 is supplied and maintained through hydraulic supply lines 9 from hydraulic hose reel 10 supplied with hydraulic fluid from a surface hydraulic supply and surface control system 18. As discussed above, the surface control system 18 may also be used to control operation of subsea control systems 119, 120, 304, although additional or separate surface control system(s) may be used for this purpose, if desired.
Hydraulic fluid for the valve actuators 3a and 3b from the accumulator 5 is supplied through hose 7 and hydraulic fluid from accumulator 15 is supplied through hose 17 to hydraulic choke 14. Electro-hydraulic control valve 6a for actuators 4a and 4b allows closing and opening of valves 3a and 3b by way of electrical signals from surface supplied by electric line 20 and electro-hydraulic control valve 6b allows closing and opening of the hydraulic choke 14 similarly supplied by control signal from surface by line 20.
During conventional drilling operations, the valves 3a and 3b are closed and the injection system 200 acts like a standard section of riser. When variable density operations are required in the riser, valves 3a and 3b are opened by hydraulic control and a fluid composition 150 including, e.g., Nitrogen is injected by the surface system 19 through the hose reel 12 down the conduit 11 into the riser inlet connection 2. The rate can be controlled at the surface system 19 and/or by the downhole choke 14 as required. One of the hydraulic control valves 3b is set up as a fail-safe valve, meaning that if pressure is lost in the hydraulic supply line it will close, thus always ensuring the integrity of the riser system. Similarly, when a return to conventional operations is required, fluid injection is stopped and the valves 3a and 3b are closed.
The injection system 200 may include, as illustrated in
In
An example use and operating procedure are described here for a typical floating drilling installation to illustrate an example method of use of the system.
The riser system 100 will be run as a normal section of riser through the rotary table RT, thus not exceeding the normal maximum OD for a 21 inch riser system of about 49 inches or 60 inches as found on newer generation floating drilling installations. It will have full bore capability for 18¾ inch BOP stack systems and be designed to the same specification mechanically and pressure capability as the heaviest wall section riser in use for that system. An injection system 200 will be run in the lower part of the riser with spoolable composite pipe (FIBERSPAR™, a commercially available composite pipe, is suitable for this application).
In normal drilling operations with, e.g., a plan to proceed to managed pressure drilling, the riser system 100 and injection system 200 will be run with all of the external components installed. The riser system 100 and injection system 200 will be installed with seal bore protector sleeves 35, 48 in place and pressure tested before insertion into riser. During conventional drilling operation the inlet and outlet valves will be closed and both the riser system 100 and injection system 200 will act as normal riser pup joints. The riser system 100 will be prepared with the correct seal bore adapters for the RCD system to be used.
When pressurized operations are required, the injection system 200 is prepared and run as part of the riser inserted at the point required. The necessary connections for control lines 9, 20 are run, as well as the flexible conduit 11, for injecting fluids of variable density in the fluid composition 150. The cables and lines are attached to the riser or to the BOP guidelines if present. Valves 3a and 3b are closed.
The riser system 100 is prepared with the necessary valves and controls as shown in
Pipe will be run in hole with a BOP test adapter. The test adapter is set in the subsea wellhead and the annular BOP C3 is closed in the riser system 100. A pressure test is then performed to riser working pressure. The annular BOP C3 in the riser system 100 is then opened and the pressure test string is pulled out. If the subsea BOP has rams that can hold pressure from above, a simpler test string can be run setting a test plug in adapter B2 on the riser system 100 (see
When the riser system 100 is required for use, an adapter 39 will be run in the lower nipple B1 of the riser system 100 to provide a pressure test nipple similar to that of the smallest casing string in the wellhead so that subsequent pressure tests do not require a trip to subsea BOP.
The seal bore protector sleeve 48 for the RCD adapter C2 may be pulled out. Then the RCD 50 can be set in C2. Once set, the RCD 50 is function tested.
The rotatable tubular 32 is then run in hole with the pressure test adapter 39a for the riser system 100 until the adapter 39a is set in adapter 39 (already prepared as part of a previous step). The RCD 50 is then closed and, for active systems only, fluid is circulated through the riser system 100 using, e.g., outlet 44. The outlet 44 is then closed and the riser is pressure tested. Once pressure tested, the pressure is bled off and the seal element on the RCD 50 is released. The test assembly is then pulled out of the riser system 100. A similar method may be completed to set another RCD 58 in section C3.
The drilling assembly is then run in hole and circulation at the drilling depth is established. The pumps are then stopped. Once stopped, the RCD 50 seal element is installed (only if needed for the particular type of RCD), and the RCD 50 is activated (for active systems only). The mud outlet 44 on the riser system 100 is then opened. Circulation is then established and backpressure is set with an automated surface choke system or, alternatively, the choke 112 connected to the outlet 44. If a change in density is required in the riser fluid, choke 14 (see
The system is shown in
Variations of the above method with the riser system 100 and injection system 200 will enable a variety of drilling permutations that require pressurized riser operations, such as but not limited to dual density or dual gradient drilling; managed pressure drilling (both under and overbalanced mud weights); underbalanced drilling with flow from the formation into the wellbore; mud-cap drilling, i.e., injection drilling with no or little return of fluids; and constant bottom hole pressure drilling using systems that allow continuous circulation. The riser system 100/injection system 200 enables the use of DAPC (dynamic annular pressure control) and SECURE (mass balance drilling) systems and techniques. The riser system 100/injection system 200 also enables the use of pressurized riser systems with surface BOP systems run below the water line. The riser system 100/injection system 200 can also be used to enable the DORS (deep ocean riser system). The ability to introduce Nitrogen as a dampening fluid will for the first time give a mechanism for removing or very much reducing the pressure spikes (surge and swab) caused by heave on floating drilling installations. The riser system 100/injection system 200 enables a line into the interior of any of the riser systems depicted in
As described above, the riser system 100 and injection system 200 may be interconnected into an otherwise conventional riser string. The riser system 100/injection system 200 provides a means for pressurizing the marine riser to its maximum pressure capability and easily allows variation of the fluid density in the riser. The injection system 200 includes a riser pup joint with provision for injecting a fluid into the riser with isolation valves. The riser system 100 includes a riser pup joint with an inner riser adapter, a pressure test nipple, a safety device, outlets with valves for diverting the mud flow and nipples with seal bores for accepting RCDs. The easy delivery of fluids to the lower injection pup joint (injection system 200) is described. A method is detailed to manipulate the density in the riser to provide a wide range of operating pressures and densities enabling the concepts of managed pressure drilling, dual density drilling or dual gradient drilling, and underbalanced drilling.
Referring additionally now to
In
The housing 280 is shown as being a separate component of the riser string 206, but in other embodiments the housing could be integrated with other module housings 268, 282, 284, 306 (described below), and could be similar to the construction of the riser section 30 shown in
The housing 280 provides a location 240 for appropriately positioning the valve module 202 in the riser string 206. In this example, the housing 280 includes an internal latch profile 262 and a seal bore 328 for securing and sealing the valve module 202 in the riser string 206.
The valve module 202 includes an anchoring device 208 with radially outwardly extendable latch members 254 for engaging the profile 262, and seals 344 for sealing in the seal bore 328. The valve module 202 is depicted in
Other configurations of the valve module 202 can be used, if desired. For example, as depicted in
The valve module 202 selectively permits and prevents fluid flow through a flow passage 204 formed longitudinally through the riser string 206. As depicted in
A variety of operations may be performed utilizing the valve module 202. For example, the valve module 202 may be used to pressure test various portions of the riser string 206, to pressure test the annular seal modules 222, 224, 226 (described below), to facilitate pressure control in a wellbore 346 during underbalanced or managed pressure drilling (such as, during drill bit 348 changes, etc., see
Referring now to
The housing 284 provides a location 244 for appropriately positioning the annular seal module 224 in the riser string 206. In this example, the housing 284 includes an internal latch profile 266 and a seal bore 332 for securing and sealing the annular seal module 224 in the riser string 206. The housing 284 may be a separate component of the riser string 206, or it may be integrally formed with any other housing(s), section(s) or portion(s) of the riser string.
The annular seal module 224 includes an anchoring device 250 with radially outwardly extendable latch members 258 for engaging the profile 266, and seals 352 for sealing in the seal bore 332. The annular seal module 224 is depicted in
Other configurations of the annular seal module 224 can be used, if desired. For example, as depicted in
The annular seal module 224 selectively permits and prevents fluid flow through an annular space 228 formed radially between the riser string 206 and a tubular string 212 positioned in the flow passage 204 (see
The annular seal module 224 also includes a bearing assembly 324 which permits the seal 218 to rotate with the tubular string 212 when the seal is engaged with the tubular string and the tubular string is rotated within the flow passage 204 (such as, during drilling operations). The bearing assembly 324 is supplied with lubricant via a lubricant supply line 322 externally connected to the housing 284. A lubricant return line 326 (see
The annular seal module 224 is an alternative for, and may be used in place of, the active RCD 50 described above. Operation of the annular seal module 224 (for example, to extend or retract the seal 218) may be controlled by means of the subsea control system 304 and control pod 302, and/or the surface control system 18 described above.
Referring now to
The housing 282 provides a location 242 for appropriately positioning the annular seal module 222 in the riser string 206. In this example, the housing 282 includes an internal latch profile 266 and a seal bore 330 for securing and sealing the annular seal module 222 in the riser string 206. The housing 282 may be a separate component of the riser string 206, or it may be integrally formed with any other housing(s), section(s) or portion(s) of the riser string.
The annular seal module 222 includes an anchoring device 248 with radially outwardly extendable latch members 256 for engaging the profile 266, and seals 354 for sealing in the seal bore 330. The annular seal module 222 is depicted in
Other configurations of the annular seal module 222 can be used, if desired. For example, as depicted in
The annular seal module 222 selectively permits and prevents fluid flow through the annular space 228 formed radially between the riser string 206 and the tubular string 212 positioned in the flow passage 204 (see
The annular seal module 222 also includes a bearing assembly 324 which permits the seals 216 to rotate with the tubular string 212 when the seal is engaged with the tubular string and the tubular string is rotated within the flow passage 204 (such as, during drilling operations). The bearing assembly 324 may be supplied with lubricant via a lubricant supply line and lubricant return line as described above for the annular seal module 224.
The annular seal module 222 is an alternative for, and may be used in place of, the passive RCD 58 described above. Operation of the annular seal module 222 may be controlled by means of the subsea control system 304 and control pod 302, and/or the surface control system 18 described above.
Referring now to
The housing 268 may be a separate component of the riser string 206, or it may be integrally formed with any other housing(s), section(s) or portion(s) of the riser string. In this configuration of the riser system 100, the housing 268 is preferably positioned above the locations 240, 242, 244, 246 provided for the other modules 202, 222, 224, 226, so that the anchoring device 210 and seals 214 may be used for pressure testing the riser string 206 and the other modules.
In one pressure testing procedure, the anchoring device 210 and seals 214 can be conveyed into and installed in the riser string 206 with a portion of the tubular string 212 which extends downwardly from the anchoring device and through any annular seal modules 222, 224, 226, but not through the valve module 202. This configuration is representatively illustrated in
Note that, in
The anchoring device 210 functions in the pressure testing procedure to prevent displacement of the tubular string 212 when pressure differentials are applied across the annular seal modules 222, 224, 226 and the valve module 202. The seals 214 on the anchoring device 210 also function to seal off the flow passage 204. Pressure can be delivered from a remote location (such as a surface facility) through the tubular string 212 to the flow passage 204 below the anchoring device 210.
The valve module 202 can be pressure tested by applying a pressure differential across the closed valve module using the tubular string 212. In the configuration of
In order to pressure test the annular seal module 222 and the portion of the riser string 206 between the annular seal modules 222, 224, the seal 218 of the annular seal module 224 can be operated to disengage from the tubular string 212. In this manner, pressure applied via the tubular string 212 to the flow passage 204 would cause a pressure differential to be applied across the annular seal module 222 and the portion of the riser string 206 between the annular seal modules 222, 224.
Alternatively, or in addition, the tubular string 212 could be positioned so that its lower end is between the annular seal modules 222, 224, in which case operation of the seal 218 may not affect whether a pressure differential is applied across the annular seal module 222 or the portion of the riser string 206 between the annular seal modules 222, 224.
If the valve module 202 is opened, then pressure applied via the tubular string 212 can be used to pressure test the portion of the riser string 206 below the annular seal module 222 and/or annular seal module 224. In this manner, the pressure integrity of the portion of the riser string 206 which would be subject to significant pressure differentials during underbalanced or managed pressure drilling can be verified.
Note that the pressure applied to the flow passage 204 via the tubular string 212 may be a pressure increase or a pressure decrease, as desired. In addition, the pressure differentials caused as a result of the application of pressure via the tubular string 212 may also be used for pressure testing various components of the riser string 206, including but not limited to valves, lines, accumulators, chokes, seals, control systems, sensors, etc. which are associated with the riser string.
Although the
Referring additionally now to
Preferably, the latch members 256 and profile 264 are of the type which selectively engage with each other as the module 222 displaces through the riser string 206. That is, the latch members 256 and profile 264 may be “keyed” to each other, so that the latch members 256 will not operatively engage any other profiles (such as profiles 262, 266, 358) in the riser string 206, and the profile 264 will not be operatively engaged by any other latch members (such as latch members 254, 258, 356). A suitable “keying” system for this purpose is the SELECT-20™ system marketed by Halliburton Engineering Services, Inc. of Houston, Tex. USA.
One advantage of using such a “keyed” system is that a minimum internal dimension ID of the riser string 206 at each of the module locations 240, 242, 244, 246 can be at least as great as a minimum internal dimension of the riser string between the opposite end connections 232, 234 of the riser string. This would not necessarily be the case if progressively decreasing no-go diameters were used to locate the modules 202, 222, 224, 226 in the riser string 206.
Once the annular seal module 222 has been installed in the riser string 206, either conveyed on the tubular string 212 as depicted in
Latch members 257 permit the seals 216 to be separately installed in or retrieved from the annular seal module 222. The latch members 257 could, for example, be the same as or similar to the latch members 256 used to secure the annular seal module 222 in the riser string 206.
In one preferred method, the annular seal module 222 can be installed and secured in the riser string 206 using a running tool, without the seals 216 being present in the module. Then, when the tubular string 212 with the bit 348 thereon is lowered through the riser string 206, the seals 216 can be conveyed on the tubular string and installed and secured in the annular seal module 222. When the tubular string 212 and bit 348 are retrieved from the riser string 206, the seals 216 can be retrieved also.
This method can also be used for installing and retrieving the seals 218, 220 on any of the other annular seal modules 224, 226 described herein, for example, by providing latch members or other anchoring devices for the seals in the annular seal modules. The seals 216, 218, 220 could also be separately conveyed, installed and/or retrieved on other types of conveyances, such as running tools, testing tools, other tubular strings, etc.
The annular seal modules 222, 224 and/or 226 can be installed in any order and in any combination, and the seals 216, 218 and/or 220 can be separately installed and/or retrieved from the riser string in any order and in any combination. For example, two annular seal modules (such as the annular seal modules 222, 224 as depicted in
Referring additionally now to
Note that any of the other modules 202, 224, 226 can also be conveyed into the riser string 206 on the tubular string 212, and any of the other modules can also be retrieved from the riser string on the tubular string. In one example described below (see
Referring additionally now to
The drilling fluid return line 342 is in this example in fluid communication with the flow passage 204 below the annular seal module 224. Drilling fluid which is circulated down the tubular string 212 is returned (along with cuttings, the fluid composition 150 and/or formation fluids, etc., during the drilling operation) via the line 342 to the surface.
The line 342 may correspond to the line 88 or 194 described above, and various valves (e.g., valves 113, 114, 115, 116, 121, 122, 133, 134), chokes (e.g., chokes 112, 117, 123, 132), sensors (e.g., sensors 111, 118, 124, 131), etc., may be connected to the line 342 for regulating fluid flow through the line, regulating back pressure applied to the flow passage 204 to maintain a constant or selectively varying pressure in the wellbore 346, etc. The line 342 is depicted in
Another line 362 may be in fluid communication with the flow passage 204, for example, in communication with the annular space 228 between the annular seal modules 222, 224. This line 362 may be used for pressure relief (in which case the line may correspond to the line 95 described above), for monitoring pressure in the annular space 228, as an alternate drilling fluid return line, or for any other purpose. The line 362 could be in communication with the flow passage 204 at any desired point along the riser string 206, as desired.
Referring additionally now to
The drilling fluid return line 342 is conveniently installed in a typically unused portion of the flange connection. The injection conduit 11 and hydraulic supply line 9, as well as the lubrication supply and return lines 322, 326, pressure relief line 362 and electrical lines 20, 89, 186, 192 are positioned external to the flange connection, but still within an envelope which permits the riser string 206 to be installed through the rotary table RT. A hydraulic return or balance line 182 may also be provided external to the flange connection, if desired.
Referring additionally now to
Note that three combined valves 310 and actuators 314 are interconnected between the return line 342 and respective angled riser port connectors 366. These valves 310 and actuators 314 may correspond to the various valves (e.g., valves 113, 114, 115, 116, 121, 122, 133, 134) and chokes (e.g., chokes 112, 117, 123, 132) described above. By arranging the valves 310 and actuators 314 as depicted in
Referring additionally now to
In
In
In
In
The arrangement of
The flex joint FJ could alternatively be positioned between any of the housings 268, 306, 282, 284, 280, and at any point along the riser string 206. One advantage of the riser system 100 is that it enables utilization of a pressurized riser in deepwater drilling operations where an intermediate flex joint FJ is required, and where a riser fill up valve is required.
Although each of the housings 306, 282, 284 for the annular seal modules 226, 224, 222 are depicted in
Referring additionally now to
In this view, the externally connected valves 310, actuators 314 and connectors 366 described above in conjunction with
Referring additionally now to
The annular seal module 226 includes multiple sets of seals 220 for sealingly engaging the tubular string 212 while the tubular string rotates within the flow passage 204. The seals 220 can, thus, seal off the annular space 228 both while the tubular string 212 rotates and while the tubular string does not rotate in the flow passage 204.
In contrast to the seals of the other annular seal modules 222, 224, the active RCD 50 and the passive RCD 58 which rotate with the tubular string 212, the seals 220 of the annular seal module 226 do not rotate with the tubular string. Instead, the seals 220 remain stationary while the tubular string 212 rotates within the seals.
A lubricant/sealant (such as viscous grease, etc.) may be injected between the seals 220 via ports 368 from an exterior of the riser string 206 to thereby provide lubrication to reduce friction between the seals and the tubular string 212, and to enhance the differential pressure sealing capability of the seals. Sensors 340 may be used to monitor the performance of the seals 220 (e.g., to detect whether any leakage occurs, etc.).
Seals similar in some respects to the seals 220 of the annular seal module 226 are described in further detail in PCT Publication No. WO 2007/008085. The entire disclosure of this publication is incorporated herein by this reference.
Although three sets of the seals 220 are depicted in
Anchoring devices 252 are used for securing the annular seal module 226 in the housing 306 at the appropriate location 246. Each anchoring device 252 includes an actuator 278 and a latch member 260 for engagement with an external profile 276 formed on the annular seal module 226.
The use of the actuators 278 external to the riser string 206 provides for convenient securing and releasing of the module 226 from a remote location. In one embodiment, one or more of the modules 226 can be conveniently installed and/or retrieved on the tubular string 212 with appropriate operation of the actuators 278.
Operation of the actuators 278 could be controlled by the subsea control system 120, 304 and control pod 302 or 303, and/or surface control system 18 described above. Operation of the annular seal module 226 (e.g., injection of the lubricant/sealant, monitoring of the sensors 340, etc.) may be controlled by means of the subsea control system 304 and control pod 302 or 303, and/or the surface control system 18 described above.
Referring additionally now to
It will be appreciated that this method allows for installation of one or more annular seal modules 226 using the tubular string 212, without requiring additional trips into the riser string 206, and/or during normal drilling operations. For example, if during a drilling operation it is observed that the seals 220 of a lower module 226 are at or near the end of their projected life (perhaps informed by indications received from the sensors 340), an additional module 226 can be conveyed by the tubular string 212 into the riser string 206 by merely installing the module onto the tubular string when a next joint 370 is connected.
In this manner, the drilling operations are not interrupted, and the tubular string 212 does not have to be retrieved from the riser string 206, in order to ensure continued sealing of the annular space 228. This method is not limited to use with drilling operations, but can be used during other operations as well, such as completion or stimulation operations.
Referring additionally now to
As depicted in
In an emergency situation, such as in severe weather conditions, it may be desirable to retrieve the tubular string 212 quickly and install hang-off tools. Use of the external actuators 278 enables this operation to be accomplished quickly and conveniently.
In the event of failure of one or more of the actuators 278 to function properly, a conventional subsea remotely operated vehicle (ROV) 320 may be used to operate the actuators 278. As described above, the ROV 320 may also be used to perform maintenance on the subsea control systems 119, 120, 142, 304, and to perform other tasks.
Also shown in
Referring additionally now to
As depicted in
During installation of the completion equipment 350, the valve module 202 can be initially closed while the completion equipment is assembled and conveyed into the riser string 206 above the valve module. After the completion equipment 350 is in the upper riser string 206, and one or more of the annular seal modules 222, 224, 226 seals off the annular space 228 about the tubular string 212 above the completion equipment, the valve module 202 can be opened to allow the completion equipment and the tubular string to be safely conveyed into the wellbore 346.
In this type of operation, the spacing between the annular seal module(s) and the valve module 202 should be long enough to accommodate the length of the completion equipment 350. For example, a configuration similar to that shown in
Referring additionally now to
In this manner, problems associated with, e.g., forming gas slugs in the riser string 206 may be avoided. The subsea choke 112, 117, 123 or 132 can still be used to regulate back pressure on the annular space 228 and, thus, the wellbore 346 (for example, during managed pressure drilling), and the benefits of dual density and dual gradient drilling can still be obtained, without flowing variable density fluids or gas through the subsea choke.
As depicted in
In another feature of the configuration illustrated in
The valves 374 may be controlled utilizing the subsea control system 142 described above. The injection system illustrated in
It may now be fully appreciated that the above description provides many improvements in the art of riser system construction, drilling methods, etc. The riser system 100 allows the tubular string 212 to be moved in and out of the well under pressure in a variety of different types of drilling operations, such as underbalanced (UBD), managed pressure (MPD) and normal drilling operations. The riser system 100 allows for various internal modules 202, 222, 224, 226 and anchoring device 210 to be run in on tubular string 212 and locked in place by hydraulic and/or mechanical means. The internal modules 202, 222, 224, 226 allow for annular isolation, well isolation, pipe rotation, diverting of flow, dynamic control of flow, and controlled fluid injection into the return line 342 and/or into the riser string 206.
The riser system 100 enables utilization of a pressurized riser in deepwater drilling operations where an intermediate flex joint FJ is required, and where a riser fill up valve is required.
The riser system 100 allows isolation of the wellbore 346 from the surface by closing the valve module 202. This permits introduction of long completion tool strings (such as the completion equipment 350), bottom hole assemblies, etc., while still maintaining multiple flowpaths back to surface to continue managed pressure drilling operations.
The riser system 100 permits flexibility in dual gradient, underbalanced, managed pressure and normal drilling operations with the ability to have chokes 112, 117, 123, 132 positioned subsea and in the return line 342, as well as the surface choke manifold CM. The subsea and surface choke systems can be linked and fully redundant. This removes the complexity of the dual gradient fluid (e.g., the fluid composition 150) being in the return line 342 during well control operations.
The riser system 100 allows dual gradient operations, without the drilling fluid having to be pumped to surface from the sea bed, removing the back pressure from the well, with the ability to have multiple injection points along the return line 342 to surface, and the flexibility to position the internal modules 202, 222, 224, 226 anywhere along the riser string 206 from the slip joint SJ to the lower marine riser package LMRP.
The riser system 100 has the capability of having multiple annular seal modules 222, 224, 226 installed in the riser string 206, in any combination thereof. The seals 216, 218, 220 in the modules 222, 224, 226 may be active or passive, control system or wellbore pressure operated, and rotating or static. The module housings 268, 280, 282, 284, 306 can accept modules provided by any manufacturer, which modules are appropriately configured for the respective internal profiles, seal bores, etc.
The riser system 100 allows for full bore access through the riser string 206 when the modules 202, 222, 224, 226 are removed, therefore, not imposing any restrictions on normal operations or procedures from a floating drilling vessel. In emergency situations, the modules 202, 222, 224, 226 can be quickly retrieved and an operator can run conventional hang-off tools through the riser string 206.
The riser system 100 allows all module housings 268, 280, 282, 284, 306 to be deployed through the rotary table RT as normal riser sections. There preferably is no need for personnel to make connections or install equipment in the moon pool area of a rig 238 for the riser system 100.
The riser system 100 provides for continuous monitoring of flow rates, pressures, temperatures, valve positions, choke positions, valve integrity (e.g., by monitoring pressure differential across valves) utilizing sensors 21, 111, 118, 124, 131, 340, 336, 338, 230. The sensors are connected to subsea and surface control systems 119, 120, 304, 142, 18, 19 for monitoring and control of all significant aspects of the riser system 100.
The riser system 100 can accept deployment of an inner riser 36, if needed for increasing the pressure differential capability of the riser string 206 below the annular seal modules 222, 224, 226.
The riser system 100 can utilize protective sleeves 35, 48 to protect ports and seal bores 328, 330, 332, 334, 360 in the riser string 206 when the respective modules are not installed. The inner diameters of the protective sleeves 35, 48 are preferably at least as great the inner diameter of the conventional riser joints used in the riser string 206.
The riser system 100 permits the annular seal modules 222, 224 and/or 226 to be installed in any order, and in any combination. The annular seal modules 222, 224 and/or 226 can all be positioned below the slip joint SJ.
The latching profiles 358, 262, 266, 264 or latch actuators 278 and profiles 270, 272, 274, 276, and seal bores 328, 330, 332, 334, 360 can be standardized to allow interchangeability between different modules and different types of modules.
The valve module 202 may be used in conjunction with a blind BOP at the wellhead structure 236 and/or a BOP module 42 in the riser system 100 for redundant isolation between the wellbore 346 and the surface in the riser string 206.
In particular, the above description provides a riser system 100 which may include a valve module 202 which selectively permits and prevents fluid flow through a flow passage 204 extending longitudinally through a riser string 206.
An anchoring device 208 can releasably secure the valve module 202 in the flow passage 204. The anchoring device 208 may be actuated from a subsea location exterior to the riser string 206.
Another anchoring device 210 may releasably secure a tubular string 212 in the flow passage 204. The anchoring device 210 may prevent displacement of the tubular string 212 relative to the riser string 206 when pressure is increased in a portion of the riser string between the valve module 202 and a seal 214, 216, 218 or 220 between the tubular string 212 and the riser string 206.
An annular seal module 222, 224 or 226 may seal an annular space 228 between the riser string 206 and the tubular string 212. The anchoring device 210 may prevent displacement of the tubular string 212 relative to the riser string 206 when pressure is increased in a portion of the riser string between the valve module 202 and the annular seal module 222, 224 or 226.
As discussed above, the riser system 100 may include one or more annular seal modules 222, 224, 226 which seal the annular space 228 between the riser string 206 and a tubular string 212 in the flow passage 204. The annular seal module 222, 224 or 226 may include one or more seals 216, 218, 220 which seal against the tubular string 212 while the tubular string rotates within the flow passage 204. The seal 216, 218 may rotate with the tubular string 212. The seal 220 may remain stationary within the riser string 206 while the tubular string 212 rotates within the seal 220. The seal 218 may be selectively radially extendable into sealing contact with the tubular string 212.
The riser system 100 may include at least one sensor 230 which senses at least one parameter for monitoring operation of the valve module 202.
A method of pressure testing a riser string 206 has been described which may include the steps of: installing a valve module 202 into an internal longitudinal flow passage 204 extending through the riser string 206; closing the valve module 202 to thereby prevent fluid flow through the flow passage 204; and applying a pressure differential across the closed valve module 202, thereby pressure testing at least a portion of the riser string 206.
The installing step may include securing the valve module 202 in a portion of the flow passage 204 disposed between opposite end connections 232, 234 of the riser string 206. The lower end connection 234 may secure the riser string 206 to a subsea wellhead structure 236, and the upper end connection 232 may secure the riser string 206 to a rig structure 238. The upper end connection 232 may rigidly secure the riser string 206 to the rig structure 238.
The method may further include the step of installing an annular seal module 222, 224 or 226 into the flow passage 204, with the annular seal module being operative to seal an annular space 228 between the riser string 206 and a tubular string 212 positioned within the flow passage 204. The pressure differential applying step may include increasing pressure in the flow passage 204 between the valve module 202 and the annular seal module 222, 224 or 226.
The method may further include the step of installing another annular seal module 222, 224 or 226 into the flow passage 204, with the second annular seal module being operative to seal the annular space 228 between the riser string 206 and the tubular string 212 positioned within the flow passage 204. The pressure differential applying step may further include increasing pressure in the flow passage 204 between the valve module 202 and the second annular seal module 222, 224 or 226.
The method may further include the step of increasing pressure in the riser string 206 between the first and second annular seal modules 222, 224 and/or 226, thereby pressure testing the riser string between the first and second annular seal modules.
In the pressure differential applying step, the portion of the riser string 206 which is pressure tested may be between the valve module 202 and an end connection 234 of the riser string 206 which is secured to a wellhead structure 236.
The method may also include the steps of: conveying a tubular string 212 into the flow passage 204; and sealing and securing the tubular string at a position in the flow passage, so that fluid flow is prevented through an annular space 228 between the riser string 206 and the tubular string 212, and the pressure differential applying step may further include applying increased pressure via the tubular string 212 to the portion of the riser string 206 which is disposed between the valve module 202 and the position at which the tubular string 212 is sealed and secured in the flow passage 204.
The method may further include the step of utilizing at least one sensor 111, 118, 124 and/or 131 to monitor pressure within the riser portion during the pressure differential applying step.
Also described above is a method of constructing a riser system 100. The method may include the steps of: installing a valve module 202 in a flow passage 204 extending longitudinally through a riser string 206, the valve module 202 being operative to selectively permit and prevent fluid flow through the flow passage 204; and installing at least one annular seal module 222, 224 and/or 226 in the flow passage 204, the annular seal module being operative to prevent fluid flow through an annular space 228 between the riser string 206 and a tubular string 212 positioned in the flow passage 204.
The method may include the steps of providing an internal location 240 for sealing and securing the valve module 202 in the flow passage 204, and providing another location 242, 244 and/or 246 for sealing and securing the annular seal module 222, 224, 226 in the flow passage, and wherein a minimum internal dimension ID of the riser string 206 at each of these locations 240, 242, 244, 246 is at least as great as a minimum internal dimension of the riser string between opposite end connections 232, 234 of the riser string.
The valve module 202 and annular seal module 222, 224, 226 installing steps may also each include actuating an anchoring device 208, 248, 250, 252 to secure the respective module relative to the riser string 206. The actuating step may include engaging a latch member 254, 256, 258, 260 of the respective module 202, 222, 224, 226 with a corresponding internal profile 262, 264, 266 formed in the riser string 206. The actuating step may include displacing a respective latch member 254, 256, 258, 260 into engagement with a corresponding external profile 270, 272, 274, 276 formed on the respective module 202, 222, 224, 226, and wherein a respective actuator 278 on an exterior of the riser string 206 causes displacement of the respective latch member 254, 256, 258, 260.
The method may include the steps of: interconnecting a valve module housing 280 as part of the riser string 206; and interconnecting an annular seal module housing 282, 284 and/or 306 as part of the riser string. Each of the interconnecting steps may include displacing the respective module housing 280, 282, 284, 306 through a rotary table RT. The displacing step may include displacing the respective module housing 280, 282, 284, 306 through the rotary table RT with at least one of a valve 113, 114, 115, 116, 121, 122, 133 and/or 134 and an accumulator 56 externally connected to the respective module housing 280, 282, 284, 306.
The riser string 206 may include a portion 308 or section 30 having at least one valve 310, 113, 114, 115, 116, 121, 122, 133 and/or 134, at least one accumulator 312 and/or 56, and at least one actuator 314 and/or 278 externally connected to the riser portion for operation of the valve and annular seal modules 202, 222, 224 and/or 226. The method may also include the step of displacing the riser portion 308 or section 30 with the externally connected valve 310, 113, 114, 115, 116, 121, 122, 133 and/or 134, accumulator 312 and/or 56 and actuator 314 and/or 278 through a rotary table RT.
The method may include the steps of connecting hydraulic control lines 90, 316, 318 externally to the riser string 206 for operation of the valve and annular seal modules 202, 222, 224 and/or 226, and connecting the hydraulic control lines to a subsea hydraulic control system 304 external to the riser string 206. The method may also include the step of replacing the hydraulic control system 304 using a subsea remotely operated vehicle 320.
The method may include the step of connecting a hydraulic supply line 90 and an electrical control line 89 between the subsea hydraulic control system 304 and a surface hydraulic control system 18. Signals for operating the subsea hydraulic control system 304 to selectively supply hydraulic fluid to operate the valve and annular seal modules 202, 222, 224 and/or 226 may be multiplexed on the electrical control line 89.
The method may include the step of connecting at least one lubrication supply line 53 or 322 externally to the riser string 206 for lubricating a bearing assembly 324 of the annular seal module 222, 224. The method may include the step of connecting at least one lubrication return line 326 externally to the riser string 206 for returning lubricant from the bearing assembly 324.
The annular seal module 222, 224, 226 includes at least one seal 216, 218, 220 which seals against the tubular string 212 while the tubular string rotates within the flow passage 204. The seal 216 or 218 may rotate with the tubular string 212. The seal 220 may remain stationary within the riser string 206 while the tubular string 212 rotates within the seal 220. The seal 218 may be selectively radially extendable into sealing contact with the tubular string 212.
The valve and annular seal module 202, 222, 224, 226 installing steps may include sealing the respective module in a corresponding seal bore 328, 330, 332, 334 formed in the riser string 206. The method may further include the steps of retrieving a respective seal bore protector sleeve 35, 48 from within the corresponding seal bore 328, 330, 332, 334 prior to the steps of installing the respective one of the valve and annular seal modules 202, 222, 224, 226.
The method may include the step of retrieving a seal bore protector sleeve 35, 48 from within the riser string 206 prior to the step of installing the valve module 202. The method may include the step of retrieving a seal bore protector sleeve 35, 48 from within the riser string 206 prior to the step of installing the annular seal module 222, 224, 226.
The method may include utilizing at least one sensor 111, 118, 124, 131 to monitor pressure in the flow passage 204 between the valve module 202 and the annular seal module 222, 224 or 226. The method may include utilizing at least one sensor 230, 336, 338, 340 to monitor at least one parameter indicative of a performance characteristic of at least one of the valve and annular seal modules 202, 222, 224, 226.
A drilling method is also described which may include the steps of: connecting an injection conduit 11 externally to a riser string 206, so that the injection conduit is communicable with an internal flow passage 204 extending longitudinally through the riser string 206; installing an annular seal module 222, 224, 226 in the flow passage 204, the annular seal module being positioned in the flow passage between opposite end connections 232, 234 of the riser string 206; conveying a tubular string 212 into the flow passage 204; sealing an annular space 228 between the tubular string 212 and the riser string 206 utilizing the annular seal module 222, 224, 226; rotating the tubular string 212 to thereby rotate a drill bit 348 at a distal end of the tubular string, the annular seal module 222, 224, 226 sealing the annular space 228 during the rotating step; flowing drilling fluid 81 from the annular space 228 to a surface location; and injecting a fluid composition 150 having a density less than that of the drilling fluid into the annular space 228 via the injection conduit 11.
In the injecting step, the fluid composition 150 may include Nitrogen gas. The fluid composition 150 may include hollow glass spheres. The fluid composition 150 may include a mixture of liquid and gas.
The riser string 206 may include a portion 1 having at least one valve 8, 3a, 3b, 6a, 6b at least one accumulator 5, 15, and at least one actuator 4a, 4b externally connected to the riser portion 1 for controlling injection of the fluid composition 150. The method may include displacing the riser portion 1 with the externally connected valve 8, 3a, 3b, 6a, 6b accumulator 5, 15 and actuator 4a, 4b, through a rotary table RT.
The method may include the steps of connecting hydraulic control lines 7, 9, 17 externally to the riser string 84, 206 for controlling injection of the fluid composition 150, and connecting the hydraulic control lines to a subsea hydraulic control system 142 external to the riser string 84, 206. The method may include replacing the hydraulic control system 142 utilizing a subsea remotely operated vehicle 320. The method may include connecting a hydraulic supply line 9 and an electrical control line 20 between the subsea hydraulic control system 142 and a surface hydraulic control system 18. Signals for operating the subsea hydraulic control system 142 to selectively supply hydraulic fluid to control injection of the fluid composition 150 may be multiplexed on the electrical control line 20.
The method may include utilizing at least one sensor 21 to monitor pressure in the injection conduit 11.
A drilling method is also described which may include the steps of: connecting a drilling fluid return line 88, 194, 342 externally to a riser string 84, 206, so that the drilling fluid return line is communicable with an internal flow passage 204 extending longitudinally through the riser string; installing an annular seal module 222, 224, 226 in the flow passage 204, the annular seal module being positioned in the flow passage between opposite end connections 232, 234 of the riser string; conveying a tubular string 212 into the flow passage 204; sealing an annular space 228 between the tubular string 212 and the riser string 206 utilizing the annular seal module 222, 224, 226; rotating the tubular string 212 to thereby rotate a drill bit 348 at a distal end of the tubular string, the annular seal module 222, 224, 226 sealing the annular space 228 during the rotating step; and flowing drilling fluid 81 from the annular space 228 to a surface location via the drilling fluid return line 342, the flowing step including varying a flow restriction through a subsea choke 112, 117, 123, 132 externally connected to the riser string 206 to thereby maintain a desired downhole pressure.
The step of varying the flow restriction may include automatically varying the flow restriction without human intervention to thereby maintain the desired downhole pressure.
The riser string 206 may include a portion 308 having at least one valve 310, at least one accumulator 312, and at least one actuator 314 externally connected to the riser portion for operating the subsea choke 112, 117, 123, 132. The method may further include displacing the riser portion 308 with the externally connected valve 310, accumulator 312 and actuator 314 through a rotary table RT.
The method may include connecting hydraulic control lines 87, 93 externally to the riser string 84, 206 for controlling operation of the choke 112, 117, 123, 132, and connecting the hydraulic control lines to a subsea hydraulic control system 119, 120 external to the riser string 84, 206. The method may include connecting the hydraulic control line 87, 93 and at least one electrical control line 186, 192 between the subsea hydraulic control system 119, 120 and a surface hydraulic control system 18. Signals for operating the subsea hydraulic control system 119, 120 to selectively supply hydraulic fluid to control operation of the choke 112, 117, 123, 132 may be multiplexed on the electrical control line 186, 192.
The method may include utilizing at least one sensor 111, 118, 124, 131 to monitor pressure in the drilling fluid return line 88, 194.
Another drilling method is described which may include the steps of: installing a first annular seal module 222, 224 or 226 in an internal flow passage 204 extending longitudinally through a riser string 206, the first annular seal module being secured in the flow passage between opposite end connections 232, 234 of the riser string; sealing an annular space 228 between the riser string 206 and a tubular string 212 in the flow passage 204 utilizing the first annular seal module 222, 224 or 226, the sealing step being performed while the tubular string rotates within the flow passage; and then conveying a second annular seal module 222, 224 or 226 into the flow passage 204 on the tubular string 212.
The tubular string 212 may remain in the flow passage 204 between the opposite end connections 232, 234 of the riser string 206 continuously between the sealing and conveying steps.
The method may include sealing the annular space 228 between the riser string 206 and the tubular string 212 in the flow passage 204 utilizing the second annular seal module 222, 224 or 226, while the tubular string rotates within the flow passage.
The second annular seal module 222, 224 or 226 may include at least one seal 216, 218, 220 which seals against the tubular string 212 while the tubular string rotates within the flow passage 204. The seal 216, 218 may rotate with the tubular string 212. The seal 220 may remain stationary within the riser string 206 while the tubular string 212 rotates within the seal. The seal 218 may be selectively radially extendable into sealing contact with the tubular string 212.
The method may include utilizing at least one sensor 118, 124, 131 to monitor pressure in the flow passage 204 between the first and second annular seal modules 222, 224, 226.
A further method is described which may include the steps of: installing multiple modules 202, 222, 224 and/or 226 in an internal flow passage 204 extending longitudinally through a riser string 206, the modules being installed in the flow passage between opposite end connections 232, 234 of the riser string; inserting a tubular string 212 through an interior of each of the modules 202, 222, 224 and/or 226; and then simultaneously retrieving the multiple modules 202, 222, 224 and/or 226 from the flow passage 204 on the tubular string 212.
The retrieving step may include operating anchoring devices 208, 248, 250, 252 for the respective modules to thereby release the modules 202, 222, 224, 226 for displacement relative to the riser string 206. Each of the anchoring devices 208, 248, 250, 252 may include an actuator 278 externally connected to the riser string 206. At least one of the anchoring devices 278 may be operable by a subsea remotely operated vehicle 320 from an exterior of the riser string 206.
The modules 202, 222, 224, 226 may include at least one annular seal module 222, 224, 226 which seals an annular space 228 between the tubular string 212 and the riser string 206. The modules 202, 222, 224, 226 may include at least one valve module 202 which selectively permits and prevents fluid flow through the flow passage 204.
A drilling method is described above which includes the steps of: sealing an annular space 228 between a tubular string 212 and a riser string 206; flowing drilling fluid from the annular space to a surface location via a drilling fluid return line 342; and injecting a fluid composition 150 having a density less than that of the drilling fluid into the drilling fluid return line via an injection conduit 11.
The fluid composition 150 may include Nitrogen gas, hollow glass spheres and/or a mixture of liquid and gas.
The injecting step may include selecting from among multiple connection points between the drilling fluid return line 342 and the injection conduit 11 for injecting the fluid composition 150 into the drilling fluid return line.
The method may include the steps of connecting hydraulic control lines 7, 9, 17 externally to the riser string 206 for controlling injection of the fluid composition 150, and connecting the hydraulic control lines to a subsea hydraulic control system 142 external to the riser string 206.
The injecting step may include injecting the fluid composition 150 into the drilling fluid return line 342 downstream from a subsea choke 112, 117, 123 or 132 which variably regulates flow through the drilling fluid return line. The injecting step may include injecting the fluid composition 150 into the drilling fluid return line 342 at a position between a surface location and a subsea choke 112, 117, 123 or 132 interconnected in the drilling fluid return line.
A drilling method described above includes the steps of: installing an annular seal module 222, 224 or 226 in an internal flow passage 204 extending longitudinally through a riser string 206, the annular seal module being secured in the flow passage between opposite end connections 232, 234 of the riser string; then conveying a second annular seal module 222, 224 or 226 into the flow passage 204; and sealing an annular space 228 between the riser string and a tubular string 212 in the flow passage utilizing the first and second annular seal modules.
The sealing step may include sealing the annular space 228 between the riser string 206 and the tubular string 212 in the flow passage 204 utilizing the first and second annular seal modules 222, 224, 226 while the tubular string rotates within the flow passage.
Each of the annular seal modules may include at least one seal 216, 218, 220 which seals against the tubular string 212 while the tubular string rotates within the flow passage 204. The seal 216, 218 may rotate with the tubular string 212. The seal 220 may remain stationary within the riser string 206 while the tubular string 212 rotates within the seal. The seal 218 may be selectively radially extendable into sealing contact with the tubular string 212.
The method may include the step of utilizing at least one sensor 118, 124, 131 to monitor pressure in the flow passage between the first and second annular seal modules 222, 224, 226.
Another drilling method described above includes the steps of: installing an annular seal module 222, 224, 226 in an internal flow passage 204 extending longitudinally through a riser string 206, the annular seal module being secured in the flow passage between opposite end connections 232, 234 of the riser string; then conveying on a tubular string 212 at least one seal 216, 218, 220 into the annular seal module 222, 224, 226; and sealing an annular space 228 between the riser string 206 and the tubular string 212 in the flow passage 204 utilizing the seal 216, 218, 220, the sealing step being performed while a drill bit 348 on the tubular string 212 is rotated.
The method may also include the steps of installing another annular seal module 222, 224, 226 in the flow passage 204, and then conveying on the tubular string 212 at least one other seal 216, 218, 220 into the second annular seal module.
The method may also include the step of sealing the annular space 228 between the riser string 206 and the tubular string 212 in the flow passage 204 utilizing the first annular seal module 222, 224, 226, while the drill bit 348 rotates.
The first seal 216, 218, 220 may seal against the tubular string 212 while the drill bit 348 rotates. The first seal 216, 218, 220 may rotate with the tubular string 212 while the tubular string rotates with the drill bit 348. The first seal 216, 218, 220 may remain stationary within the riser string 206 while the tubular string 212 rotates within the first seal. The first seal 216, 218, 220 may be selectively radially extendable into sealing contact with the tubular string 212.
The method may include the step of retrieving on the tubular string 212 the first seal 216, 218, 220 from the riser string 206.
The tubular string 212 may or may not rotate during drilling operations. For example, if a mud motor (which rotates a drill bit on an end of a tubular string in response to circulation of mud or other drilling fluid through the motor) is used, drilling operations can be performed without rotating the tubular string 212. The annular seal modules 222, 224, 226 can seal off the annular space 228 whether or not the tubular string 212 rotates during drilling, completion, stimulation, etc. operations.
While specific embodiments have been shown and described, modifications can be made by one skilled in the art without departing from the spirit or teaching of this invention. The embodiments as described are exemplary only and are not limiting. Many variations and modifications are possible and are within the scope of the invention. Accordingly, the scope of protection is not limited to the embodiments described, but is only limited by the claims that follow, the scope of which shall include all equivalents of the subject matter of the claims.
Of course, a person skilled in the art would, upon a careful consideration of the above description of representative embodiments of the invention, readily appreciate that many modifications, additions, substitutions, deletions, and other changes may be made to the specific embodiments, and such changes are contemplated by the principles of the present invention. Accordingly, the foregoing detailed description is to be clearly understood as being given by way of illustration and example only, the spirit and scope of the present invention being limited solely by the appended claims and their equivalents.
This application is a division of prior application Ser. No. 12/299,411 filed on Jun. 1, 2009, which claims priority to a national stage application under 35 USC §371 of International Application No. PCT/US07/83974 filed on Nov. 7, 2007, which claims the benefit of the filing date of U.S. Provisional Application No. 60/864,712 filed on Nov. 7, 2006. The entire disclosures of these prior applications are incorporated herein by this reference.
Number | Name | Date | Kind |
---|---|---|---|
3362487 | Lindsey | Jan 1968 | A |
3387851 | Cugini | Jun 1968 | A |
3429385 | Jones et al. | Feb 1969 | A |
3443643 | Jones | May 1969 | A |
3552502 | Wilson, Sr. | Jan 1971 | A |
3603409 | Watkins | Sep 1971 | A |
3815673 | Bruce et al. | Jun 1974 | A |
3827511 | Jones | Aug 1974 | A |
3971926 | Gau et al. | Jul 1976 | A |
4046191 | Neath | Sep 1977 | A |
4063602 | Howell et al. | Dec 1977 | A |
4091881 | Maus | May 1978 | A |
4099583 | Maus | Jul 1978 | A |
4194567 | Marais | Mar 1980 | A |
4234043 | Roberts | Nov 1980 | A |
4291772 | Beynet | Sep 1981 | A |
4436157 | Brooks | Mar 1984 | A |
4468056 | Kramer et al. | Aug 1984 | A |
4502534 | Roche et al. | Mar 1985 | A |
4626135 | Roche | Dec 1986 | A |
4682913 | Shatto et al. | Jul 1987 | A |
4685521 | Raulins | Aug 1987 | A |
4813495 | Leach | Mar 1989 | A |
4832126 | Roche | May 1989 | A |
4848473 | Lochte | Jul 1989 | A |
4880060 | Schwendemann et al. | Nov 1989 | A |
5006845 | Calcar et al. | Apr 1991 | A |
5010956 | Bednar | Apr 1991 | A |
5154078 | Codazzi | Oct 1992 | A |
5303582 | Miska | Apr 1994 | A |
5444619 | Hoskins et al. | Aug 1995 | A |
5771971 | Horton et al. | Jun 1998 | A |
5771974 | Stewart et al. | Jun 1998 | A |
5934371 | Bussear et al. | Aug 1999 | A |
6002985 | Stephenson | Dec 1999 | A |
6012015 | Tubel | Jan 2000 | A |
6021377 | Dubinsky et al. | Feb 2000 | A |
6035952 | Bradfield et al. | Mar 2000 | A |
6053252 | Edwards | Apr 2000 | A |
6065550 | Gardes | May 2000 | A |
6101447 | Poe, Jr. | Aug 2000 | A |
6102673 | Mott et al. | Aug 2000 | A |
6125936 | Swisher | Oct 2000 | A |
6138774 | Bourgoyne et al. | Oct 2000 | A |
6173768 | Watson | Jan 2001 | B1 |
6230824 | Peterman et al. | May 2001 | B1 |
6263982 | Hannegan et al. | Jul 2001 | B1 |
6273193 | Hermann et al. | Aug 2001 | B1 |
6325159 | Peterman et al. | Dec 2001 | B1 |
6328107 | Maus | Dec 2001 | B1 |
6450262 | Regan | Sep 2002 | B1 |
6454022 | Sangesland et al. | Sep 2002 | B1 |
6457540 | Gardes | Oct 2002 | B2 |
6470975 | Bourgoyne et al. | Oct 2002 | B1 |
6474422 | Schubert et al. | Nov 2002 | B2 |
6527062 | Elkins et al. | Mar 2003 | B2 |
6571873 | Maus | Jun 2003 | B2 |
6585044 | Rester et al. | Jul 2003 | B2 |
6598682 | Johnson et al. | Jul 2003 | B2 |
6662110 | Bargach et al. | Dec 2003 | B1 |
6668943 | Maus et al. | Dec 2003 | B1 |
6732798 | Johnson et al. | May 2004 | B2 |
6732804 | Hosie et al. | May 2004 | B2 |
6739397 | Ayling | May 2004 | B2 |
6745857 | Gjedebo | Jun 2004 | B2 |
6802379 | Dawson et al. | Oct 2004 | B2 |
6814140 | Robichaux | Nov 2004 | B2 |
6820702 | Niedermayr et al. | Nov 2004 | B2 |
6840322 | Haynes et al. | Jan 2005 | B2 |
6853921 | Thomas et al. | Feb 2005 | B2 |
6854532 | Fincher et al. | Feb 2005 | B2 |
6892812 | Niedermayr et al. | May 2005 | B2 |
6901391 | Storm, Jr. et al. | May 2005 | B2 |
6904981 | Van Riet | Jun 2005 | B2 |
6913092 | Bourgoyne et al. | Jul 2005 | B2 |
6920085 | Finke et al. | Jul 2005 | B2 |
6920942 | Koederitz | Jul 2005 | B2 |
6926101 | DeBoer | Aug 2005 | B2 |
6981561 | Krueger et al. | Jan 2006 | B2 |
7023691 | Feight et al. | Apr 2006 | B1 |
7032691 | Humphreys | Apr 2006 | B2 |
7044237 | Leuchtenberg | May 2006 | B2 |
7055627 | Fontana et al. | Jun 2006 | B2 |
7073591 | Massie et al. | Jul 2006 | B2 |
7079952 | Thomas et al. | Jul 2006 | B2 |
7080685 | Bailey et al. | Jul 2006 | B2 |
7090036 | DeBoer | Aug 2006 | B2 |
7093662 | De Boer | Aug 2006 | B2 |
7096975 | Aronstam et al. | Aug 2006 | B2 |
7114571 | Gatherar et al. | Oct 2006 | B2 |
7134489 | Van Riet | Nov 2006 | B2 |
7158886 | Hou et al. | Jan 2007 | B2 |
7159669 | Bourgoyne et al. | Jan 2007 | B2 |
7165610 | Hopper | Jan 2007 | B2 |
7174975 | Krueger et al. | Feb 2007 | B2 |
7185718 | Gardes | Mar 2007 | B2 |
7185719 | Van Riet | Mar 2007 | B2 |
7201231 | Chaplin et al. | Apr 2007 | B2 |
7207399 | Duhe et al. | Apr 2007 | B2 |
7216715 | Reynolds | May 2007 | B2 |
7237613 | Radi et al. | Jul 2007 | B2 |
7237623 | Hannegan | Jul 2007 | B2 |
7258171 | Bourgoyne et al. | Aug 2007 | B2 |
7264058 | Fossli | Sep 2007 | B2 |
7270185 | Fontana et al. | Sep 2007 | B2 |
7278496 | Leuchtenberg | Oct 2007 | B2 |
7281593 | Steiner et al. | Oct 2007 | B2 |
7331394 | Edwards et al. | Feb 2008 | B2 |
7350597 | Reitsma et al. | Apr 2008 | B2 |
7353887 | Krueger et al. | Apr 2008 | B2 |
7367410 | Sangesland | May 2008 | B2 |
7367411 | Leuchtenberg | May 2008 | B2 |
7395878 | Reitsma | Jul 2008 | B2 |
7407019 | Kinder et al. | Aug 2008 | B2 |
7487837 | Bailey et al. | Feb 2009 | B2 |
7497266 | Fossli | Mar 2009 | B2 |
7513310 | Fossli | Apr 2009 | B2 |
7562723 | Reitsma | Jul 2009 | B2 |
7610251 | Shayegi et al. | Oct 2009 | B2 |
7650950 | Leuchtenberg | Jan 2010 | B2 |
7658228 | Moksvold | Feb 2010 | B2 |
7677329 | Stave | Mar 2010 | B2 |
7708064 | Sehsah | May 2010 | B2 |
7721822 | Krueger | May 2010 | B2 |
7806203 | Krueger et al. | Oct 2010 | B2 |
7913774 | Partouche | Mar 2011 | B2 |
7926593 | Bailey et al. | Apr 2011 | B2 |
7997345 | Hannegan | Aug 2011 | B2 |
8201628 | Lovorn et al. | Jun 2012 | B2 |
8322432 | Bailey et al. | Dec 2012 | B2 |
8397836 | Pool et al. | Mar 2013 | B2 |
20010047885 | Calder | Dec 2001 | A1 |
20010050185 | Calder et al. | Dec 2001 | A1 |
20020011338 | Maurer et al. | Jan 2002 | A1 |
20020092655 | Fincher et al. | Jul 2002 | A1 |
20020108783 | Elkins et al. | Aug 2002 | A1 |
20020112888 | Leuchtenberg | Aug 2002 | A1 |
20030066650 | Fontana et al. | Apr 2003 | A1 |
20030070840 | Boer | Apr 2003 | A1 |
20030079912 | Leuchtenberg | May 2003 | A1 |
20030089498 | Johnson et al. | May 2003 | A1 |
20030098181 | Aronstam et al. | May 2003 | A1 |
20030106712 | Bourgoyne et al. | Jun 2003 | A1 |
20030110017 | Guthrie et al. | Jun 2003 | A1 |
20030111799 | Gilmore | Jun 2003 | A1 |
20030127230 | Von Eberstein, Jr. et al. | Jul 2003 | A1 |
20030139916 | Choe et al. | Jul 2003 | A1 |
20030170077 | Herd et al. | Sep 2003 | A1 |
20030220742 | Niedermayer et al. | Nov 2003 | A1 |
20040040746 | Niedermayer et al. | Mar 2004 | A1 |
20040065440 | Farabee et al. | Apr 2004 | A1 |
20040124008 | Fincher et al. | Jul 2004 | A1 |
20040178001 | Bourgoyne et al. | Sep 2004 | A1 |
20040206548 | Aronstam et al. | Oct 2004 | A1 |
20050061499 | Hopper | Mar 2005 | A1 |
20050061546 | Hannegan | Mar 2005 | A1 |
20050092522 | Humphreys | May 2005 | A1 |
20050092523 | McCaskill et al. | May 2005 | A1 |
20050096848 | Hou et al. | May 2005 | A1 |
20050252286 | Ibrahim et al. | Nov 2005 | A1 |
20060006004 | Terry et al. | Jan 2006 | A1 |
20060021755 | Radi et al. | Feb 2006 | A1 |
20060065402 | Fontana et al. | Mar 2006 | A9 |
20060070772 | De Boer et al. | Apr 2006 | A1 |
20060086538 | Van Riet | Apr 2006 | A1 |
20060100836 | Singh | May 2006 | A1 |
20060102387 | Bourgoyne et al. | May 2006 | A1 |
20060169491 | Fossli | Aug 2006 | A1 |
20060185857 | York et al. | Aug 2006 | A1 |
20060191716 | Humphreys | Aug 2006 | A1 |
20060207795 | Kinder et al. | Sep 2006 | A1 |
20070068704 | Krueger et al. | Mar 2007 | A1 |
20070168056 | Shayegi et al. | Jul 2007 | A1 |
20070240875 | Van Riet | Oct 2007 | A1 |
20070278007 | Krueger et al. | Dec 2007 | A1 |
20080041149 | Leuchtenberg | Feb 2008 | A1 |
20080060846 | Belcher et al. | Mar 2008 | A1 |
20080105434 | Orbell et al. | May 2008 | A1 |
20090101351 | Hannegan | Apr 2009 | A1 |
20090139724 | Gray et al. | Jun 2009 | A1 |
20090211239 | Askeland | Aug 2009 | A1 |
20100018715 | Orbell et al. | Jan 2010 | A1 |
20110024189 | Saeed et al. | Feb 2011 | A1 |
20110139464 | Henderson et al. | Jun 2011 | A1 |
20110139506 | Lovorn et al. | Jun 2011 | A1 |
20110139509 | Pool et al. | Jun 2011 | A1 |
20110214882 | Santos | Sep 2011 | A1 |
20110259612 | Lovorn et al. | Oct 2011 | A1 |
20110290562 | Standifird et al. | Dec 2011 | A1 |
20120061087 | Iblings et al. | Mar 2012 | A1 |
20120103610 | Turner et al. | May 2012 | A1 |
20120168171 | Varpe | Jul 2012 | A1 |
20120186873 | Shayegi et al. | Jul 2012 | A1 |
20120241217 | Davis et al. | Sep 2012 | A1 |
20120242920 | Xu et al. | Sep 2012 | A1 |
20120251407 | Petela et al. | Oct 2012 | A1 |
20120255776 | Knudsen et al. | Oct 2012 | A1 |
20120255777 | Bernard | Oct 2012 | A1 |
20120285744 | Bernard | Nov 2012 | A1 |
Number | Date | Country |
---|---|---|
0881357 | Dec 1998 | EP |
1071862 | Jan 2001 | EP |
1240404 | Sep 2002 | EP |
1240404 | Dec 2003 | EP |
1071862 | Nov 2004 | EP |
1356186 | Jun 2005 | EP |
1664478 | Dec 2005 | EP |
1432887 | Mar 2006 | EP |
1595057 | Jul 2006 | EP |
1488073 | Aug 2006 | EP |
1907664 | Apr 2008 | EP |
1917444 | May 2008 | EP |
1969204 | Sep 2008 | EP |
2053196 | Apr 2009 | EP |
2150681 | Feb 2010 | EP |
2171207 | Apr 2010 | EP |
2179127 | Apr 2010 | EP |
2231997 | Sep 2010 | EP |
2229787 | Oct 1990 | GB |
9942696 | Aug 1999 | WO |
0165060 | Sep 2001 | WO |
2001083941 | Nov 2001 | WO |
2001090528 | Nov 2001 | WO |
0206634 | Jan 2002 | WO |
0244518 | Jun 2002 | WO |
0250398 | Jun 2002 | WO |
03025334 | Mar 2003 | WO |
03025336 | Mar 2003 | WO |
03071091 | Aug 2003 | WO |
2004005667 | Jan 2004 | WO |
2004074627 | Sep 2004 | WO |
2004085788 | Oct 2004 | WO |
2005001237 | Jan 2005 | WO |
2005017308 | Feb 2005 | WO |
2005042917 | May 2005 | WO |
2006029379 | Mar 2006 | WO |
2006031119 | Mar 2006 | WO |
2006099362 | Sep 2006 | WO |
2006118920 | Nov 2006 | WO |
2006138565 | Dec 2006 | WO |
2007008085 | Jan 2007 | WO |
2007016000 | Feb 2007 | WO |
2007030017 | Mar 2007 | WO |
2007112292 | Apr 2007 | WO |
2007081711 | Jul 2007 | WO |
2007124330 | Nov 2007 | WO |
2007126833 | Nov 2007 | WO |
2008133523 | Nov 2008 | WO |
2008134266 | Nov 2008 | WO |
2008151128 | Dec 2008 | WO |
2008156376 | Dec 2008 | WO |
2009017418 | Feb 2009 | WO |
2009018448 | Feb 2009 | WO |
2009058706 | May 2009 | WO |
2009086442 | Jul 2009 | WO |
2009111412 | Sep 2009 | WO |
2009123476 | Oct 2009 | WO |
2010065646 | Jun 2010 | WO |
2010095947 | Aug 2010 | WO |
2011043764 | Apr 2011 | WO |
Entry |
---|
International Search Report with Written Opinion issued 21 Nov. 2011 for PCT Patent Application No. PCT/US11/036616, 13 pages. |
Specification and Drawings for U.S. Appl. No. 13/423,366, filed Mar. 19, 2012, 29 pages. |
US 6,708,780, 3/2004, Bourgoyne et al. (withdrawn). |
Office Action issued Mar. 14, 2012 for U.S. Appl. No. 12/299,411, 36 pages. |
Office Action issued Sep. 16, 2011 for U.S. Appl. No. 12/299,411, 23 pages. |
Office Action issued May 31, 2013 for U.S. Appl. No. 13/542,875, 10 pages. |
IRIS; “Automatic Coordination of Equipment While Circulating out a Kick and Displacing the Kill-Weight Mud,” IADC Well Control Europe, dated 2010, 41 pages. |
Office Action issued Feb. 25, 2011 for U.S. Appl. No. 11/936,411, 66 pages. |
GE Oil & Gas; “Hydril Pressure Control K Pulsation Dampers,” product information, dated Aug. 6, 2010, 2 pages. |
Chinese Office Action issued Feb. 22, 2012 for CN Patent Application No. 200780049409.0, 11 pages. |
Examination Report issued Apr. 12, 2012 for GB Patent Application No. GB1108380.5, 2 pages. |
Singapore Examination Report issued Dec. 27, 2011 for SG Patent Application No. 200903022-2, 8 pages. |
Office Action issued Feb. 7, 2012 for U.S. Appl. No. 13/022,964, 15 pages. |
International Search Report with Written Opinion issued Feb. 8, 2012 for PCT Patent Application No. PCT/US11/031767, 9 pages. |
Office Action issued Jan. 24, 2012 for U.S. Appl. No. 12/638,012, 18 pages. |
International Preliminary Report on Patentability issued May 22, 2009 for PCT Patent Application No. PCT/US07/83974, 13 pages. |
International Search Report and Written Opinion issued Feb. 12, 2009 for PCT Patent Application No. PCT/US08/87686, 7 pages. |
International Search Report ad Written Opinion issued Sep. 22, 2008 for PCT Patent Application No. PCT/US07/83974, 16 pages. |
Singapore Written Opinion issued May 17, 2010 for SG Patent Application No. 2009030222, 10 pages. |
Pre-Interview First Office Action issued Jul. 14, 2010 for U.S. Appl. No. 11/936,411, 14 pages. |
Pre-Interview First Office Action issued Jul. 29, 2010 for U.S. Appl. No. 11/936,411, 3 pages. |
Australian First Official Report issued Oct. 5, 2010 for AU Patent Application No. 2007317276, 2 pages. |
Singapore Office Action issued Feb. 15, 2011 for SG Patent Application No. 200903022, 9 pages. |
Australian Examiner's Report issued Mar. 7, 2011 for AU Patent Application No. 2007317276, 2 pages. |
International Search Report and Written Opinion issued Jun. 17, 2011 for PCT Patent Application No. PCT/US2010/056433, 9 pages. |
International Preliminary Report on Patentability issued Jun. 30, 2011 for PCT Patent Application No. PCT/US2008/087686, 6 pages. |
International Search Report and Written Opinion issued Jul. 27, 2011 for PCT Patent Application No. PCT/US2010/062394, 10 pages. |
Office Action issued Jul. 15, 2013 for U.S. Appl. No. 13/330,059, 13 pages. |
Office Action issued Oct. 18, 2013 for U.S. Appl. No. 13/542,781, 36 pages. |
Office Action issued Oct. 29, 2013 for U.S. Appl. No. 13/542,875, 53 pages. |
Office Action issued Apr. 17, 2013 for U.S. Appl. No. 13/542,781, 10 pages. |
Office Action issued Dec. 5, 2013 for U.S. Appl. No. 13/542,856, 13 pages. |
Office Action issued Feb. 3, 2014 for U.S. Appl. No. 12/299,411, 63 pages. |
Office Action issued Aug. 23, 2012 for U.S. Appl. No. 13/423,366, 19 pages. |
Australian Examination report issued Sep. 28, 2012 for AU Patent Application No. 2008365249, 3 pages. |
Office Action issued Oct. 11, 2012 for U.S. Appl. No. 13/492,688, 17 pages. |
Chinese Office Action issued Nov. 13, 2012 for CN Patent Application No. 200780049409.0, 3 pages. |
English translation of Chinese Office Action issued Nov. 13, 2012 for CN Patent Application No. 200780049409.0, 5 pages. |
Office Action issued Dec. 5, 2012 for U.S. Appl. No. 13/423,366, 27 pages. |
Office Action issued Feb. 27, 2013 for U.S. Appl. No. 13/423,366, 34 pages. |
Canadian Office Action issued Mar. 25, 2013 for CA Patent Application No. 2,765,069, 3 pages. |
Office Action issued Apr. 5, 2013 for U.S. Appl. No. 13/542,892, 12 pages. |
Chinese Office Action issued Apr. 7, 2013 for CN Patent Application No. 200780049409.0, 3 pages. |
English translation of Chinese Office Action issued Apr. 7, 2013 for CN Patent Application No. 200780049409.0, 4 pages. |
Society of Petroleum Engineers, SPE 85310, dated Oct. 20-22, 2003, 12 pages. |
Society of Petroleum Engineers, SPE 72058, dated May 25-26, 2001, 6 pages. |
Shell; “Full-Scale Automated Choke Manifold,” presentation dated Apr. 20, 2005, 22 pages. |
Witold Pedrycz; “From Granular Computing to Computational Intelligence and Human-centric Systems,” IEEE Computational Intelligence Society, May 2005, pp. 6-11, 6 pages. |
@Balance; “Dynamic Annular Pressure Control,” dated 2005, 1 page. |
Nils-Olav Skeie, et al.; “Early detection of Hydrocarbon liquid to surface during MPD operations,” dated 2006, 1 page. |
Press release, “Impact Solutions Group and Drilling Systems Team Up to Offer the Secure DrillingTM Managed Pressure Drilling System to the Industry,” dated Oct. 21, 2004, 2 pages. |
International Preliminary Report on Patentability issued for International Patent Application No. PCT/US07/60001, dated Sep. 12, 2008, 14 pages. |
Office Action issued Mar. 26, 2008 for U.S. Appl. No. 11/333,768, 97 pages. |
Office Action issued Sep. 22, 2008 for U.S. Appl. No. 11/333,768, 72 pages. |
International Search Report with Written Opinion issued for International Patent Application No. PCT/US07/60001, dated Jul. 18, 2008, 15 pages. |
Kishan Mehrotra, et al., “Elements of Artificial Neural Networks,” MIT Press, pp. 70-78, dated 1997, 11 pages. |
Corrado Mencar, “Theory of Fuzzy Information Granulation: Contributions to Interpretability Issues,” University of Bari, pp. 3-8,19, and 211-214, dated Dec. 2004, 12 pages. |
International Search Report with Written Opinion issued Dec. 21, 2011 for PCT Patent Application No. PCT/US11/031790, 15 pages. |
Weatherford International Ltd.; “Weatherford Model 7800 Rotating Control Device”, article No. 4593.00, dated 2007, 5 pages. |
Weatherford International Ltd.; “Model 7875 Rotating Control Device”, article No. 4594.01, dated 2010, 4 pages. |
Hannegan, Don; Weatherford International; “Offshore Drilling Hazard Mitigation: Controlled Pressure Drilling Redefines What is Drillable”, Managed Pressure Drilling Magazine, Drilling Contractor article, dated Jan.-Feb. 2009, 4 pages. |
Smith Services; “Hold 2500 Rotating Control Device”, product brochure, article No. ss-04-0055, dated 2004, 4 pages. |
Smith Services; “Marine Riser RCD”, product presentation, dated Jul. 2009, 18 pages. |
Office Action issued Feb. 7, 2012 for U.S. Appl. No. 13/022,964, 15 page. |
International Preliminary Report on Patentability issued Feb. 9, 2012 for PCT Patent Application No. PCT/US09/052227, 7 pages. |
FAIPP Office Action issued Jul. 14, 2010 for U.S. Appl. No. 11/936,411, 16 pages. |
International Search Report with Written Opinion issued Oct. 13, 2010 for PCT Patent Application No. PCT/US10/020122, 13 pages. |
International Search Report with Written Opinion issued Jan. 25, 2011 for PCT Patent Application No. PCT/US10/032578, 9 pages. |
Office Action issued Nov. 25, 2011 for U.S. Appl. No. 13/084,841, 19 pages. |
International Search Report with Written Opinion issued Dec. 13, 2011 for PCT Patent Application No. PCT/US11/035751, 16 pages. |
Number | Date | Country | |
---|---|---|---|
20120267118 A1 | Oct 2012 | US |
Number | Date | Country | |
---|---|---|---|
60864712 | Nov 2006 | US |
Number | Date | Country | |
---|---|---|---|
Parent | 12299411 | US | |
Child | 13542734 | US |