Patent Grant
8684088
1. Field of the Invention
The present inventions relate to blowout preventers and, in particular, subsea blowout preventers used for the offshore exploration and production of hydrocarbons, such as oil and natural gas. Thus, and in particular, the present inventions relate to novel shear laser modules for subsea blowout preventer stacks and methods of retrofitting existing blowout preventer stacks with these shear laser modules and using such devices to manage and control offshore drilling activities.
As used herein, unless specified otherwise the terms “blowout preventer,” “BOP,” and “BOP stack” are to be given their broadest possible meaning, and include: (i) devices positioned at or near the borehole surface, e.g., the seafloor, which are used to contain or manage pressures or flows associated with a borehole; (ii) devices for containing or managing pressures or flows in a borehole that are associated with a subsea riser; (iii) devices having any number and combination of gates, valves or elastomeric packers for controlling or managing borehole pressures or flows; (iv) a subsea BOP stack, which stack could contain, for example, ram shears, pipe rams, blind rams and annular preventers; and, (v) other such similar combinations and assemblies of flow and pressure management devices to control borehole pressures, flows or both and, in particular, to control or manage emergency flow or pressure situations.
As used herein, unless specified otherwise “offshore” and “offshore drilling activities” and similar such terms are used in their broadest sense and would include drilling activities on, or in, any body of water, whether fresh or salt water, whether manmade or naturally occurring, such as for example rivers, lakes, canals, inland seas, oceans, seas, bays and gulfs, such as the Gulf of Mexico. As used herein, unless specified otherwise the term “offshore drilling rig” is to be given its broadest possible meaning and would include fixed towers, tenders, platforms, barges, jack-ups, floating platforms, drill ships, dynamically positioned drill ships, semi-submersibles and dynamically positioned semi-submersibles. As used herein, unless specified otherwise the term “seafloor” is to be given its broadest possible meaning and would include any surface of the earth that lies under, or is at the bottom of, any body of water, whether fresh or salt water, whether manmade or naturally occurring. As used herein, unless specified otherwise the terms “well” and “borehole” are to be given their broadest possible meaning and include any hole that is bored or otherwise made into the earths surface, e.g., the seafloor or sea bed, and would further include exploratory, production, abandoned, reentered, reworked, and injection wells. As used herein the term “riser” is to be given its broadest possible meaning and would include any tubular that connects a platform at, on or above the surface of a body of water, including an offshore drilling rig, a floating production storage and offloading (“FPSO”) vessel, and a floating gas storage and offloading (“FGSO”) vessel, to a structure at, on, or near the seafloor for the purposes of activities such as drilling, production, workover, service, well service, intervention and completion.
As used herein the term “drill pipe” is to be given its broadest possible meaning and includes all forms of pipe used for drilling activities; and refers to a single section or piece of pipe. As used herein the terms “stand of drill pipe,” “drill pipe stand,” “stand of pipe,” “stand” and similar type terms are to be given their broadest possible meaning and include two, three or four sections of drill pipe that have been connected, e.g., joined together, typically by joints having threaded connections. As used herein the terms “drill string,” “string,” “string of drill pipe,” string of pipe” and similar type terms are to be given their broadest definition and would include a stand or stands joined together for the purpose of being employed in a borehole. Thus, a drill string could include many stands and many hundreds of sections of drill pipe.
As used herein the term “tubular” is to be given its broadest possible meaning and includes drill pipe, casing, riser, coiled tube, composite tube, production tubing, vacuum insulated tubing (VIT) and any similar structures having at least one channel therein that are, or could be used, in the drilling industry. As used herein the term “joint” is to be given its broadest possible meaning and includes all types of devices, systems, methods, structures and components used to connect tubulars together, such as for example, threaded pipe joints and bolted flanges. For drill pipe joints, the joint section typically has a thicker wall than the rest of the drill pipe. As used herein the thickness of the wall of a tubular is the thickness of the material between the internal diameter of the tubular and the external diameter of the tubular.
As used herein, unless specified otherwise “high power laser energy” means a laser beam having at least about 1 kW (kilowatt) of power. As used herein, unless specified otherwise “great distances” means at least about 500 m (meter). As used herein the term “substantial loss of power,” “substantial power loss” and similar such phrases, mean a loss of power of more than about 3.0 dB/km (decibel/kilometer) for a selected wavelength. As used herein the term “substantial power transmission” means at least about 50% transmittance.
2. Discussion of Related Art
Deep Water Drilling
Offshore hydrocarbon exploration and production has been moving to deeper and deeper waters. Today drilling activities at depths of 5000 ft, 10,000 ft and even greater depths are contemplated and carried out. For example, its has been reported by RIGZONE, www.rigzone.com, that there are over 300 rigs rated for drilling in water depths greater than 1,000 ft (feet), and of those rigs there are over 190 rigs rated for drilling in water depths greater than 5,000 ft, and of those rigs over 90 of them are rated for drilling in water depths of 10,000 ft. When drilling at these deep, very-deep and ultra-deep depths the drilling equipment is subject to the extreme conditions found in the depths of the ocean, including great pressures and low temperatures at the seafloor.
Further, these deep water drilling rigs are capable of advancing boreholes that can be 10,000 ft, 20,000 ft, 30,000 ft and even deeper below the sea floor. As such, the drilling equipment, such as drill pipe, casing, risers, and the BOP are subject to substantial forces and extreme conditions. To address these forces and conditions drilling equipment, for example, drill pipe and drill strings, are designed to be stronger, more rugged, and in may cases heavier. Additionally, the metals that are used to make drill pipe and casing have become more ductile.
Typically, and by way of general illustration, in drilling a subsea well an initial borehole is made into the seabed and then subsequent and smaller diameter boreholes are drilled to extend the overall depth of the borehole. Thus, as the overall borehole gets deeper its diameter becomes smaller; resulting in what can be envisioned as a telescoping assembly of holes with the largest diameter hole being at the top of the borehole closest to the surface of the earth.
Thus, by way of example, the starting phases of a subsea drill process may be explained in general as follows. Once the drilling rig is positioned on the surface of the water over the area where drilling is to take place, an initial borehole is made by drilling a 36″ hole in the earth to a depth of about 200-300 ft. below the seafloor. A 30″ casing is inserted into this initial borehole. This 30″ casing may also be called a conductor. The 30″ conductor may or may not be cemented into place. During this drilling operation a riser is generally not used and the cuttings from the borehole, e.g., the earth and other material removed from the borehole by the drilling activity, are returned to the seafloor. Next, a 26″ diameter borehole is drilled within the 30″ casing, extending the depth of the borehole to about 1,000-1,500 ft. This drilling operation may also be conducted without using a riser. A 20″ casing is then inserted into the 30″ conductor and 26″ borehole. This 20″ casing is cemented into place. The 20″ casing has a wellhead secured to it. (In other operations an additional smaller diameter borehole may be drilled, and a smaller diameter casing inserted into that borehole with the wellhead being secured to that smaller diameter casing.) A BOP is then secured to a riser and lowered by the riser to the sea floor; where the BOP is secured to the wellhead. From this point forward all drilling activity in the borehole takes place through the riser and the BOP.
The BOP, along with other equipment and procedures, is used to control and manage pressures and flows in a well. In general, a BOP is a stack of several mechanical devices that have a connected inner cavity extending through these devices. Tubulars are advanced from the offshore drilling rig down the riser, through the BOP cavity and into the borehole. Returns, e.g., drilling mud and cuttings, are removed from the borehole and transmitted through the BOP cavity, up the riser, and to the offshore drilling rig. The BOP stack typically has an annular preventer, which is an expandable packer that functions like a giant sphincter muscle around a tubular. Some annular preventers may also be used or capable of sealing off the cavity when a tubular is not present. When activated, this packer seals against a tubular that is in the BOP cavity, preventing material from flowing through the annulus formed between the outside diameter of the tubular and the wall of the BOP cavity. The BOP stack typically also has a pipe ram preventer and my have more than one of these. Pipe ram preventers typically are two half-circle like clamping devices that are driven against the outside diameter of a tubular that is in the BOP cavity. Pipe ram preventers can be viewed as two giant hands that clamp against the tubular and seal-off the annulus between the tubular and the BOP cavity wall. Blind ram preventers may also be contained in the BOP stack, these rams can seal the cavity when no tubulars are present.
Pipe ram preventers and annular preventers typically can only seal the annulus between a tubular in the BOP and the BOP cavity; they cannot seal-off the tubular. Thus, in emergency situations, e.g., when a “kick” (a sudden influx of gas, fluid, or pressure into the borehole) occurs, or if a potential blowout situation arises, flows from high downhole pressures can come back up through the inside of the tubular, the annulus between the tubular and the riser, and up the riser to the drilling rig. Additionally, in emergency situations, the ram and annular preventers may not be able to form a strong enough seal around the tubular to prevent flow through the annulus between the tubular and the BOP cavity. Thus, BOP stacks include a mechanical shear ram assembly. (As used herein, unless specified otherwise, the term “shear ram” would include blind shear rams, shear sealing rams, shear seal rams, shear rams, and any ram that is intended to, or capable of, cutting or shearing a tubular.) Mechanical shear rams are typically the last line of defense for emergency situations, e.g., kicks or potential blowouts. Mechanical shear rams function like giant gate valves that are supposed to quickly close across the BOP cavity to seal it. They are intended to cut through any tubular is in the BOP cavity that would potentially block the shear ram from completely sealing the BOP cavity.
BOP stacks can have many varied configurations and components, which are dependent upon the conditions and hazards that are expected during deployment and use. These components could include, for example, an annular type preventer, a rotating head, a single ram preventer with one set of rams (blind or pipe), a double ram preventer having two sets of rams, a triple ram type preventer having three sets of rams, and a spool with side outlet connections for choke and kill lines. Examples of existing configurations of these components could be: a BOP stack having a bore of 7 1/16″ and from bottom to top a single ram, a spool, a single ram, a single ram and an annular preventer and having a rated working pressure of 5,000 psi; a BOP stack having a bore of 13⅝″ and from bottom to top a spool, a single ram, a single ram, a single ram and an annular preventer and having a rated working pressure of 10,000 psi; and, a BOP stack having a bore of 18¾″ and from bottom to top, a single ram, a single ram, a single ram, a single ram, an annular preventer and an annular preventer and having a rated working pressure of 15,000 psi.
BOPs need to contain the pressures that could be present in a well, which pressures could be as great as 15,000 psi or greater. Additionally, there is a need for shear rams that are capable of quickly and reliably cutting through any tubular, including drilling collars, pipe joints, and bottom hole assemblies that might be present in the BOP when an emergency situation arises or other situation where it is desirable to cut tubulars in the BOP and seal the well. With the increasing strength, thickness and ductility of tubulars, and in particular tubulars of deep, very-deep and ultra-deep water drilling, there has been an ever increasing need for stronger, more powerful, and better shear rams. This long standing need for such shear rams, as well as, other information about the physics and engineering principles underlying existing mechanical shear rams, is set forth in: West Engineering Services, Inc., “Mini Shear Study for U.S. Minerals Management Services” (Requisition No. 2-1011-1003, December 2002); West Engineering Services, Inc., “Shear Ram Capabilities Study for U.S. Minerals Management Services” (Requisition No. 3-4025-1001, September 2004); and, Barringer & Associates Inc., “Shear Ram Blowout Preventer Forces Required” (Jun. 6, 2010, revised Aug. 8, 2010).
In an attempt to meet these ongoing and increasingly important needs, BOPs have become larger, heavier and more complicated. Thus, BOP stacks having two annular preventers, two shear rams, and six pipe rams have been suggested. These BOPs can weigh many hundreds of tons and stand 50 feet tall, or taller. The ever-increasing size and weight of BOPs presents significant problems, however, for older drilling rigs. Many of the existing offshore rigs do not have the deck space, lifting capacity, or for other reasons, the ability to handle and use these larger more complicated BOP stacks.
High Power Laser Beam Conveyance
Prior to the recent breakthroughs of co-inventor Dr. Mark Zediker and those working with him at Foro Energy, Inc., Littleton Colo., it was believed that the transmission of high power laser energy over great distances without substantial loss of power was unobtainable. Their breakthroughs in the transmission of high power laser energy, and in particular in power levels greater than 5 kW, are set forth, in part, in the novel and innovative teachings contained in US patent application publications 2010/0044106 and 2010/0215326 and in Rinzler et. al, pending U.S. patent application Ser. No. 12/840,978 titled “Optical Fiber Configurations for Transmission of Laser Energy Over Great Distances” (filed Jul. 21, 2010). The disclosures of these three US patent applications, to the extent that they refer or relate to the transmission of high power laser energy, and lasers, fibers and cable structures for accomplishing such transmissions, are incorporated herein by reference. It is to be noted that this incorporation by reference herein does not provide any right to practice or use the inventions of these applications or any patents that may issue therefrom and does not grant, or give rise to, any licenses thereunder.
The utilization and application of high power lasers to BOP and risers is set forth in U.S. patent application Ser. Nos. 13/034,175, 13/034,017 and 13/034,037, filed concurrently herewith, the entire disclosures of which are incorporated herein by reference.
In drilling operations it has long been desirable to have a BOP that has the ability to quickly, reliably, and in a controlled manner sever tubulars and seal off, or otherwise manage the pressure, flow or both of a well. As the robustness of tubulars, and in particular tubulars for deep sea drilling, has increased, the need for such a BOP has continued, grown and become more important. The present invention, among other things, solves this need by providing the articles of manufacture, devices and processes taught herein.
Thus, there is provided herein a blowout preventer stack for land based operations, sea based operations, or both having a ram preventer, an annular preventer, and a shear laser module. The blowout preventer may also be configured such that its annular preventer, ram preventer, and shear laser module have a common cavity, which has a cavity axis. The blowout preventer stack's shear laser module can also have a laser cutter having a beam path that extends from the laser cutter into the common cavity and in some instances, where the beam path intersects the cavity axis.
There is also provided a shear laser module for use in a blowout preventer stack, this module has a body, the body which has a first connector and a second connector, the connectors adapted for connection to components in a blowout preventer stack, the body having a cavity for passing tubulars, line structures or both, through the cavity; and, a laser cutter in the body which laser cutter has a beam path. In this manner, the beam path may travel from the laser cutter into the cavity and to any tubular that may be in the cavity.
Still further it is provided that the shear laser module and laser cutter may have a shield located adjacent to the cavity, which shield protects the laser cutter from damage from the conditions present in the blowout preventer cavity, such as pressure, temperature, tubular or line structures moving through or rotating within the cavity, cuttings, hydrocarbons, and drilling fluids, while not appreciably interfering with the movement of tubulars and other structures or materials through the cavity.
Yet further it is provided that the ram preventer can be a shear ram and that the blowout preventer can also have a second annular preventer, a second shear ram, a first pipe ram, a second pipe ram, and a third pipe ram.
Moreover, it is provided that the blowout preventer and laser shear module can have a plurality of laser cutters, which can include a first and a second laser cutter, wherein the first laser cutter has a first beam path that extends from the first laser cutter into the cavity, wherein the second laser cutter has a second beam path that extends from the second laser cutter into the cavity. Additionally, the first, the second or both beam paths can intersect within the cavity, can be directed toward the cavity axis and can intersect the cavity axis. Further, the first and second beam paths may not intersect within the cavity and they may be substantially parallel, they may form a normal angle with a central axis of the cavity, which angle can be an obtuse angle with the axis, an acute angle with the axis, or be a right angle.
There is further provided a blowout preventer in which a second annular preventer, a second shear ram, a first pipe ram, a second pipe ram, and a third pipe ram are present.
Still further it is provided that the blowout preventer or laser shear module may have first and second laser cutters that are configured to rotate around the blowout preventer cavity upon activation, orbit at least partially around the cavity during activation, and may be positioned outside of the cavity, or adjacent to the cavity.
Yet further there is provided a shear laser module having a support cable optically associated with the laser cutter and a feed-through assembly mechanically associated with the support cable. The modules may be rated at greater than 5,000 psi operating pressure, greater than 10,000 psi operating pressure, or greater than 15,000 psi operating pressure.
There is also provided an offshore drilling rig having a laser assisted subsea blowout drilling system, for performing activities near a seafloor, the system having a riser capable of being lowered from and operably connected to an offshore drilling rig to a depth at or near the seafloor; a blowout preventer capable of being operably connected to the riser and lowered by the riser from the offshore drilling rig to the seafloor; the blowout preventer including a shear laser module and a ram preventer; the shear laser module including a laser cutter; a high power laser in optical communication with the laser cutter; and, the laser cutter being operably associated with the blowout preventer and riser, whereby the laser cutter is capable of being lowered to at or near the seafloor and upon activation delivering a high power laser beam to a tubular that is within the blowout preventer.
Yet further there is provided a method of retrofitting a pre-existing blowout preventer (“BOP”) stack with a shear laser module to make a laser assisted BOP stack, the method having the following activities: evaluating a pre-existing BOP stack; determining that the pre-existing BOP stack does not meet the requirements for an intended potential use; and retrofitting the pre-existing BOP stack by adding a shear laser module to the pre-existing BOP stack; whereby the retrofitted BOP stack meets the requirements for the intended use.
Still further there is provided a method of making a laser assisted BOP stack, wherein there is obtained an annular preventer, a ram preventer, a shear laser module and assembling a BOP stack including the annular preventer, the ram preventer and the shear laser module.
Additionally, there is provided a method of drilling subsea wells by using a laser assisted blowout preventer and riser, the method including lowering a laser assisted blowout preventer from an offshore drilling rig to a seafloor using a riser, wherein the riser has an inner cavity, and wherein the laser assisted blowout preventer includes a shear laser module having an inner cavity; securing the blowout preventer to a borehole in the seafloor, by way for example to a wellhead, whereby the borehole, the shear laser module cavity and the riser cavity are in fluid and mechanical communication; and, wherein, the shear laser module has the capability to perform laser cutting of a tubular present in the laser assisted blowout preventer cavity.
Moreover there is provided a method of drilling subsea wells by using a laser assisted blowout preventer and riser, the method including lowering a laser assisted blowout preventer, the laser assisted blowout preventer including a shear laser module having an inner cavity, from an offshore drilling rig to the seafloor using a riser having an inner cavity; securing the blowout preventer to a wellhead atop a borehole, whereby the borehole, the shear laser module cavity and the riser cavity are in fluid and mechanical communication; and, advancing the borehole by lowering tubulars from the offshore drilling rig down through the riser cavity, the shear laser module cavity and into the borehole; wherein, the shear laser module has the capability to perform laser cutting of any tubular present in the laser assisted blowout preventer cavity.
Yet additionally there is provided a subsea tree having a mechanical valve and a laser cutter, wherein the mechanical valve can be a flapper valve or a ball valve. The subsea tree may further have an outer wall, configured to be placed adjacent to a BOP cavity wall; an inner wall, defining a subsea tree inner cavity; and, the inner and outer walls defining an annular area therebetween; wherein the laser cutter is contained substantially within the annulus defined by the inner and outer walls. Still further a beam path may be defined between an area adjacent to area of operation for the mechanical valve and the laser cutter.
Further, there is provided a method of performing work on a subsea well by using high power laser assisted technology, including lowering a blowout preventer having an interior cavity, from an offshore drilling rig to a seafloor; securing the blowout preventer to a borehole in the seafloor, for example by securing to a christmas tree or by removing the christmas tree and securing to a well head, whereby the borehole and the interior cavity are in fluid and mechanical communication; positioning within the blowout preventer cavity a subsea test tree having an inner cavity and including a laser cutter; and, lowering tubulars or line structures from the offshore drilling rig down through the inner cavity of the subsea test tree; wherein, the subsea test tree has the capability to perform laser cutting of any tubular or line structure present in the inner cavity of the subsea test tree. Still further a blowout preventer having a laser shear module that may be capable of cutting the subsea tree may also be used.
In general, the present inventions relate to shear laser modules for BOP stacks and a BOP stack having high power laser beam cutters. These BOP stacks are used to manage the conditions of a well, such as pressure, flow or both. Thus, by way of example, an embodiment of a laser assisted subsea BOP drilling system is schematically shown in
The laser assisted riser and BOP package 150 has a riser 105 and a laser assisted BOP stack 108. The upper portion, i.e., the portion of the riser when deployed that is closest to the surface of the water 104, of riser 105, is connected to the drillship 100 by tensioners 103 that are attached to tension ring 102. The upper section of the riser 105 may have a diverter 101 and other components (not shown in this figure) that are commonly utilized and employed with risers and are well known to those of skill in the art of offshore drilling.
The riser 105 extends from the moon pool 130 of drill ship 100 and is connected to laser assisted BOP stack 108. The riser 105 is made up of riser sections, e.g., 106, that are connected together, by riser couplings, e.g., 107, and lowered through the moon pool 130 of the drill ship 100. The lower portion, i.e., the portion of the riser that when deployed is closest to the seafloor, of the riser 105 is connected to the laser assisted BOP stack 108 by way of the riser-BOP connecter 111. The riser-BOP connecter 111 is associated with flex joint 112, which may also be referred to as a flex connection or ball joint. The flex joint 112 is intended to accommodate movements of the drill ship 100 from positions that are not directly above the laser assisted BOP stack 108; and thus accommodate the riser 105 coming into the laser assisted BOP stack 108 at an angle.
The laser assisted BOP stack may be characterized as having two component assemblies: an upper component assembly 109, which may be referred to as the lower marine riser package (LMRP), and a lower component assembly 110, which may be referred to as the lower BOP stack or the BOP proper. In this embodiment, the upper component assembly 109 has a frame 113 that houses an annular preventer 115. The lower component assembly 110 has a frame 114 that houses an annular preventer 116, a shear laser module (“SLM”) 117, a first ram preventer 118, a second ram preventer 119, and a third ram preventer 120. As used herein unless specified otherwise, the term “ram preventer” is to be given its broadest definition and would include any mechanical devices that clamp, grab, hold, cut, sever, crush, or combinations thereof, a tubular within a BOP stack, such as shear rams, blind rams, blind-shear rams, pipe rams, casing shear rams, and ram blowout preventers such as Hydril's HYDRIL PRESSURE CONTROL COMPACT Ram, Hydril Pressure Control Conventional Ram, HYDRIL PRESSURE CONTROL QUICK-LOG, and HYDRIL PRESSURE CONTROL SENTRY Workover, SHAFFER ram preventers, and ram preventers made by Cameron. The laser assisted BOP stack 108 has a wellhead connecter 121 that attaches to wellhead 122, which is attached to borehole 124.
The riser has an internal cavity, not shown in
Typically, in deep sea drilling operations a 21″ riser and an 18¾″ BOP are used. The term “21″ riser” is generic and covers risers having an outer diameter in the general range of 21″ and would include for example a riser having a 21¼″ outer diameter. Wall thickness for 21″ risers can range of from about ⅝″ to ⅞″ or greater. Risers and BOPs, however, can vary in size, type and configuration. Risers can have outer diameters ranging from about 13⅜″ to about 24.″ BOP's can have cavities, e.g., bore diameters ranging from about 4⅙″ to 26¾.″ Risers may be, for example, conventional pipe risers, flexible pipe risers, composite tube structures, steel cantenary risers (“SCR”), top tensioned risers, hybrid risers, and other types of risers known to those skilled in the offshore drilling arts or later developed. The use of smaller and larger diameter risers, different types and configurations of risers, BOPs having smaller and larger diameter cavities, and different types and configurations of BOPs, are contemplated; and, the teachings and inventions of this specification are not limited to, or by, the size, type or configuration of a particular riser or BOP.
During deployment the laser assisted BOP stack 108 is attached to the riser 105, lowered to the seafloor 123 and secured to a wellhead 122. The wellhead 122 is positioned and fixed to a casing (not shown), which has been cemented into a borehole 124. From this point forward, generally, all the drilling activity in the borehole takes place through the riser and the BOP. Such drilling activity would include, for example, lowering a string of drill pipe having a drill bit at its end from the drill ship 100 down the interior cavity of the riser 105, through the cavity of the laser assisted BOP stack 108 and into the borehole 124. Thus, the drill string would run from the drill ship 100 on the surface of the water 104 to the bottom of the borehole, potentially many tens of thousands of feet below the water surface 104 and seafloor 123. The drill bit would be rotated against the bottom of the borehole, while drilling mud is pumped down the interior of the drill pipe and out the drill bit. The drilling mud would carry the cuttings, e.g., borehole material removed by the rotating bit, up the annulus between the borehole wall and the outer diameter of the drill string, continuing up through the annulus between BOP cavity wall and the outer diameter of the drill string, and continuing up through the annulus between the inner diameter of the riser cavity and the outer diameter of the drill string, until the drilling mud and cuttings are directed, generally by a bell housing (not shown), or in extreme situations a diverter 101, to the drill ship 100 for handling or processing. Thus, the drilling mud is pumped from the drill ship 100 through a drill string in the riser to the bottom of the borehole and returned to the drill ship, in part, by the laser assisted riser and BOP package 150.
Turning now to
The top 825 of the laser assisted BOP 800 is secured to a riser 816 by a flex joint 815. The flex joint 815, which may also be referred to as a flex connecter or ball joint, allows the riser 816 to be at an angle with respect to the laser assisted BOP 800, and thus, accommodates some movement of the riser 816 and the drilling rig 818 on the surface of the water 824. The riser 816 is connected to the drilling rig 818 by riser tensioners 817, and other equipment known to those of skill in the offshore drilling arts, but not shown in this figure. The drilling rig 818, which in this example is shown as a semi-submersible, but could be any type of platform or device for drilling in or above water, has a moon pool 819, a drill floor 820, a derrick 821, and other drilling and drilling sport equipment and devices utilized for operation, which are known to the offshore drilling arts, but are not shown in the figure.
When deployed, as shown in
Thus, by way of example, casing 814 can be 20″ casing and borehole 812 can be a 26″ diameter borehole, casing 811 can be 30″ casing and borehole 809 can be a 36″ diameter borehole. From this point forward, generally, all the drilling activity in the borehole takes place through the riser and the BOP.
In
In
As noted above in this specification, older BOPs, such as the pre-existing BOP stack shown in
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In addition to the forging examples of retrofit BOP stacks other configurations and arrangements are contemplated. For example, pre-existing ram shears may be replaced with a shear laser module or multiple shear laser modules, a combination of shear rams and shear laser modules may be added, a shear laser ram assembly may be added, multiple laser modules may be added and combinations of the forgoing may be done as part of a retrofitting process to obtain a retrofitted laser assisted BOP stack. Additionally, larger and newer BOP stacks may also obtain benefits by having a shear laser module added to the stacks components.
The present specification, however, is not limited to retrofitting of pre-existing BOPs. The specification also contemplates laser assisted BOP stacks, whether made form new, refurbished or pre-existing components or materials.
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In
The laser assisted BOP stacks of the present inventions may be used to control and manage both pressures and flows in a well; and may be used to manage and control emergency situations, such as a potential blowout. In addition to the shear laser module, the laser assisted BOP stacks may have an annular preventer. The annular preventers may have an expandable packer that seals against a tubular that is in the BOP cavity preventing material from flowing through the annulus formed between the outside diameter of the tubular and the inner cavity wall of the laser assisted BOP. In addition to the shear laser module, the laser assisted BOP stacks may have ram preventers. The ram preventers may be, for example: pipe rams, which may have two half-circle like clamping devices that are driven against the outside diameter of a tubular that is in the BOP cavity; blind rams that can seal the cavity when no tubulars are present, or they may be a shear rams that can cut tubulars and seal off the BOP cavity; or they may be a laser shear ram assembly. In general, laser shear rams assemblies use a laser beam to cut or weaken a tubular, including drilling collars, pipe joints, and bottom hole assemblies that might be present in the BOP cavity, which are disclosed in co-filed application Ser. No. 13/047,175.
Laser assisted subsea BOP drilling systems, and in particular the shear laser modules, may utilize a single high power laser, and preferably may have two or three high power lasers, and may have several high power lasers, for example, six or more. High power solid-state lasers, specifically semiconductor lasers and fiber lasers are preferred, because of their short start up time and essentially instant-on capabilities. The high power lasers for example may be fiber lasers or semiconductor lasers having 10 kW, 20 kW, 50 kW or more power and, which emit laser beams with wavelengths preferably in about the 1550 nm (nanometer), or 1083 nm ranges. Examples of preferred lasers, and in particular solid-state lasers, such as fiber lasers, are set forth in US patent application publications 2010/0044106 and 2010/0215326 and in pending U.S. patent application Ser. No. 12/840,978. The laser, or lasers, may be located on the offshore drilling rig, above the surface of the water, and optically connected to the BOP on the seafloor by way of a high power long distance laser transmission cable, preferred examples of which are set forth in US patent application publications 2010/0044106 and 2010/0215326 and in pending U.S. patent application Ser. No. 12/840,978. The laser transmission cable may be contained in a spool and unwound and attached to the BOP and riser as they are lowered to the seafloor. The lasers may also be contained in, or associated with, the BOP frame, eliminating the need for a long distance of high power optical cable to transmit the laser beam from the surface of the water down to the seafloor. In view of the extreme conditions in which the shear laser modules and laser shear rams are required to operate and the need for high reliability in their operation, one such configuration of a laser assisted subsea BOP drilling systems is to have at least one high power laser located on the offshore drilling rig and connect to the BOP by a high power transmission cable and to have at least one laser in, or associated with, the BOP frame on the seafloor.
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Turning to
The embodiment of
During drilling and other activities, tubulars are typically positioned within the BOP inner cavity. An annulus is formed between the outer diameter of the tubular and the inner cavity wall. These tubulars have an outer diameter that can range in size from about 18″ down to a few inches, and in particular, typically range from about 16⅖ (16.04)″ to about 5″, or smaller. When tubulars are present in the cavity, upon activation of the SLM, the laser delivery assembly delivers high power laser energy to the tubular located in the cavity. The high power laser energy cuts the tubular completely permitting the tubular to be moved or dropped away from the rams or annular preventers in the stack, permitting the BOP to quickly seal off the inner BOP cavity, and thus the well, without any interference from the tubular.
Although a single laser delivery assembly is shown in the examples of the embodiments of
The body of the SLM may be a single piece that is machined to accommodate the laser delivery assembly, or it may be made from multiple pieces that are fixed together in a manner that provides sufficient strength for its intend use, and in particular to withstand pressures of 5,000 psi, 10,000 psi, 15,000 psi, 20,000 psi, and greater. The area of the body that contains the laser delivery assembly may be machined out, or otherwise fabricated to accommodate the laser delivery assembly, while maintaining the strength requirements for the body's intended use. The body of the SLM may also be two or more separate components or parts, e.g., one component for the upper half and one for the lower half. These components could be attached to each other by, for example, bolted flanges, or other suitable attachment means known to one of skill in the offshore drilling arts. The body, or a module making up the body, may have a passage, passages, channels, or other such structures, to convey fiber optic cables for transmission of the laser beam from the laser source into the body and to the laser delivery assembly, as well as, other cables that relate to the operation or monitoring of the laser delivery assembly and its cutting operation.
Turning to
The body 1001 contains laser delivery assembly 1009. There is also shown a tubular 1012 in the cavity 1004. The body 1001 also has a feed-through assembly 1013 for managing pressure and permitting optical fiber cables and other cables, tubes, wires and conveyance means, which may be needed for the operation of the laser cutter, to be inserted into the body 1001. The feed-through assembly 1013 connects with conduit 1038 for conveyance to a high power laser, or other sources of materials for the cutting operation.
If the cavity 1004 is viewed as the face of a clock, the laser cutters 1026, 1027, 1028 and 1029 could be viewed as being initially positioned at 12 o'clock, 9 o'clock, 6 o'clock and 3 o'clock, respectively. Upon activation, the laser cutters and their respective laser beams, begin to orbit around the center axis 1011, and the tubular 1012. (In this configuration the laser cutters would also rotate about their own axis as they orbit, and thus, if they moved through one complete orbit they would also have moved through one complete rotation.) In the present example the cutters and beams orbit in a counter clockwise direction, as viewed in the figures; however, a clockwise rotation may also be used.
Thus, as seen in the next view of the sequence,
During the cutting operation, and in particular for circular cuts that are intended to sever the tubular, it is preferable that the tubular not move in a vertical direction. Thus, at or before the laser cutters are fired, the pipe rams, the annular preventer, or a separate holding device should be activated to prevent vertical movement of the pipe during the laser cutting operation. The separate holding device could also be contained in the SLM.
The rate of the orbital movement of the laser cutters is dependent upon the number of cutters used, the power of the laser beam when it strikes the surface of the tubular to be cut, the thickness of the tubular to be cut, and the rate at which the laser cuts the tubular. The rate of the orbital motion should be slow enough to ensure that the intended cuts can be completed.
In addition to orbiting cutters, the laser beam can be scanned, e.g., moved in a fan like pattern. In this manner the beam path would be scanned along the area to be cut, e.g., an area of a tubular, while the cutter, or at least the base of the cutter, remained in a fixed position. This scanning of the laser beam can be accomplished, for example, by moving the cutter back and forth about a fixed point, e.g., like the movement of an oscillating fan. It may also be accomplished by having optics contained within the cutter that scans the beam path, e.g., a laser scanner, and thus the laser beam in the fan like pattern. For example a multi-faceted mirror or prim that is rotated may be utilized as a scanner. It should be noted, however, that scanning processes in general might be less efficient the other cutting approaches provided in this specification. Additional scanning patterns for the beam path and laser beam many also be employed to accomplished or address a specific cutting application or tubular configuration in a BOP cavity.
The orbital or other movement of the laser cutters can be accomplished by mechanical, hydraulic and electro-mechanical systems known to the art. For example, the cutters can be mounted to step motors that are powered by batteries, in the BOP, electrical cables from the surface, or both. The step motors may further have controllers associated with them, which controllers can be configured to control the step motors to perform specific movements corresponding to specific cutting steps. Cam operated systems may be employed to move the cutters through a cutting motion or cycle. The cams may be driven by electric motors, hydraulic motors, hydraulic pistons, or combinations of the forgoing, to preferably provide for back up systems to move the cutters, should one motive means fail. A gearbox, a rack gear assembly, or combinations there of may be utilized to provide cutter movement, in conjunction with an electric motor, hydraulic motor or piston assembly. The control system may be integral to the cutter motive means, such as a step motor control combination, may be part of the BOP, such as being contained with the other control system on the BOP, or it may be on the rig, or combinations of the forgoing.
The use of the term “completed” cut, and similar such terms, includes severing the tubular into two sections, i.e., a cut that is all the way through the wall and around the entire circumference of the tubular, as well as, cuts in which enough material is removed from the tubular to sufficiently weaken the tubular to ensure that the shear rams are in sealing engagement. Depending upon the particular configuration of the SLM, the laser assisted BOP stack, and the BOP's intended use, a completed cut could be, for example: severing the tubular into two separate sections; the removal of a ring of material around the outer portion of the tubular, from about 10% to about 90% of the wall thickness; a number of perforations created in the wall, but not extending through the wall of the tubular; a number of perforations going completely through the wall of the tubular; a number of slits created in the wall, but not extending through the wall of the tubular; a number of slits going completely through the wall of the tubular; the material removed by the shot patterns disclosed in this specification; or, other patterns of material removal and combinations of the foregoing. It is preferred that the complete cut is made in less than one minute, and more preferable that the complete cut be made in 30 seconds or less.
The rate of the orbital motion can be fixed at the rate needed to complete a cut for the most extreme tubular or combination of tubulars, or the rate of rotation could be variable, or predetermined, to match the particular tubular, or types of tubulars, that will be present in the BOP during a particular drilling operation.
The greater the number of laser cutters in a rotating laser delivery assembly, the slower the rate of orbital motion can be to complete a cut in the same amount of time. Further, increasing the number of laser cutters decreases the time to complete a cut of a tubular, without having to increase the orbital rate. Increasing the power of the laser beams will enable quicker cutting of tubulars, and thus allow faster rates of orbiting, fewer laser cutters, shorter time to complete a cut, or combinations thereof.
The laser cutters used in the examples and illustrations of the embodiments of the present inventions may be any suitable device for the delivery of high power laser energy. Thus, any configuration of optical elements for culminating and focusing the laser beam can be employed. A further consideration, however, is the management of the optical effects of fluids and materials that may be located within the annulus between the tubular and the BOP inner cavity wall.
Such drilling fluids could include, by way of example, water, seawater, salt water, brine, drilling mud, nitrogen, inert gas, diesel, mist, foam, or hydrocarbons. There can also likely be present in these drilling fluids borehole cuttings, e.g., debris, which are being removed from, or created by, the advancement of the borehole or other downhole operations. There can be present two-phase fluids and three-phase fluids, which would constitute mixtures of two or three different types of material. These drilling fluids can interfere with the ability of the laser beam to cut the tubular. Such fluids may not transmit, or may only partially transmit, the laser beam, and thus, interfere with, or reduce the power of, the laser beam when the laser beam is passed through them. If these fluids are flowing, such flow may further increase their non-transmissiveness. The non-transmissiveness and partial-transmissiveness of these fluids can result from several phenomena, including without limitation, absorption, refraction and scattering. Further, the non-transmissiveness and partial-transmissiveness can be, and likely will be, dependent upon the wavelength of the laser beam.
In an 18¾″ BOP, i.e., the cavity has a diameter of about 18¾,″ depending upon the configuration of the laser cutters and the size of the tubular in the cavity, the laser beam could be required to pass through over 6″ of drilling fluids. In other configurations the laser cutters may be positioned in close, or very close, proximity to the tubular to be cut and moved in a manner where this close proximity is maintained. In these configurations the distance for the laser beam to travel between the laser cutters and the tubular to be cut may be maintained within about 2″, less than about 2″, less than about 1″ and less than about ½″, and maintained within the ranges of less than about 3″ to less than about ½″, and less than about 2″ to less than about ½″.
In particular, for those configurations and embodiments where the laser has a relatively long distance to travel, e.g., greater than about 1″ or 2″ (although this distance could be more or less depending upon laser power, wavelength and type of drilling fluid, as well as, other factors) it is advantageous to minimize the detrimental effects of such borehole fluids and to substantially ensure, or ensure, that such fluids do not interfere with the transmission of the laser beam, or that sufficient laser power is used to overcome any losses that may occur from transmitting the laser beam through such fluids. To this end, mechanical, pressure and jet type systems may be utilized to reduce, minimize or substantially eliminate the effect of the drilling fluids on the laser beam.
For example, mechanical devices such as packers and rams, including the annular preventer, may be used to isolate the area where the laser cut is to be performed and the drilling fluid removed from this area of isolation, by way of example, through the insertion of an inert gas, or an optically transmissive fluid, such as an oil or diesel fuel. The use of a fluid in this configuration has the added advantage that it is essentially incompressible. Moreover, a mechanical snorkel like device, or tube, which is filled with an optically transmissive fluid (gas or liquid) may be extended between or otherwise placed in the area between the laser cutter and the tubular to be cut. In this manner the laser beam is transmitted through the snorkel or tube to the tubular.
A jet of high-pressure gas may be used with the laser cutter and laser beam. The high-pressure gas jet may be used to clear a path, or partial path for the laser beam. The gas may be inert, or it may be air, oxygen, or other type of gas that accelerates the laser cutting. The relatively small amount of oxygen needed, and the rapid rate at which it would be consumed by the burning of the tubular through the laser-metal-oxygen interaction, should not present a fire hazard or risk to the drilling rig, surface equipment, personnel, or subsea components.
The use of oxygen, air, or the use of very high power laser beams, e.g., greater than about 1 kW, could create and maintain a plasma bubble or a gas bubble in the cutting area, which could partially or completely displace the drilling fluid in the path of the laser beam.
A high-pressure laser liquid jet, having a single liquid stream, may be used with the laser cutter and laser beam. The liquid used for the jet should be transmissive, or at least substantially transmissive, to the laser beam. In this type of jet laser beam combination the laser beam may be coaxial with the jet. This configuration, however, has the disadvantage and problem that the fluid jet does not act as a waveguide. A further disadvantage and problem with this single jet configuration is that the jet must provide both the force to keep the drilling fluid away from the laser beam and be the medium for transmitting the beam.
A compound fluid laser jet may be used as a laser cutter. The compound fluid jet has an inner core jet that is surrounded by annular outer jets. The laser beam is directed by optics into the core jet and transmitted by the core jet, which functions as a waveguide. A single annular jet can surround the core, or a plurality of nested annular jets can be employed. As such, the compound fluid jet has a core jet. This core jet is surrounded by a first annular jet. This first annular jet can also be surrounded by a second annular jet; and the second annular jet can be surrounded by a third annular jet, which can be surrounded by additional annular jets. The outer annular jets function to protect the inner core jet from the drill fluid present in the annulus between the BOP cavity wall and the tubular. The core jet and the first annular jet should be made from fluids that have different indices of refraction. In the situation where the compound jet has only a core and an annular jet surrounding the core the index of refraction of the fluid making up the core should be greater than the index of refraction of the fluid making up the annular jet. In this way, the difference in indices of refraction enable the core of the compound fluid jet to function as a waveguide, keeping the laser beam contained within the core jet and transmitting the laser beam in the core jet. Further, in this configuration the laser beam does not appreciably, if at all, leave the core jet and enter the annular jet.
The pressure and the speed of the various jets that make up the compound fluid jet can vary depending upon the applications and use environment. Thus, by way of example the pressure can range from about 3000 psi, to about 4000 psi to about 30,000 psi, to preferably about 70,000 psi, to greater pressures. The core jet and the annular jet(s) may be the same pressure, or different pressures, the core jet may be higher pressure or the annular jets may be higher pressure. Preferably the core jet is higher pressure than the annular jet. By way of example, in a multi-jet configuration the core jet could be 70,000 psi, the second annular jet (which is positioned adjacent the core and the third annular jet) could be 60,000 psi and the third (outer, which is positioned adjacent the second annular jet and is in contact with the work environment medium) annular jet could be 50,000 psi. The speed of the jets can be the same or different. Thus, the speed of the core jet can be greater than the speed of the annular jet, the speed of the annular jet can be greater than the speed of the core jet and the speeds of multiple annular jets can be different or the same. The speeds of the core jet and the annular jet can be selected, such that the core jet does contact the drilling fluid, or such contact is minimized. The speeds of the jet can range from relatively slow to very fast and preferably range from about 1 ms (meters/second) to about 50 m/s, to about 200 m/s, to about 300 m/s and greater The order in which the jets are first formed can be the core jet first, followed by the annular rings, the annular ring jet first followed by the core, or the core jet and the annular ring being formed simultaneously. To minimize, or eliminate, the interaction of the core with the drilling fluid, the annular jet is created first followed by the core jet.
In selecting the fluids for forming the jets and in determining the amount of the difference in the indices of refraction for the fluids the wavelength of the laser beam and the power of the laser beam are factors that should be considered. Thus, for example for a high power laser beam having a wavelength in the 1080 nm (nanometer) range the core jet can be made from an oil having an index of refraction of about 1.53 and the annular jet can be made from a mixture of oil and water having an index of refraction from about 1.33 to about 1.525. Thus, the core jet for this configuration would have an NA (numerical aperture) from about 0.95 to about 0.12, respectively. Further details, descriptions, and examples of such compound fluid laser jets are contained in Zediker et. al, Provisional U.S. Patent Application Ser. No. 61/378,910, titled Waveguide Laser Jet and Methods of Use, filed Aug. 31, 2010, the entire disclosure of which is incorporated herein by reference. It is to be noted that said incorporation by reference herein does not provide any right to practice or use the inventions of said application or any patents that may issue therefrom and does not grant, or give rise to, any licenses thereunder.
The laser cutters have a discharge end from which the laser beam is propagated. The laser cutters also have a beam path. The beam path is defined by the path that the laser beam is intended to take, and extends from the discharge end of the laser cutter to the material or area to be cut. Preferably, the beam path(s) may be configured to provide a completed cut at the area where the mechanical forces for the shear rams, the tension that the tubular may be under, or both, are the greatest. In this way, the likelihood that unwanted material may be left in the ram interface to obstruct or inhibit the sealing of the rams is reduced or eliminated. As described herein, other laser cutter placements, firing sequences, shear arrangements, or combinations of thereof, also address this issue of providing greater assurances that the rams enter into sealing engagement.
The angle at which the laser beam contacts the tubular may be determined by the optics within the laser cutter or it may be determined by the angle or positioning of the laser cutter itself. In
The angle between the beam path (and a laser beam traveling along that beam path) and the BOP vertical axis, corresponds generally to the angle at which the beam path and the laser beam will strike a tubular that is present in the BOP cavity. However, using a reference point that is based upon the BOP to determine the angle is preferred, because tubulars may shift or in the case of joints, or a damaged tubular, present a surface that has varying planes that are not parallel to the BOP cavity center axis.
Because the angle formed between the laser beam and the BOP vertical axis can vary, and be predetermined, the laser cutter's position, or more specifically the point where the laser beam leaves the cutter does not necessarily have to be normal to the area to be cut. Thus, the laser cutter position or the beam launch angle can be such that the laser beam travels from: above the area to be cut, which would result in an acute angle being formed between the laser beam and the BOP vertical axis; the same level as the area to be cut, which would result in a 90° angle being formed between the laser beam and the BOP vertical axis; or, below the area to be cut, which would result in an obtuse angle being formed between the laser beam and the BOP cavity vertical axis. In this way, the relationship between the shape of the rams, the surfaces of the rams, the forces the rams exert, and the location of the area to be cut by the laser can be evaluated and refined to optimize the relationship of these factors for a particular application.
The ability to predetermine the angle that the laser beam forms with the BOP vertical axis provides the ability to have specific and predetermined shapes to the end of a severed tubular. Thus, if the laser beam is coming from above the cutting area an inward taper can be cut on the upper end of the lower piece of the severed tubular. If the laser beam is coming from below the area to be cut an outward taper can be cut on the upper end of the lower piece of the severed tubular. If the laser beam is coming from the same level as the cutting area no taper will be cut on the ends of the severed tubulars. These various end shapes for the severed lower tubular maybe advantageous for attaching various types of fishing tools to that tubular to remove it from the well at some later point in time.
The number of laser cutters utilized in a configuration of the present inventions can be a single cutter, two cutters, three cutters, and up to and including 12 or more cutters. As discussed above, the number of cutters depends upon several factors and the optimal number of cutters for any particular configuration and end use may be determined based upon the end use requirements and the disclosures and teachings provided in this specification.
Examples of laser power, fluence and cutting rates, based upon published data, are set forth in Table I.
The flexible support cables for the laser cutters provide the laser energy and other materials that are needed to perform the cutting operation. Although shown as a single cable for each laser cutter, multiple cables could be used. Thus, for example, in the case of a laser cutter employing a compound fluid laser jet the flexible support cable would include a high power optical fiber, a first line for the core jet fluid and a second line for the annular jet fluid. These lines could be combined into a single cable or they may be kept separate. Additionally, for example, if a laser cutter employing an oxygen jet is utilized, the cutter would need a high power optical fiber and an oxygen line. These lines could be combined into a single cable or they may be kept separate as multiple cables. The lines and optical fibers should be covered in flexible protective coverings or outer sheaths to protect them from borehole fluids, the BOP environment, and the movement of the laser cutters, while at the same time remaining flexible enough to accommodate the orbital movement of the laser cutters. As the support cables near the feed-through assembly there to for flexibility decreases and more rigid means to protect them can be employed. For example, the optical fiber may be placed in a metal tube. The conduit that leaves the feed-through assembly adds additional protection to the support cables, during assembly of the SLM, the BOP stack, handling of the BOP, handling of the SLM, deployment of the BOP, and from the environmental conditions at the seafloor.
It is preferable that the feed-through assemblies, the conduits, the support cables, the laser cutters and other subsea components associated with the operation of the laser cutters, should be constructed to meet the pressure requirements for the intended use of the BOP. The laser cutter related components, if they do not meet the pressure requirements for a particular use, or if redundant protection is desired, may be contained in or enclosed by a structure that does meet the requirements. Thus, if the BOP is rated at 10,000 psi these components should be constructed to withstand that pressure. For deep and ultra-deep water uses the laser cutter related components should preferably be capable of operating under pressures of 15,000 psi, 20,000 psi or greater. The materials, fittings, assemblies, useful to meet these pressure requirements are known to those of ordinary skill in the offshore drilling arts, related sub-sea Remote Operated Vehicle (“ROV”) art, and in the high power laser art.
In
There is also provided a shield 1470. This shield 1470 protects the laser cutters and the laser delivery assembly from drilling fluids and the movement of tubulars through the BOP cavity. Is it preferably positioned such that it does not extend into, or otherwise interfere with, the BOP cavity or the movement of tubulars through that cavity. It is preferably pressure rated at the same level as the other BOP components. Upon activation, it may be mechanically or hydraulically moved away from the laser beam's path or the laser beam may be shoot through it, cutting and removing any shield material that initially obstructs the laser beam. Upon activation the lasers cutters shoot laser beams from outside of the BOP cavity into that cavity and toward any tubular that may be in that cavity. Thus, there are laser beam paths 1480, 1481, 1482, 1483, 1484, 1485, 1486, and 1487, which paths rotate around center axis 1411 during operation.
In general, operation of a laser assisted BOP stack where at least one laser beam is directed toward the center of the BOP and at least one laser cutter is configured to orbit (partially or completely) around the center of the BOP to obtain circumferential cuts, i.e., cuts around the circumference of a tubular (including slot like cuts that extend partially around the circumference, cuts that extend completely around the circumference, cuts that go partially through the tubular wall thickness, cut that go completely through the tubular wall thickness, or combinations of the foregoing) may occur as follows. Upon activation, the laser cutter fires a laser beam toward the tubular to be cut. At a time interval after the laser beam has been first fired the cutter begins to move, orbiting around the tubular, and thus the laser beam is moved around the circumference of the tubular, cutting material away from the tubular. The laser beam will stop firing at the point when the cut in the tubular is completed. At some point before, during, or after the firing of the laser beam, ram shears are activated, severing, displacing, or both any tubular material that may still be in their path, and sealing the BOP cavity and the well.
In
Although eight evenly spaced laser cutters are shown in the example of a fixed laser cutter embodiment in
In the operation of such fixed laser cutter embodiments, the laser cutters would fire laser beams, along beam paths. The beam paths do not move with respect to the BOP. The laser beams would cut material from the tubular substantially weakening it and facilitating the severing and displacement of the tubular by the shear ram. Depending upon the placement of the laser beams on the tubular, the spot size of the laser beams on the tubular, and the power of the laser beam on the tubular, the cutters could quickly sever the tubular into two sections. If such a severing laser cut is made above the shear rams, the lower section of the tubular may drop into the borehole, provided that there is sufficient space at the bottom of the borehole, and thus out of the path of the shear rams, a blind ram, or both. A similar cut, which completely severs the tubular into two pieces, could be made by the orbiting cutter embodiments.
By having the laser delivery assemblies and in particular the laser cutters on extendable arms or pistons the distance of the laser beam path through any drilling fluids can be greatly reduced if not eliminated. Thus, the firing of the laser beam may be delayed until the laser cutters are move close to, very close to, or touching, the tubular to be cut.
In
The body 1601 has a feed-through assemblies 1613, 1614 for managing pressure and permitting optical fiber cables and other cables, tubes, wires and conveyance means, which may be needed for the operation of the laser cutter, to be inserted into the body 1601. The body, as seen in
The laser delivery assembly 1624 has three laser cutters 1626, 1627 and 1628. Flexible support cables are associated with each of the laser cutters. Flexible support cable 1635 is associated with laser cutter 1626, flexible support cable 1636 is associated with laser cutter 1627 and flexible support cable 1637 is associated with laser cutter 1628. The flexible support cables are located in channel 1650 and enter feed-through assembly 1613. In the general area of the feed-through assembly 1613 the support cables may transition from flexible to semi-flexible. However, in this and similar embodiments were the cutters do not move, there is not the need for the cutters to be flexible. The cables and may further be included in conduit 1633 for conveyance to a high power laser, or other sources of materials for the cutting operation.
The laser delivery assembly 1625 has three cutters 1631, 1630, and 1629. Flexible support cables are associated with each of the laser cutters. The flexible support cable 1640 is associated with laser cutter 1631, flexible support cable 1639 is associated with laser cutter 1630 and flexible support cable 1638 is associated with laser cutter 1629. The flexible support cables are located in channel 1651 and enter feed-through assembly 1614. In the general area of the feed-through assembly 1614 the support cables may transition from flexible to semi-flexible. However, in this and similar embodiments were the cutters do not move there is not the need for the cutters to be flexible. The cables may further be included in conduit 1634 for conveyance to a high power laser, or other sources of materials for the cutting operation.
In addition to finding applications in, and in association with, a BOP stack and risers, high power laser assemblies and cutters have applications in, and in association with, subsea well intervention equipment and procedures, including subsea well completion tools and assemblies, for example subsea completion test trees. Subsea test trees (as used herein subsea tree is to be given its broadest meaning possible and includes, subsea completion trees, and other assemblies that perform similar activities) have many applications, and are typically used to in conjunction with a surface vessel to conduct operations such as completion, flow testing, intervention, and other subsea well operations. Subsea trees are typically connected to a surface vessel by a string of tubulars.
In general, during and after completion of a well there may arise occurrences or situations when it is necessary to enter, reenter, into the well bore again with testing, cleaning or other types of equipment or instruments. Typically, this may be accomplished by placing a BOP, or a lower marine riser package (LRP) and an emergency disconnect package (EDP), on the well. Thus, typically, when dealing with a well having a vertical “christmas tree”, which is assembly of valves, spools, pressure gauges and/or chokes fitted to the wellhead of the completed well to control production, the vertical christmas tree will be removed and the BOP secured to the well head. When dealing with horizontal and enhanced vertical christmas trees, typically, the christmas tree can be left in place, remaining secured to the well head, and the BOP (or LRP/EDP) secured to the christmas tree.
In general, when a subsea test tree is performing subsea operations the subsea test tree is extended into, and positioned within, the BOP's inner cavity. The outer diameter of the subsea test tree is slightly smaller than the inner cavity of a BOP. Thus for an 18¾ inch BOP, a typical subsea test tree will have an outer diameter of about 18½ inches. Such a subsea tree could have an inner diameter, or inner cavity, of about 7⅓ inches. The subsea test tree has, in addition to other ports and valves, two valves that are intended to control borehole pressures, flows or both and, in particular, to control or manage emergency flow or pressure situations. In general these valves may be a lower ball valve and an upper ball valve or in some assemblies this upper valve can be a flapper valve. Typically, and preferably these control valves are independent of each other, and configured to fail in a closed position. When the test tree is positioned within a BOP these valves are generally positioned below the ram shears.
During operations with a subsea test tree, many different types of tubulars and lines may be extend through the inner cavity of the test tree and into the well head and well bore. Thus, for example, VIT, wireline, slickline, coil tubing (having outer diameters of up to about 2 inches, or potentially greater) and jointed pipe (having an outer diameter of from 1 to 2 inches, or potentially greater) could be extended into and through the test tree inner cavity.
Turning to
The laser-subsea test tree may be used in conjunction with a non-laser BOP, or in conjunction with or as a part of a laser BOP system.
The configurations of and arrangement of the various components in a laser assisted BOP stack, an SLM and a laser subsea test tree, provide the capability of many varied sequences of laser cutter firing and activation of ram preventers and annular preventers. Thus, the sequence of laser firings and activations can be varied depending upon the situation present in the well or the BOP, to meet the requirements of that situation. Thus, for example, pipe rams could engage a tubular, laser cutters could sever the tubular without crushing it. In another example, where a casing and a tubular in that cases are in the BOP, an SLM could be fired to sever the casing, which is then pulled and dropped away, laser ram shears are then used to sever the tubular and seal the BOP cavity. In yet another example, in a situation where the BOP has for unknown reasons failed to seal off the well, all laser cutters can be repeatedly fired, removing what ever tubular may be obstructing the various rams, permitting the to seal the well The present inventions provide the ability to quickly provide laser, laser-mechanical, and mechanical cutting and sealing actions in a BOP to address situations that may arise in offshore drilling. As such, the scope of the present inventions is not limited to a particular offshore situation or sequence of activities.
The invention may be embodied in other forms than those specifically disclosed herein without departing from its spirit or essential characteristics. The described embodiments are to be considered in all respects only as illustrative and not restrictive.
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| Number | Date | Country | |
|---|---|---|---|
| 20120217019 A1 | Aug 2012 | US |
