Patent Grant
9845652
Field of the Invention
The present inventions relate to the delivery of high power directed energy for use in well control systems.
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, unless specified otherwise, 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.
As used herein the term “earth” should be given its broadest possible meaning, and includes, the ground, all natural materials, such as rocks, and artificial materials, such as concrete, that are or may be found in the ground, including without limitation rock layer formations, such as, granite, basalt, sandstone, dolomite, sand, salt, limestone, rhyolite, quartzite and shale rock.
As used herein the term “borehole” should be given it broadest possible meaning and includes any opening that is created in a material, a work piece, a surface, the earth, a structure (e.g., building, protected military installation, nuclear plant, offshore platform, or ship), or in a structure in the ground, (e.g., foundation, roadway, airstrip, cave or subterranean structure) that is substantially longer than it is wide, such as a well, a well bore, a well hole, a micro hole, slimhole and other terms commonly used or known in the arts to define these types of narrow long passages. Wells would further include exploratory, production, abandoned, reentered, reworked, and injection wells.
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 should 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 should 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, vacuum insulated tubing (“VIT), production tubing 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 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 the terms “blowout preventer,” “BOP,” and “BOP stack” should be given their broadest possible meaning, and include: (i) devices positioned at or near the borehole surface, e.g., the surface of the earth including dry land or 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 or a connector; (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 term “fixed platform,” would include any structure that has at least a portion of its weight supported by the seafloor. Fixed platforms would include structures such as: free-standing caissons, well-protector jackets, pylons, braced caissons, piled-jackets, skirted piled-jackets, compliant towers, gravity structures, gravity based structures, skirted gravity structures, concrete gravity structures, concrete deep water structures and other combinations and variations of these. Fixed platforms extend from at or below the seafloor to and above the surface of the body of water, e.g., sea level. Deck structures are positioned above the surface of the body of water a top of vertical support members that extend down in to the water to the seafloor.
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 330 rigs rated for drilling in water depths greater than 600 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, risers, 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 blowout preventer (“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, in general, 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. BOP's can have cavities, e.g., bore diameters ranging from about 4⅙″ to 26¾.″ 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 also typically has ram preventers. As used herein, unless specified otherwise, the terms “ram preventer” and “ram” are 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, variable rams, variable pipe rams, casing shear rams, and 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.
Thus, the BOP stack typically 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 situations arises, flows from high downhole pressures can come back up through the inside of the tubular, the annulus between the tubular and riser, and up the riser to the drilling rig. Additionally, in emergency situations, the pipe 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. Mechanical shear rams are typically the last line of defense for emergency situations, e.g., kicks or potential blowouts. (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 function like giant gate valves that supposed to quickly close across the BOP cavity to seal it. They are intended to cut through any tubular that 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, 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. (As used herein the term “preventer” in the context of a BOP stack, would include all rams, shear rams, and annular preventers, as well as, any other mechanical valve like structure used to restrict, shut-off or control the flow within a BOP bore.)
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.
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.
Risers, which would include marine risers, subsea risers, and drilling risers, are essentially large tubulars that connect an offshore drilling rig, vessel or platform to a borehole. Typically a riser is connected to the rig above the water level and to a BOP on the seafloor. Risers can be viewed as essentially a very large pipe, that has an inner cavity through which the tools and materials needed to drill a well are sent down from the offshore drilling rig to the borehole in the seafloor and waste material and tools are brought out of the borehole and back up to the offshore drilling rig. Thus, the riser functions like an umbilical cord connecting the offshore rig to the wellbore through potentially many thousands of feet of water.
Risers can vary in size, type and configuration. All risers have a large central or center tube that can have an outer diameters ranging from about 13⅜″ to about 24″ and can have wall thickness from about ⅝″ to ⅞″ or greater. Risers come in sections that can range in length from about 49 feet to about 90 feet, and typically for ultra deep water applications, are about 75 feet long, or longer. Thus, to have a riser extend from the rig to a BOP on the seafloor the rise sections are connected together by the rig and lowered to the seafloor.
The ends of each riser section have riser couplings that enable the large central tube of the riser sections to be connected together. The term “riser coupling” should be given its broadest possible meaning and includes various types of coupling that use mechanical means, such as, flanges, bolts, clips, bowen, lubricated, dogs, keys, threads, pins and other means of attachment known to the art or later developed by the art. Thus, by way of example riser couplings would include flange-style couplings, which use flanges and bolts; dog-style couplings, which use dogs in a box that are driven into engagement by an actuating screw; and key-style couplings, which use a key mechanism that rotates into locking engagement. An example of a flange-style coupling would be the VetcoGray HMF. An example of a dog-style coupling would be the VetcoGray MR-10E. An example of a key-style coupling would be the VetcoGray MR-6H SE
Each riser section also has external pipes associated with the large central tube. These pipes are attached to the outside of the large central tube, run down the length of the tube or riser section, and have their own connections that are associated with riser section connections. Typically, these pipes would include a choke line, kill line, booster line, hydraulic line and potentially other types of lines or cables. The choke, kill, booster and hydraulic lines can have inner diameters from about 3″ (hydraulic lines may be as small as about 2.5″) to about 6.5″ or more and wall thicknesses from about ½″ to about 1″ or more.
Situations arise where it may be necessary to disconnect the riser from the offshore drilling rig, vessel or platform. In some of these situations, e.g., drive-off of a floating rig, there may be little or no time, to properly disconnect the riser. In others situations, such as weather related situations, there may be insufficient time to pull the riser string once sufficient weather information is obtained; thus forcing a decision to potentially unnecessarily pull the riser. Thus, and particularly for deep, very deep and ultra deep water drilling there has existed a need to be able to quickly and with minimal damage disconnect a riser from an offshore drilling rig.
In offshore drilling activities critical and often times emergency situations arise. These situations can occur quickly, unexpectedly and require prompt attention and remedial actions. Although these offshore emergency situations may have similar downhole causes to onshore drilling emergency situations, the offshore activities are much more difficult and complicated to manage and control. For example, it is generally more difficult to evacuate rig personnel to a location, away from the drilling rig, in an offshore environment. Environmentally, it is also substantially more difficult to mitigate and manage the inadvertent release of hydrocarbons, such as in an oil spill, or blowout, for an offshore situation than one that occurs onshore. The drilling rig, in an offshore environment, can be many tens of thousands of feet away from the wellhead. Moreover, the offshore drilling rig is fixed to the borehole by the riser and any tubulars that may be in the borehole. Such tubulars may also interfere with, inhibit, or otherwise prevent, well control equipment from functioning properly. These tubulars and the riser can act as a conduit bringing dangerous hydrocarbons and other materials into the very center of the rig and exposing the rig and its personnel to extreme dangers.
Thus, there has long been a need for systems that can quickly and reliably address, assist in the management of, and mitigate critical and emergency offshore drilling situations. This need has grown ever more important as offshore drilling activities have moved into deeper and deeper waters. In general, it is believed that the art has attempted to address this need by relying upon heavier and larger pieces of equipment; in essence by what could be described as using brute force in an attempt to meet this need. Such brute force methods, however, have failed to meet this long-standing and important need.
There has been a long standing need for improved systems that can provide safe and effective control of well conditions, and in particular to do so at greater depths and under harsher conditions and under increased energy and force requirements. The present inventions, among other things, solve these and other needs by providing the articles of manufacture, devices and processes taught herein.
Thus, there is provided a well control system having a reduced potential mechanical energy requirement, the system having: a body defining a cavity; a mechanical device associated with the cavity; a source of directed energy, having the capability to deliver a directed energy to a location within the cavity, the directed energy having a first amount of energy; and, a source of potential mechanical energy associated with the mechanical device, and capable of delivering mechanical energy to a location within the cavity, the source of potential energy having a potential energy having a second amount of energy; wherein, the first amount of energy is at least as great as about 5% of the second amount of energy.
There is further provided a well control system or method of controlling a well having one or more of the following features including: wherein the body has a blowout preventer; wherein the mechanical device has a ram; wherein the mechanical device has a shear ram; wherein the ram is selected from the group consisting of a blind ram, a shear ram, a blind shear ram, a pipe ram and a casing shear ram; having a high power laser system, a riser and a blowout preventer stack; wherein the mechanical device is selected from the group consisting of a blind ram, a fixed pipe ram, a variable pipe ram, a shear ram, a blind shear ram, a pipe ram and a casing shear ram; wherein the source of potential mechanical energy has a charged accumulator; wherein the source of potential mechanical energy has a plurality of charged accumulators; wherein the source of potential mechanical energy has a charged accumulator bank; wherein the charged accumulator has a pressure of at least about 1,000 psi; wherein the charged accumulator has a pressure of at least about 3,000 psi; wherein the charged accumulator has a pressure of at least about 5,000 psi; wherein the charged accumulator has a pressure of at least about 5,000 psi; wherein the source of directed energy is a high power laser have a power of at least about 10 kW; wherein the source of directed energy is a high power laser have a power of at least about 15 kW; wherein the source of directed energy is a high power laser have a power of at least about 20 kW; wherein the source of directed energy is a high power laser have a power of at least about 40 kW; wherein the first amount of energy is at least about 150 kJ; wherein the first amount of energy is at least about 600 kJ; wherein the well control systems has a high power laser system; the body has a blowout preventer; the source of potential mechanical energy has a charged accumulator, having a pressure of at least about 1,000 psi; and the mechanical device is selected from the group consisting of a blind ram, a shear ram, a ram, a blind shear ram, a pipe ram and a casing shear ram; wherein the well control systems has a high power laser system; the body has a blowout preventer; the source of potential mechanical energy has a charged accumulator, having a pressure of at least about 1,000 psi; and the mechanical device is selected from the group consisting of a blind ram, a shear ram, a blind shear ram, a ram, a pipe ram and a casing shear ram; wherein the well control systems has a high power laser system; the body has a blowout preventer; the source of potential mechanical energy has a charged accumulator, having a pressure of at least about 1,000 psi; and the mechanical device is selected from the group consisting of a blind ram, a shear ram, a blind shear ram, a pipe ram, a ram and a casing shear ram; wherein the well control systems has a high power laser system; the body has a blowout preventer; the source of potential mechanical energy has a charged accumulator, having a pressure of at least about 1,000 psi; and the mechanical device is selected from the group consisting of a blind ram, a shear ram, a blind shear ram, a ram, a pipe ram and a casing shear ram; wherein the well control systems has a high power laser system; the body has a blowout preventer; the source of potential mechanical energy has a charged accumulator, having a pressure of at least about 1,000 psi; and the mechanical device is selected from the group consisting of a blind ram, a shear ram, a blind shear ram, a ram, a pipe ram and a casing shear ram; wherein the first amount of energy is greater than the second amount of energy energy; wherein the first amount of energy is at least as great as about 25% of the second amount of energy; wherein the first amount of energy is at least as great as about 50% of the second amount of energy; wherein the first amount of energy is at least as great as about 100% of the second amount of energy; and, wherein the first amount of energy is greater than the second amount of energy.
There is still further provided a well control system having a reduced potential mechanical energy requirement, the system having: a body defining a cavity; a mechanical device associated with the cavity; a source of directed energy, having the capability to deliver a directed energy to a location associated with the cavity, the directed energy having a first power; and, a source of potential mechanical energy associated with the mechanical device, and capable of delivering mechanical energy to a location within the cavity, the source of potential energy having a potential energy having a second power; wherein, the first power is at least as great as about 5% of the second power.
Moreover, there is provided a well control system having a reduced potential mechanical energy requirement, the system having: a high power laser system; a riser; a blowout preventer stack; the blowout preventer stack defining a cavity; a mechanical device for sealing a well associated with the cavity; a source of directed energy, having the capability to deliver a directed energy to a location associated with the cavity, the directed energy having a first amount of energy; and, a source of potential mechanical energy associated with the mechanical device, and capable of delivering mechanical energy to a location associated with the cavity, the source of potential energy having a potential energy having a second amount of energy energy; wherein, the first amount of energy is at least as great as about 5% of the second amount of energy.
There is further provided a well control system or method of controlling a well having one or more of the following features including: wherein in the source of directed energy is a high power laser have a power of at least about 15 kW, and the source of potential energy is a charged bank of accumulators having a pressure of at least about 1,000 psi; wherein in the source of directed energy is a high power laser of at least about 20 kW; wherein the source of potential energy is a charged bank of accumulators having a pressure of at least about 1,000 psi.
Additionally, there is provided a constant energy depth independent well control system, the system having: a device for delivering directed energy; a device for delivering mechanical energy associated with a potential energy source having an amount of potential energy; and, the device for delivering directed energy compensatively associated with the device for delivering mechanical energy, whereby the delivery of the directed energy compensates for losses in potential energy.
There is further provided a well control system or method of controlling a well having one or more of the following features including: a high power laser, a riser and a blowout preventer stack; wherein the losses of potential energy arise from the potential energy source being positioned under a surface of a body of water at a depth; wherein the depth is at least about 5,000 ft; and, wherein the source of potential energy has a bank of charged accumulators.
Yet further, there is provided a laser BOP having: a first and a second ram block; the first ram block having a first and a second laser device, the first laser device defining a first laser beam path for delivery of a laser beam, the second laser device defining a second beam path for delivery of a laser beam; the second ram block having a third and a fourth laser device, the third laser device defining a third laser beam path for delivery of a laser beam, the fourth laser device defining a fourth laser beam path for delivery of a laser beam; and, the ram blocks associated with an actuator center line; whereby the laser beam paths define beam path angles with respect to the actuator center line.
Still additionally, there is provided a laser BOP having: a first ram block; the first ram block having a first and a second laser device, the first laser device defining a first laser beam path for delivery of a laser beam, the second laser device defining a second beam path for delivery of a laser beam; and, the ram block associated with an actuator center line; whereby the laser beam paths define beam path angles with respect to the actuator center line.
There is further provided a well control system or method of controlling a well having one or more of the following features including: a laser BOP having a beam path angle for a first laser beam path of 90°; wherein the beam path angle for the first laser beam path is greater than 90°; wherein the beam path angle for the first laser beam path is less than 90°; wherein the beam path angles for the first and second beam paths are greater than 90°; wherein the beam path angles for the first and second beam paths are less than 90°; wherein the beam path angles for the first and second beam paths are about the same angle; wherein the beam path angles for the first and second beam paths are different angles; wherein the first laser beam has a power of at least about 10 kW; wherein the first and second laser beams each have a power of at least about 10 kW.
Yet still further, there is provided a laser BOP of having: a second ram block; the second ram block having a third and a fourth laser device, the third laser device defining a third laser beam path for delivery of a laser beam, the fourth laser device defining a fourth beam path for delivery of a laser beam; and, the second ram block associated with the actuator center line, and whereby the third and fourth laser beam paths define beam path angles with respect to the actuator center line.
Furthermore, there is provided a method of severing a tubular in a BOP cavity, having: delivering directed energy to a predetermined location on a tubular positioned in a cavity of a BOP; the directed energy damaging the tubular in a predetermined pattern; applying a mechanical force to the tubular in association with the damage pattern, whereby the tubular is severed.
There is further provided a well control system or method of controlling a well having one or more of the following features including: wherein the directed energy is a high power laser beam; wherein the directed energy is a high power laser beam having at least 10 kW of power; wherein the predetermined damage pattern is a slot; wherein the predetermined damage pattern is a slot having a length and a varying width; wherein the directed energy is a high power laser beam having at least about 5 kW of power, and having a focal length, wherein the damage pattern is a slot having a length and a varying width, whereby the width varies proportionally to the focal length of the laser beam.
Still further this is provided a method for closing a well having: a step for delivering a high power laser beam to a tubular in a cavity in a BOP; a step for removing material from the tubular with the delivered high power laser beam; a step for applying a mechanical force to the tubular; and, the step for mechanically closing the well.
Yet additionally, there is provided a laser ram BOP having: a means for providing a high power laser beam to a BOP stack, the BOP stack defining a cavity; a means for directing the high power laser beam to a tubular within the BOP cavity; and, a means for applying a mechanical force to the tubular.
There is further provided a well control system or method of controlling a well having one or more of the following features including: wherein the means for providing a high power laser beam has a battery powered 10 kW laser located subsea adjacent to the BOP stack; and wherein the means for directing the high power laser beam has a pressure compensated fluid laser jet; and wherein the pressure compensated fluid laser jet is a means for compensating pressure; wherein the means for compensating pressure is the embodiment shown in
Still further there is provided a BOP package having: a lower marine rise package; a lower BOP stack; a connector releasable connecting the lower marine riser package and the lower BOP stack; and, the connector having a high power directed energy delivery device.
There is further provided a well control system or method of controlling a well having one or more of the following features including: wherein the connector is capable of being released at an angle, defined by a position of a rig associated with the BOP stack with respect to a vertical line from the BOP stack, that is greater than about 5°; wherein the releasable angle is greater than about 6°; wherein the releasable angle is greater than about 7°; wherein the releasable angle is greater than about 10°; and wherein the high power energy deliver device has a high power laser beam delivery device capable of delivering a high power laser beam having a power of at least about 5 kW.
The present inventions relate to the delivery and utilization of high power directed energy in well control systems and particularly to systems, methods and structures for utilizing high power directed energy, in conjunction with devices, that deliver mechanical energy, such as, for example, BOPs, BOP stacks, BOP-riser packages, ram assemblies, trees, sub-sea trees, and test trees.
Generally, well control systems and methods utilize various mechanical devices and techniques to control, manage and assure the proper flow of hydrocarbons, such as oil and natural gas, into a well and to the surface where the hydrocarbons may be collected, transported, processed and combinations and variations of these. Such systems perform many and varied activities. For example, and generally, one such application is the mechanical shutting in, shutting off, or otherwise closing, or partially closing, of a well to prevent, mitigate, or manage a leak, blowout, kick, or such type of uncontrolled, unanticipated, emergency, or in need of control, event. Thus, for example, a BOP, may be used to mechanically close a well; and in the process of closing the well, to the extent necessary, sever any tubulars that may be blocking, or would otherwise interfere with the closing of the mechanical devices, e.g., rams, used to close and seal the well. In other situations, such as a tree, there may be a valve that is closed to shut the well off. This valve is intended to upon closing, sever or cut an object, such a wireline, that may be present.
Generally, in such situations where the well is being closed, the associated well control devices are intended to close the well quickly and under any, and all, conditions. As exploration and product of hydrocarbons moves to more and more difficult to access locations, and in particular moves to deeper and deeper water depths, e.g., 1,000 ft, 5,000 ft, 10,000 ft, and deeper, the demands on BOPs and other such well control devices has become ever and ever more arduous.
At such depths the increased pressure from the water column reduces the capabilities of the potential energy storage devices, e.g., the accumulators, by reducing the amount of potential energy that can be stored by those devices. Similarly, as depth increases, the temperature of the water decreases, again reducing the amount of potential energy that can be stored by those devices. On the other hand, as depth increases, the strength, size and ductility, of the tubulars used for drilling increases, requiring greater potential energy, mechanical energy and force to assure that any, and all, tubulars present in the BOP will be cut, and not interfere with the closing off of the well.
Prior to the present inventions, to address these demands, e.g., the reduced ability to store potential energy and the increased need for greater mechanical energy, on BOPs and other similar devices, the art generally has taken a brute force approach to this problem. Thus, and in general, the size, weight, potential energy holding capabilities, and mechanical energy delivery capabilities, of such devices has been ever increasing. For example, current and planned BOP stacks can be over 60 feet tall, weigh over 350 tons, and have over one hundred accumulators, having sufficient potential energy when fully charged, to exert about 1.9 million pounds, about 2.0 million pounds, or more, of shear force at sea level.
Embodiments of the present inventions, in part, utilize directed energy to replace, reduce, compensate for, augment, and variations and combinations of these, potential energy requirements, mechanical power requirements, mechanical energy requirements, and shear force requirements of well control systems, such as BOPs. Thus, by using directed energy, to replace, reduce, compensate for, augment, and variations and combinations of these, mechanical energy, many benefits and advantages may be realized.
For example, among other things: smaller weight and size BOPs may be developed that have the same performance capabilities as much larger units; greater water depths of operation may be achieved without the expected increase in size, potential energy requirements and mechanical energy capabilities; in general, less potential energy may be required to be stored on the BOP to have the same efficacy, e.g., ability to cut and seal the well under various conditions; and, in general, less mechanical energy, and shear force, may be required to be delivered by the BOP to have the same efficacy, e.g., ability to cut and seal the well under various conditions.
These and other benefits from utilizing directed energy and the substation, augmentation, and general relationship of, directed energy to mechanical energy, including potential mechanical energy, will be recognized by those of skill in the art based upon the teachings and disclosure of this specification; and come within the scope of protection of the present inventions.
Thus, and in general, embodiments of the present systems and methods involve the application of directed energy and mechanical energy to structures, e.g., a tubular, a drill pipe, in a well control device, e.g., a BOP, a test-tree, and to close off the well associated with the well control device. For example, the directed energy may be applied to the structure in a manner to weaken, damage, cut, or otherwise destroy a part or all of the structure at a predetermined location, manner, position, and combinations and variations of these. A mechanical energy may be applied by a mechanical device having an amount of potential energy associated with the device, e.g., charged accumulators having over 5,000 psi pressure in association with a blind shear ram BOP, to force through what might remain of the structure and force the mechanical device into a sealing relationship with the well bore.
The directed energy and mechanical forces are preferably applied in the manner set forth in this specification, and by way of example, may be applied as taught and disclosed in US patent applications: Ser. No. 13/034,175; Ser. No. 13/034,183; Ser. No. 13/034,017; and, Ser. No. 13/034,037, the entire disclosures of each of which are incorporated herein by reference.
As used herein “directed energy” would include, for example, optical laser energy, non-optical laser energy, microwaves, sound waves, plasma, electric arcs, flame, flame jets, explosive blasts, exploded shaped charges, steam, neutral particle beam, or any beam, and combinations and variations of the foregoing, as well as, water jets and other forms of energy that are not “mechanical energy” as defined in these specifications. (Although a water jet, and some others, e.g., shaped charge explosions, and steam, may be viewed as having a mechanical interaction with the structure, for the purpose of this specification, unless expressly provided otherwise, will be characterized amongst the group of directed energies, based upon the following specific definition of mechanical energy). “Mechanical energy,” as used herein, is limited to energy that is transferred to the structure by the interaction or contact of a solid object, e.g., a ram or valve edge, with that structure.
These methods provide for the application of unique combinations of directed energy and mechanical force to obtain a synergism. This synergism enables the combinations to obtain efficacious operations using, or requiring, less mechanical force, energy, and potential energy that would otherwise be expected, needed or required. This synergism, although beneficial in many applications, conditions and settings, is especially beneficial at increasing water depths.
Thus, for example the compression ratio (“CR”) of a system, e.g., a BOP stack, is defined as the ratio of the maximum pressure (“Pmax”) the accumulator bank of the system can have and the minimum pressure (“Pmin”) needed for the system to perform the closing operation, e.g., shearing and closing. Thus, CR=Pmax/Pmin. For example, a system having a maximum pressure of 6,000 psi and a minimum pressure of 3,000 psi at sea level would have a CRsea level of 2. (Generally, the higher the CR, the better efficacy, or greater the shearing and sealing capabilities of the system.)
This same system, however, at a depth of 12,000 feet would have a CR12,000 of 1.36. At a depth of 12,000 feet the pressure of the water column would be about 5,350 psi, which is additive to both Pmax and Pmin. Thus, for this same system—CR12,000=6000 Pmax+5,350/3000 Pmin+5,350=11,350/8,350=1.36. About a 32% decrease in CR (from a CR of 2 to a CR of 1.36).
However, utilizing embodiments of the present inventions, the Pmin of the system may be significantly reduced, because the directed energy weakens, damages, or partially cuts the structure, e.g., a tubular, a drill pipe, that is in the BOP cavity. Thus, less shear force is required to sever the structure and seal the well. For example, using an amount of directed energy, e.g., 10 kW (kilo Watts) for 30 seconds (300 kJ (kilo Joules)), the Pmin of the system may be reduced to 750 psi, resulting in a CR12,000 of 1.86 for a directed energy-mechanical energy system. CR12000−6000 Pmax+5,350/750 Pmin+5,350=11,350/6100=1.86. About a 36% increase in the CR at depth over the system that did not utilize directed energy (from a CR of 1.36 to a CR of 1.86). Thus, utilizing an embodiment of the present invention, the CR at depth of the system can be increased through the use of directed energy without increasing the Pmax of the system. Thus, avoiding the need to increase the size and weight of the system. The potential energy of the system having the 750 Pmin would be 604 kJ, while the system having 3,000 Pmin would be 2,426 kJ, as set forth in Table I (stroke is 9⅜ inched based upon 18¾ inch bore size, divided by two).
The reduced temperature of the water at depth can have similar negative effects on CR. Thus, for example, a 6,000 psi charge Pmax at 80° F. would be 4,785 psi at 40° F. These and other negative effects on CR, or other measures of a well control systems efficacy, may be over come through the use of directed energy to weaken, damage, cut, partially cut, or otherwise make the ability of the ram to pass through the structure in the well control system cavity, e.g., a tubular, drill pipe, tool joint, drill collar, etc. in the BOP cavity, easier, e.g., requiring less mechanical energy.
The damaging, cutting, slotting, or weakening of a structure in a cavity of a well control device, such as for example a tubular such as a drill pipe in the cavity of a BOP may occur from the timed delivery, of a single from of directed energy or from the timed delivery of multiple forms of directed, and mechanical energy. Predetermined energy delivery patterns, from a shape, time, fluence, relative timing, and location standpoint, among others may be used. Thus, for example with laser energy the laser beam could be pulsed or continuous. Further the directed energy may be used to create weakening through thermal shock, thermal fatigue, thermal crack propagation, and other temperature change related damages or weakenings. Thus, differential expansion of the structure, e.g., tubular, may be used to weaken or crack the tubular. A mechanical wedge may then be driven into the weakened or cracked area driving the tubular apart. Hitting and rapid cooling may also be used to weaken the tubular, thus requiring less potential energy and mechanical force to separate the tubular. For example the tubular may be rapidly heated in a specific pattern with a laser beam, and then cooled in a specific pattern, with for example a low temperature gas or liquid, to create a weakening. The heating and cooling timing, patterns, and relative positions of those patterns may be optimized for particular tubulars and BOP configurations, or may further be optimized to effectively address anticipated situations within the BOP cavity when the well's flow needs to be restricted, controlled or stopped.
The ram block or other sealing device may further be shaped, e.g., have an edge, that exploits a directed energy weakened area of a structure, such as laser notched tubular in a BOP cavity. Thus, for example, the face of the ram block may be such that it enters the laser created notch and pry open the crack to separate the tubular, permitting the ram to pass through and seal the well bore. Thus, it may be preferable to have the face of the ram in a predetermined shape or configuration matched to, corresponding with, or based upon, the predetermined shape of the notch, cut or weakened area.
The laser cutting heads, or some other types of directed energy devices, may inject or create gases, liquids, plasma and combinations of these, in the BOP cavity during operations. Depending upon the circumstances, e.g., the configuration of the BOP stack, the closing sequence and open-closed status of the various preventers in the BOP stack, the well bore conditions, the directed energy delivery assembly, and potentially others, the injected or created materials may have to be managed and handled.
Thus, for example, it may be desirable to avoid having large volumes of undispersed gas, e.g., a big gas bubble, injected into the riser, or more specifically injected into the column of mud or returning fluids in the annulus between the inner side of the riser and the outer side of the drill pipe that is within the riser. Similarly, if large volumes of a fluid are injected into the BOP cavity, depending upon the circumstances, this introduced fluid may greatly increase the pressure within the BOP cavity making it more difficult to close the rams. Thus, this injected or created gases or fluids may be removed through the existing choke lines, kill lines, though modified ports and check valve systems, through other ports in the BOP, for example for the removal of spent hydraulic fluid. Generally, this injected or created gases or fluids, should be removed in a manner that accomplished the intended objective, e.g., avoiding an increase in pressure in the cavity, or avoiding large gas bubble formation in the rise fluid column, while maintaining and not compromising the integrity of the BOP stack to contain pressure and close off the well.
Turning to
In an example of a closing and venting operation for the BOP of the embodiment of
Turning to
When deployed sub-sea, e.g., on the floor of the sea bead, each pod would be connected to, or a part of, a multiplexed electro-hydraulic (MUX) control system. An umbilical, not shown would transmit for example, control signals, electronic power, hydraulics, fluids for laser jets and high power laser beams from the surface to the BOP stack 2000. The pods control (independently, in conjunction with control signals from the surface and combinations thereof) among other things, the operation of the various rams, and the valves in the choke and kill lines.
The choke and kill lines provide, among other things, the ability to add fluid, at high pressure and volume if need, such as heavy drilling mud, and to do so in relation to specific locations with respect to ram placement in the stack. These lines also provide the ability to bleed off or otherwise manage extra pressure that may be present in the well. They may also be utilized to handle any excess pressure or fluid volume that is associated with the use of a directed energy delivery device, such as a laser jet, a water jet, or a shaped explosive charge.
The lower BOP section 2014 of the BOP stack 2000 has a double ram BOP 2016, a laser double ram BOP 2018, a double ram BOP 2020, a single ram BOP 2022, and a wellhead connector 2024. The lower BOP section 2014 has associated with its frame 2051 four banks of accumulators 2030a, 2030b, 2030c, 2030d, with each bank having two depth compensated accumulators, e.g., 2031. The depth compensated accumulators, and the accumulator banks, may be pressurized to a Pmax of at least about 1,000 psi, at least about 3,000 psi, at least about 5,000 psi, and at least about 6,000 psi, about 7,500 psi and more. The pressurized, or charged as they may then be referred to, accumulators provide a source of stored energy, i.e., potential energy, that is converted into mechanical energy upon their discharge to, for example, close the rams in a BOP. The laser ram may be located at other positions in the BOP stack, including either or both of the top two positions in the stack, and additional laser BOPs may also be utilized.
Turning to
Embodiments of topside choke and kill system of the type generally known to those of skill in the art may be used with embodiments of the present BOPs. Thus, for example, embodiments of a fluid laser jet is used, it conjunction with, these choke and kill systems, while preferably not affecting the choke and kill lines and the performance of those lines. In an embodiment, the hydraulic lines on the drilling riser that can be generally used to supplement the fluid side of the BOP accumulators from the surface, may be used to provide the fluid for the laser fluid jet. Thus these lines may also be used, reconfigured, or additional lines added to the drilling riser, to transport the laser media, e.g., the fluid used in a laser fluid jet, down to the jet when it is deployed below sea level. Generally, there may be a hydraulic line for the subsea control pods. Further, there may be one or two boost lines present on the riser.
These and other such lines may be modified, added or reconfigured, to provide a way for the laser jet fluid to be transported down to the laser jet. For example, a tube (for the laser jet fluid) may run inside of the boost line, with an appropriate exit, and valving at the bottom of the boost line, for the tube to be connected to the laser jet assembly and nozzle. This tube may also be run down the outside of the riser.
Table 2 shows the expansion of a gas that is injected into a BOP cavity as the gas rises up through the riser column fluid, e.g., the drilling mud. The values presented in the Table 2 are based upon a wellbore temperature of 100° F., and gas discharge conditions at the surface of 115 psia and 60° F.
As can be seen from Table 2 a gallon of gas, for example at 10,000 feet depth, in a riser having mud having a density of 15 ppg will occupy a volume of 44.9 gallons at the surface. For example, even if this gas reaches the surface as one monolithic bubble, the top side diverter, which would be closed and holding 100 psig should be able to handle this influx of gas from the laser cutting, and divert this gas to the gas handler system of the rig. This influx of gas from the laser cutting may be diverted to the sea, buy way of the annular vent line, which may be positioned in the BOP stack; it may be handled by the choke and kill system by venting into either existing valving or modified valving. Preferably, this influx of gas from the laser jet fluid may be vented into the choke lines and bled off in a manner similar to the management of a kick. Further, this influx of laser jet fluid my be handled through the drilling riser to either the topside gas handling system or through a topside vent line to the flare boom. If a disconnect occurs, the entire contents of the drilling riser will be dumped to the sea, and this influx will be vented to the sea. Preferably, if a laser fluid jet is used, the laser media, e.g., the fluid, (N2, water, brine, silicon oil, D2O) is vented subsea prior to disconnect as a preferred option to entry into the drilling riser.
In some situations gas from the laser jet may also enter into the drilling pipe as the slots are cut in the pipe. In this situation the gas should be vented, or otherwise managed, e.g., bled off from the top of the drilling pipe before connections are broken.
If laser fluid jets of the type disclosed and taught in US Patent Application Publication No. 2012/0074110, and U.S. Patent Application Ser. Nos. 61/1605,429 and 61/605,434, the entire disclosure of each of which are incorporated herein by reference, are used, the source of fluid (gas, e.g., nitrogen (N2), or liquid, e.g., “hydraulic,” e.g., liquid, oil, aqueous, etc.) for the jet may come from accumulators located at, near or on the BOP stack, e.g., mounted on the BOP stack frame. Table 3 sets forth examples of some operating parameters that may be utilized with such an accumulator system.
Existing accumulators have a gas side and a fluid side. In general only the fluid side can be recharged via the riser hydraulic lines. This is how the higher ambient pressure (as the operating depth of the BOP increases) decreases the volume subsea as the gas side becomes compressed due to ideal gas laws. To charge the gas side subsea an ROV is employed, which maybe cumbersome and requires venting the pressure upon retrieval. In embodiments using a laser fluid jet, where the fluid is a gas, e.g., N2, a gas source may be by accumulation subsea, scavenging an existing line, adding a new line, and combinations and variations of these. In embodiments using a laser fluid jet where the fluid is a liquid, a source for this liquid may be to provide accumulation subsea, scavenge an existing line to the surface, or add a line to the surface, or install a pump, e.g., an electrically driven pump. In embodiments where a compound liquid and gas laser jet is utilized sources for both the gas and liquid will be provided. The source of fluid for the laser jet may be sea water, in which case for example the sea water may be pumped from the sea to form the jet, or used to fill an accumulator for discharge to form the jet. For example, seawater may be used with the laser and laser systems disclosed and taught in Ser. Nos. 61/734,809 and 61/786,763 the entire disclosures of each of which are incorporated herein by reference.
Generally, if a subsea tank is used to hold the fluid for the laser jet, it may be desirable for that tank to be pressure compensated to the well bore pressure. In this manner a pump or an accumulator would not have to overcome the well bore pressure (or at least would not have to overcome the amount of well bore pressure that is compensated for). For example, turning to
Turning to
The use of a laser mechanical shear rams further provides the ability to use, require, the same amount of mechanical energy for shearing different sizes and types of tubulars. Because the laser can cut or weaken, these different size tubulars down to a structure that can be cut by the same mechanical ram, one laser shear ram may be configured to handle all of the different types of tubulars intended to be used in a drilling plan for a well. Thus, a further advantage that may be seen with a laser shear ram BOP stack is that the stack does not have to be changed, or reconfigured, or swapped out, to accommodate different sizes and types of tubulars that are being used during the advancement of a well. Thus, the BOP would not have to be pulled from the bottom to have rams changed for example to accommodate casing verse drill pipe. The elimination of such pulling and replacement activities can provide substantial cost savings, and avoids risks to personnel and equipment that are associated with pulling and rerunning the riser and BOP.
In
Examples of such varying width cuts are shown in
By way of example, the laser delivery assemblies and optical cables may be of the type disclosed and taught in the following US patent application publications and US patent applications: Publication Number 2010/0044106; Publication Number 2010/0044105; Publication Number 2010/0044103; Publication Number 2010/0215326; Publication Number 2012/0020631; Publication Number 2012/0074110; Publication No. 2012/0068086; Ser. No. 13/403,509; Ser. No. 13/486,795; Ser. No. 13/565,345; Ser. No. 61/605,429; and Ser. No. 61/605,434 the entire disclosures of each of which are incorporated herein by reference.
The laser beams in the embodiment of
The beam path angle may be greater than and smaller than 85°. Thus, for example, it may be about 70°, about 75°, about 80°, about 90°, about 95°, and about 100°. The beam path angle is, in part, based upon the position of the laser beam device's launch point for the laser beam, the desired shape of the cut(s) in the tubular, and the angle of the leading face of the block (to preferably prevent the laser beam from striking or being directed into that face of the block). In laser shear rams having multiple laser beams and laser beam paths, the beam path angles may be the same or different.
The position of the laser induced flaws, e.g., slots, cuts, etc., may be normal to, parallel to, or some other angle with respect to the ram actuator centerline.
In
In
Laser delivery devices may be used for emergency disconnection of any of the components along a deployed riser BOP package to enable the drilling rig to move away from (either intentionally, or unintentionally such as in a drift-off) the well and lower BOP stack. The laser delivery devices may be placed at any point, but preferably where mechanical disconnects are utilized, and should the mechanical disconnect become inoperable, jammed, or otherwise not disconnect, the laser device can be fired cutting though preselected materials or structures, such as the connector, bolts, flanges, locking dogs, etc. to cause a disconnection.
Turning to there is shown a schematic of a rig 2301 on a surface 2301 of a body of water 2309 that is connected to a BOP stack 2304 on the sea floor 2303 by way of a riser 2308. The BOP stack 2304 has a LMPR 2305 that is attached to the lower BOP stack 2306 by way of a connector 2307. The connector may be, for example, a VETCOGRAY H-4® Connector. When the drilling rig moves a certain distance away from being directly above the well and BOP, i.e., moves away from the vertical axis or centering line 2311, the connector 2307 may be come jammed. When the angle 2311 formed between the centering line 2311 and the riser, (or the line between the top of the BOP and the rotary table of the drill ship) becomes large enough, at times around 2-4°, generally around 5°, and in some cases slightly more, the connector 2907 engagement-disengagement mechanism can become inoperable, jamming the connector and thus preventing it from being unlocked, and preventing the LMRP from being able to be disconnected from the lower stack. This distance that the rig 2902 is from the centerline 2310 can also be viewed, as shown in
To increase the angle at which the rig can be off the centerline, i.e., increase the size of the area, e.g., the diameter of the outer sage circle in
For example, turning to
Turning to
is a schematic view of an embodiment of a surface system that may be used with a drilling rig, e.g., a drill ship, semi-submersible, jack-up, etc., and a laser BOP system. The surface system 2600 may have a diverter 2601, a flex joint 2602, a space out joint 2603, an inner barrel telescopic joint 2604, a dynamic seal telescope joint 2605, tensioners 2606, a tension ring 2607, an outer barrel telescopic joint (tension joint) 2608, and a riser joint 2609. The laser conveyance and laser fluid conveyance structures could be located at or near position 2626a, e.g., near the diverter 2601; at or near position 2626b, e.g., below the space out joint 2603; at or near position 2626c, e.g., below the tensioners 2606; or at or near position 2626d, near the riser joint 2609. The high power laser fiber, the high power laser fluid jet conduits, or conveyance structures, may enter into the riser system at these positions or other locations in, or associated with, the surface system 2600.
Turning to
Turning to
Laser cutters, laser devices and laser delivery assemblies can be used in, or in conjunction with commercially available annular preventers, rotating heads, spherical BOPs, and other sealing type well control devices. Thus, they may be used in, or with, for example, NOV (National Oilwell Varco) preventer, GE HYDRIL pressure control devices, SHAFFER pressure control devices, spherical preventers, tapered rubber core preventers, CAMERON TYPE D preventers, and CAMERON TYPE DL preventers.
Table 5 set forth examples of operating conditions for a laser module using a rotating cutting type laser delivery device.
High power laser systems, which may include, conveyance structures for use in delivering high power laser energy over great distances and to work areas where the high power laser energy may be utilized, or they may have a battery operated, or locally powered laser, by other means. Preferably, the system may include one or more high power lasers, which are capable of providing: one high power laser beam, a single combined high power laser beam, multiple high power laser beams, which may or may not be combined at various point or locations in the system, or combinations and variations of these.
A single high power laser may be utilized in the system, or the system may have two or three high power lasers, 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 in the range from about 455 nm (nanometers) to about 2100 nm, preferably in the range about 800 nm to about 1600 nm, about 1060 nm to 1080 nm, 1530 nm to 1600 nm, 1800 nm to 2100 nm, and more preferably about 1064 nm, about 1070-1080 nm, about 1360 nm, about 1455 nm, 1490 nm, or about 1550 nm, or about 1900 nm (wavelengths in the range of 1900 nm may be provided by Thulium lasers).
An example of this general type of fiber laser is the IPG YLS-20000. The detailed properties of which are disclosed in US patent application Publication Number 2010/0044106.
Examples of lasers, conveyance structures, high power laser fibers, high power laser systems, optics, connectors, cutters, and other laser related devices, systems and methods that may be used with, or in conjunction with, the present inventions are disclosed and taught in the following US patent application publications and US patent applications: Publication Number 2010/0044106; Publication Number 2010/0044105; Publication Number 2010/0044103; Publication Number 2010/0215326; Publication Number 2012/0020631; Publication Number 2012/0074110; Publication No. 2012/0068086; Ser. No. 13/403,509; Ser. No. 13/486,795; Ser. No. 13/565,345; Ser. No. 61/605,429; Ser. No. 61/605,434; Ser. No. 61/734,809; Ser. No. 61/786,763; and Ser. No. 61/98,597, the entire disclosures of each of which are incorporated herein by reference.
These various embodiments of conveyance structures may be used with these various high power laser systems. The various embodiments of systems and methods set forth in this specification may be used with other high power laser systems that may be developed in the future, or with existing non-high power laser systems, which may be modified in-part based on the teachings of this specification, to create a laser system. These various embodiments of high power laser systems may also be used with other conveyance structures that may be developed in the future, or with existing structures, which may be modified in-part based on the teachings of this specification to provide for the utilization of directed energy as provided for in this specification. Further the various apparatus, configurations, and other equipment set forth in this specification may be used with these conveyance structures, high power laser systems, laser delivery assemblies, connectors, optics and combinations and variations of these, as well as, future structures and systems, and modifications to existing structures and systems based in-part upon the teachings of this specification. Thus, for example, the structures, equipment, apparatus, and systems provided in the various Figures and Examples of this specification may be used with each other and the scope of protection afforded the present inventions should not be limited to a particular embodiment, configuration or arrangement that is set forth in a particular embodiment in a particular Figure.
Many other uses for the present inventions may be developed or realized and thus the scope of the present inventions is not limited to the foregoing examples of uses and applications. The present inventions may be embodied in other forms than those specifically disclosed herein without departing from their spirit or essential characteristics. The described embodiments are to be considered in all respects only as illustrative and not restrictive.
This application: (i) claims, under 35 U.S.C. §119(e)(1), the benefit of the filing date of Sep. 1, 2012, of provisional application Ser. No. 61/696,142, (ii) is a continuation-in-part of U.S. patent application Ser. No. 13/034,175, filed Feb. 24, 2011; (iii) is a continuation-in-part of U.S. patent application Ser. No. 13/034,183 filed Feb. 24, 2011; (iv) is a continuation-in-part of U.S. patent application Ser. No. 13/034,017 filed Feb. 24, 2011; and, (v) is a continuation-in-part of patent application Ser. No. 13/034,037 filed Feb. 24, 2011, the entire disclosures of each of which is incorporated herein by reference.
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| Number | Date | Country | |
|---|---|---|---|
| 20140000902 A1 | Jan 2014 | US |
| Number | Date | Country | |
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| 61696142 | Sep 2012 | US |
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