Patent Publication Number: US-9845652-B2

Title: Reduced mechanical energy well control systems and methods of use

Description:
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. 
    
    
     BACKGROUND OF THE INVENTION 
     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&#39;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&#39;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 &amp; 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. 
     SUMMARY 
     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  FIG. 20 . 
     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. 
    
    
     
       BRIEF DESCRIPTION OF THE DRAWINGS 
         FIG. 1  is a schematic view of an embodiment of a laser BOP stack in accordance with the present invention. 
         FIG. 2  is a schematic view of an embodiment of a laser BOP stack in accordance with the present invention. 
         FIG. 3A  is a side perspective view of an embodiment of a laser BOP stack in accordance with the present invention. 
         FIG. 3B  is a front perspective view of the embodiment of  FIG. 3A . 
         FIG. 4  is a schematic of an embodiment of a pipe being sheared. 
         FIG. 5  is a schematic of an embodiment of a pipe being sheared in accordance with the present invention. 
         FIG. 6  is a schematic showing an embodiment of a pipe being sheared in accordance with the present invention. 
         FIG. 7  is a chart providing computer simulation modeling data for the embodiments of  FIGS. 4, 5, and 6 . 
         FIG. 8  is a schematic diagram of an accumulator system in accordance with the present invention. 
         FIG. 9  is a schematic of an embodiment of a laser shear ram in accordance with the present invention. 
         FIG. 10  is a perspective view of an embodiment of a laser shear ram in accordance with the present invention. 
         FIG. 10A  is a perspective view of components of the embodiment of  FIG. 10 . 
         FIG. 10B  is a perspective view of components of the embodiment of  FIG. 10 . 
         FIG. 11  is a illustration of an embodiment of laser beam path and laser beam positioning in accordance with the present invention. 
         FIG. 12  is a perspective view of an embodiment of a slot in a tubular in accordance with the present invention. 
         FIG. 13  is a perspective view of an embodiment of a slot in a tubular in accordance with the present invention. 
         FIG. 14  is a perspective view of an embodiment of a slot in a tubular in accordance with the present invention. 
         FIG. 15A  is a perspective view of an embodiment of a slot in a tubular in accordance with the present invention. 
         FIG. 15B  is a perspective view of an embodiment of a slot in a tubular in accordance with the present invention. 
         FIG. 16A  is a schematic view of an embodiment of a slot position relative to laser rams in accordance with the present invention. 
         FIG. 16B  is a perspective view of an embodiment of a slot position relative to laser rams in accordance with the present invention. 
         FIG. 17A  is a schematic view of an embodiment of a slot position relative to laser rams in accordance with the present invention. 
         FIG. 17B  is a perspective view of an embodiment of a slot position relative to laser rams in accordance with the present invention. 
         FIG. 18  is a cross sectional view of an embodiment of a laser delivery assembly in an embodiment of a laser ram shear in accordance with the present invention. 
         FIG. 19  is a perspective view of an embodiment of a riser section in accordance with the present invention. 
         FIG. 20  is a schematic view of an embodiment of a laser fluid jet assembly in accordance with the present invention. 
         FIG. 21  is a perspective view of an embodiment of a slot in accordance with the present invention. 
         FIG. 22  is an embodiment of a slot in accordance with the present invention. 
         FIG. 23  is a schematic of a LMRP connector ESD (Emergency System Disconnect) in accordance with the present invention. 
         FIG. 23A  is an illustration of rig position for an LMRP connector ESD in accordance with the present invention. 
         FIG. 24  is a cross sectional view of the LMRP connector of the embodiment of  FIG. 23 . 
         FIG. 24A  is a cross sectional view of components of the embodiment of  FIG. 24  is an unlocked position. 
         FIG. 24B  is a cross sectional view of components of the embodiment of  FIG. 24  in a locked position. 
         FIG. 25A  is a face on illustration of an embodiment of a laser ram block in accordance with the present invention. 
         FIG. 25B  is a perspective view of the embodiment of  FIG. 25A . 
         FIG. 26  is perspective view of embodiments of positions and paths for the topside location and placement of the high power laser optical fiber cable in accordance with the present invention. 
         FIG. 27  is a perspective view of embodiments of positions and paths for the subsea location and placement of the high power optical fiber cable in accordance with the present invention. 
         FIG. 28  is a perspective cutaway view of an embodiment of a laser annular preventer. 
         FIG. 29  is a cross sectional schematic view of an embodiment of a laser annular preventer. 
     
    
    
     DESCRIPTION OF THE PREFERRED EMBODIMENTS 
     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 (“P max ”) the accumulator bank of the system can have and the minimum pressure (“P min ”) needed for the system to perform the closing operation, e.g., shearing and closing. Thus, CR=P max /P min . 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 CR sea 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 CR 12,000  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 P max  and P min . Thus, for this same system—CR 12,000 =6000 P max +5,350/3000 P min +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 P min  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 P min  of the system may be reduced to 750 psi, resulting in a CR 12,000  of 1.86 for a directed energy-mechanical energy system. CR 12000 −6000 P max +5,350/750 P min +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 P max  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 P min  would be 604 kJ, while the system having 3,000 P min  would be 2,426 kJ, as set forth in Table I (stroke is 9⅜ inched based upon 18¾ inch bore size, divided by two). 
     
       
         
           
               
               
               
               
               
               
               
             
               
                 TABLE 1 
               
               
                   
               
               
                 Piston 
                 Stroke 
                 Pistons 
                 Pressure 
                 Force 
                 Energy 
                 Energy 
               
               
                 Inch 
                 Inch 
                 Qty 
                 psi 
                 lbf 
                 ft-lb 
                 kJ 
               
               
                   
               
             
            
               
                   
               
            
           
           
               
               
               
               
               
               
               
            
               
                 22 
                 9.375 
                 2 
                 750 
                 285100 
                 445468 
                 604 
               
               
                 22 
                 9.375 
                 2 
                 3000 
                 1140398 
                 1781872 
                 2416 
               
               
                   
               
            
           
         
       
     
     The reduced temperature of the water at depth can have similar negative effects on CR. Thus, for example, a 6,000 psi charge P max  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&#39;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  FIG. 1  there is provided a schematic side view of an embodiment of a directed energy-mechanical energy BOP stack. The BOP stack  1003  has an upper section  1000 , and a lower section  1013 . The upper section  1000  has a flex joint  1012  for connecting to the riser (not shown in this figure), an annular preventer  1011 , a collet connector  1001 , a first control pod  1002   a , a second control pod  1002   b , and a choke and kill line connector  1020  (a second choke and kill line connector associated with the second control pod  1002   b  is on the back side of BOP stack  1003 , and is thus not shown in this figure). The first choke and kill lines  1014  extend from the connector  1020  in to the lower section  1013 . The lower section  1013  has an annular preventer  1004 , double ram  1005  BOP, and a laser double ram BOP  1008 . The lower section  1013  also has 100 accumulators, schematically shown in the drawing as two accumulators each in several accumulator banks, e.g.,  1006   a ,  1006   b ,  1006   c ,  1006   d ,  1006   e ,  1006   f . The lower section  1013  also has a wellhead connector  1010  that is shown attached to the wellhead  1009 . The accumulator banks, e.g.,  1006   a ,  1006   b ,  1006   c ,  1006   d ,  1006   e ,  1006   f , are positioned on a frame  1007  that is associated with the lower section  1013 . 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. 
     In an example of a closing and venting operation for the BOP of the embodiment of  FIG. 1 , the annular preventer  1004  may be closed around the drill pipe or other tubular located within the BOP cavity. The laser shear ram may be operated and closed cutting and then severing the drill pipe and sealing the well. During the laser cutting operation fluid from the laser cutting jet may be vented through the choke line, which is then closed upon, or after the sealing, of the shear ram blocks. 
     Turning to  FIG. 2  there is shown a perspective view of an embodiment of a laser BOP stack. The laser BOP stack  2000  has a lower marine riser package ((“LMRP”)  2012  that has a frame  2050  and a lower BOP section  2014  having a frame  2051 . The LMRP  2012  has a riser adapter  2002 , a flex joint  2004 , an upper annular preventer  2006 , and a lower annular preventer  2008 . The frame  2050  of the LMRP  2012  supports a first control module or pod  2010   a  and a second control module or pod  2010   b.    
     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  2030   a ,  2030   b ,  2030   c ,  2030   d , with each bank having two depth compensated accumulators, e.g.,  2031 . The depth compensated accumulators, and the accumulator banks, may be pressurized to a P max  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  FIGS. 3A and 3B  there is shown an embodiment of a BOP stack, with a front perspective view shown in  FIG. 3B  and a side perspective view shown in  FIG. 3A . The BOP stack  3000  has a riser adapter  3002 , a flex joint  3004 , an annular preventer  3006 , a LMRP connector  3008 , a laser blind shear ram  3010 , a laser casing shear ram  3011 , a first, second, third, fourth pipe rams,  3012 ,  3013 ,  3014 ,  3015  and a wellhead connector  3020 . There is a first choke and kill line  3005   a  and a second choke and kill line  3005   b . The laser beam for the laser casing shear ram is delivered from a subsea fiber laser having 20 kW of power and a battery power supply (for example batteries currently used for powering electric automobiles, could be used to power the laser to deliver sufficient directed energy through the laser beam to make the necessary weakening cuts), which may be located on the frame (not shown) for the BOP stack. A second battery powered 20 kW laser may also be associated with this BOP stack and serve as a back up laser beam supply should the optical fiber(s) to the surface laser become come damaged or broken. It should be noted that although the batteries in these systems represent potential energy, they would be potential energy that is converted into directed energy, and would not be considered a source of potential mechanical energy or as providing mechanical energy or power. 
     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. 
     
       
         
           
               
               
               
               
               
             
               
                 TABLE 2 
               
               
                   
               
               
                 Water Depth 
                 5,000 ft 
                 10,000 ft 
                 5,000 ft 
                 10,000 ft 
               
               
                   
               
             
            
               
                   
               
            
           
           
               
               
               
               
               
            
               
                 Mud density 
                 15 
                 15 
                 17 
                 17 
               
               
                 ppg(pounds per 
               
               
                 gallon) 
               
               
                 N2 volume 
                 28.2 
                 44.9 
                 30.9 
                 47.9 
               
               
                 (gal.) 
               
               
                 N2 volume BBL 
                 0.67 
                 1.07 
                 0.74 
                 1.14 
               
               
                 (barrels) 
               
               
                   
               
            
           
         
       
     
     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, (N 2 , water, brine, silicon oil, D 2 O) 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 (N 2 ), 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. 
     
       
         
           
               
             
               
                 TABLE 3 
               
             
            
               
                   
               
               
                 Accumulator Drivers 
               
            
           
           
               
               
            
               
                 Input Data 
                 Analysis Results 
               
            
           
           
               
               
               
               
               
               
               
               
               
               
               
               
               
               
            
               
                   
                   
                   
                   
                   
                 Total 
                   
                   
                   
                   
                 Surf. 
                 Surf. 
                 Sub- 
                   
               
               
                   
                   
                 Sea 
                 Well- 
                 Laser 
                 laser 
                   
                   
                 Avg. 
                 Total 
                 pre- 
                 pre- 
                 sea 
                   
               
               
                   
                 Water 
                 Head 
                 bore 
                 differ- 
                 press. 
                 Jet 
                   
                 flow 
                 flow 
                 charge 
                 charge 
                 charge 
                 Accum 
               
               
                   
                 Depth 
                 press. 
                 press. 
                 ential 
                 MOP 
                 fluid 
                 Time 
                 rate 
                 vol. 
                 temp 
                 press. 
                 press. 
                 Vol 
               
               
                 # 
                 ft 
                 psig 
                 psig 
                 press. 
                 psia 
                 Media 
                 sec. 
                 gpm 
                 gal 
                 F. 
                 psig 
                 Pisg 
                 gal 
               
               
                   
               
            
           
           
               
               
               
               
               
               
               
               
               
               
               
               
               
               
            
               
                 1 
                 1,000 
                 445 
                 45 
                 125 
                 585 
                 nitro. 
                 45 
                 45 
                 33.8 
                 70 
                 10,912 
                 11,104 
                 20 
               
               
                 2 
                 1,000 
                 445 
                 5,000 
                 125 
                 5,140 
                 nitro. 
                 45 
                 45 
                 33.8 
                 70 
                 10,912 
                 11,104 
                 170 
               
               
                 3 
                 1,000 
                 445 
                 10,000 
                 125 
                 10,140 
                 nitro. 
                 45 
                 45 
                 33.8 
                 70 
                 10,912 
                 11,104 
                 1,400 
               
               
                 4 
                 1,000 
                 445 
                 15,000 
                 125 
                 15,140 
                 nitro. 
                 45 
                 45 
                 33.8 
                   
                   
                   
                   
               
               
                 5 
                 1,000 
                 445 
                 445 
                 1,000 
                 1,460 
                 hydra. 
                 45 
                 8 
                 6.0 
                 70 
                 4.890 
                 11,230 
                 20 
               
               
                 6 
                 1,000 
                 445 
                 5,000 
                 1,000 
                 6,015 
                 hydra. 
                 45 
                 8 
                 6.0 
                 70 
                 8,935 
                 11,230 
                 50 
               
               
                 7 
                 1,000 
                 445 
                 10,000 
                 1,000 
                 11,015 
                 hydra. 
                 45 
                 8 
                 6.0 
                 70 
                 10,912 
                 11,230 
                 480 
               
               
                 8 
                 1,000 
                 445 
                 15,000 
                 1,000 
                 16,015 
                 hydra. 
                 45 
                 8 
                 6.0 
                   
                   
                   
                   
               
               
                 9 
                 5,000 
                 2,226 
                 2,226 
                 125 
                 2,366 
                 nitro. 
                 45 
                 45 
                 33.8 
                 70 
                 10,912 
                 10,068 
                 70 
               
               
                 10 
                 5,000 
                 2.226 
                 5,000 
                 125 
                 5,140 
                 nitro. 
                 45 
                 45 
                 33.8 
                 70 
                 10,912 
                 10,068 
                 170 
               
               
                 11 
                 5,000 
                 2,226 
                 10,000 
                 125 
                 10,140 
                 nitro. 
                 45 
                 45 
                 33.8 
                 70 
                 10,912 
                 10,068 
                 1,410 
               
               
                 12 
                 5,000 
                 2,226 
                 15,000 
                 125 
                 15,140 
                 nitro. 
                 45 
                 45 
                 33.8 
                   
                   
                   
                   
               
               
                 13 
                 5,000 
                 2,226 
                 2,226 
                 1,000 
                 3,241 
                 hydra. 
                 45 
                 8 
                 6.0 
                 70 
                 6,905 
                 11,152 
                 30 
               
               
                 14 
                 5,000 
                 2,226 
                 5,000 
                 1,000 
                 6,015 
                 hydra. 
                 45 
                 8 
                 6.0 
                 70 
                 9,486 
                 11,152 
                 40 
               
               
                 15 
                 5,000 
                 2,226 
                 10,000 
                 1,000 
                 11,015 
                 hydra. 
                 45 
                 8 
                 6.0 
                 70 
                 10,917 
                 11,152 
                 160 
               
               
                 16 
                 5,000 
                 2,226 
                 15,000 
                 1,000 
                 16,015 
                 hydra. 
                 45 
                 8 
                 6.0 
                   
                   
                   
                   
               
               
                 17 
                 10,000 
                 4,452 
                 4,452 
                 125 
                 4,592 
                 nitro. 
                 45 
                 45 
                 33.8 
                 70 
                 10,912 
                 8,885 
                 140 
               
               
                 18 
                 10,000 
                 4,452 
                 5,000 
                 125 
                 5,140 
                 nitro. 
                 45 
                 45 
                 33.8 
                 70 
                 10,912 
                 8,885 
                 170 
               
               
                 19 
                 10,000 
                 4,452 
                 10,000 
                 125 
                 10,140 
                 nitro. 
                 45 
                 45 
                 33.8 
                 70 
                 10,912 
                 8,885 
                 1,410 
               
               
                 20 
                 10,000 
                 4,452 
                 15,000 
                 125 
                 15,140 
                 nitro. 
                 45 
                 45 
                 33.8 
                   
                   
                   
                   
               
               
                 21 
                 10.000 
                 4,452 
                 4,452 
                 1,000 
                 5,467 
                 hydra. 
                 45 
                 8 
                 6.0 
                 70 
                 9,635 
                 11,055  
                 40 
               
               
                 22 
                 10,000 
                 4,452 
                 5,000 
                 1,000 
                 8,015 
                 hydra. 
                 45 
                 8 
                 6.0 
                 70 
                 10,121  
                 11,055 
                 40 
               
               
                 23 
                 10,000 
                 4.452 
                 10,000 
                 1,000 
                 11,015 
                 hydra. 
                 45 
                 8 
                 6.0 
                 70 
                 10,912  
                 11,055 
                 100 
               
               
                 24 
                 10.000 
                 4,452 
                 15,000 
                 1,000 
                 18,016 
                 hydra. 
                 45 
                 8 
                 6.0 
               
               
                   
               
            
           
         
       
     
     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., N 2 , 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  FIG. 20  there is provided an embodiment of a well bore pressure compensated system  2000  for a laser jet  2002 . Upon activation the valve  2007  would be opened causing the fluid in the BOP cavity  2001  to flow in and against the piston  2005 , having seals  2006 . Thus, the pressure from the BOP cavity is exerted against the bottom of the piston  2005 , which pressurizes the laser jet fluid in the tank  2004  to the same pressure as is present in the BOP cavity  2001 . In this manner the booster pump  2003 , which preferably is a piston type pump, would not have to over come the BOP cavity pressure to create, e.g., shoot, launch, the fluid jet into the BOP cavity. A pressure intensifier may be used, and thus create the fluid jet without the need for a booster pump. If seawater is used for the laser jet fluid, it could be sucked through a filter into the pump for forming the jet. 
     Turning to  FIG. 8  there is provided a schematic diagram of an embodiment of an accumulator system  8000  for providing potential energy to a BOP stack for use as, conversion into, mechanical energy, through the actuation of rams, in conjunction with a laser ram BOP system. Thus, in this embodiment the system  8000  has accumulator banks  8014   a ,  8104   b ,  8014   c ,  8014   d , which have pre-charge valves  8013   a ,  8013   b ,  8013   c ,  8013   d  respectively associated with the accumulator banks. The accumulator banks are connected through tubing having full open valves  8015   a ,  8015   b ,  8015   c , which in turn are in fluid communication through tubing with relief valve  8007 , pressure regulator  8009  (e.g., 1,800-3,000 psi), and a regulator by-pass  8008 . There is then a valve and gauge  8016 , and a relief value  8018 , which are located along the tubing which connects to the BOP rams  8024 , to the laser shear ram  8024   a , to the choke  8023 , and to the annular BOP  8022 . Four way valves, e.g.,  8017 , are associated with the rams, choke and annular. There is also associated and in fluid communication via tubing and valves in the system a check valve  8019 , a pressure regulator (e.g., 0-1,500 psi, 0-10.3 Mpa), and a valve and gauge  8021 . The system  8000  also has a fluid reservoir  8001 ; two pumps  8003 ,  8004 , which are associated via tubing with a test fluid line  8002 , a BOP test line or connection for another pump  8011 , a check valve  8010 , a check valve  8012 , a connector for another pump  8005 . Table 4 sets forth examples of powers and energy values that may be present and utilized in embodiments of such systems. 
     
       
         
           
               
               
               
               
               
               
               
             
               
                 TABLE 4 
               
               
                   
               
               
                   
                 Power in kW 
                   
                   
                   
                   
                   
               
               
                   
                 of delivered 
                   
                   
                   
                   
                   
               
               
                   
                 mechanical 
                   
                   
                   
                   
                   
               
               
                   
                 energy 
                 Potential 
                 Mechanical energy 
                   
                 Time of laser 
                 Directed 
               
               
                   
                 (based upon 
                 Energy kJ of 
                 delivered by shear 
                 Laser 
                 pattern 
                 Energy 
               
               
                 Example 
                 15 second 
                 Charged 
                 ram to laser 
                 power in 
                 delivery in 
                 delivered in 
               
               
                 No. 
                 shear time) 
                 accumulator 
                 effected area in kJ 
                 kW 
                 seconds 
                 kJ 
               
               
                   
               
             
            
               
                   
               
            
           
           
               
               
               
               
               
               
               
            
               
                 1 
                 60 
                 &gt;893 
                 893 
                 10 
                 30 
                 300 
               
               
                 2 
                 87 
                 &gt;1,305 
                 1,305 
                 20 
                 30 
                 600 
               
               
                 3 
                 67 
                 &gt;1,003 
                 1,003 
                 40 
                 15 
                 600 
               
               
                 4 
                 73 
                 &gt;1,091 
                 1,091 
                 40 
                 30 
                 1,200 
               
               
                 5 
                 30 
                 &gt;447 
                 447 
                 10 
                 30 
                 300 
               
               
                 6 
                 44 
                 &gt;657 
                 657 
                 20 
                 30 
                 600 
               
               
                 7 
                 33 
                 &gt;502 
                 502 
                 40 
                 15 
                 600 
               
               
                 8 
                 36 
                 &gt;546 
                 546 
                 40 
                 30 
                 1,200 
               
               
                 9 
                 89 
                 &gt;1340 
                 1340 
                 10 
                 30 
                 300 
               
               
                 10 
                 131 
                 &gt;1958 
                 1958 
                 20 
                 30 
                 600 
               
               
                 11 
                 100 
                 &gt;1505 
                 1505 
                 40 
                 15 
                 600 
               
               
                 12 
                 109 
                 &gt;1637 
                 1637 
                 40 
                 30 
                 1,200 
               
               
                 13 
                 15 
                 &gt;223 
                 223 
                 10 
                 30 
                 300 
               
               
                 14 
                 22 
                 &gt;326 
                 326 
                 20 
                 30 
                 600 
               
               
                 15 
                 17 
                 &gt;251 
                 251 
                 40 
                 15 
                 600 
               
               
                 16 
                 18 
                 &gt;273 
                 273 
                 40 
                 30 
                 1,200 
               
               
                 17 
                 119 
                 &gt;1786 
                 1786 
                 10 
                 30 
                 300 
               
               
                 18 
                 174 
                 &gt;2610 
                 2610 
                 20 
                 30 
                 600 
               
               
                 19 
                 134 
                 &gt;2006 
                 2006 
                 40 
                 15 
                 600 
               
               
                 20 
                 145 
                 &gt;2182 
                 2182 
                 40 
                 30 
                 1,200 
               
               
                   
               
            
           
         
       
     
     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. 
       FIG. 4 ,  FIG. 5 , and  FIG. 6  schematically showing three examples of approaches to shearing a pipe located in a BOP cavity. In  FIG. 8 , there is shown the brute force solely mechanical manner of using the potential energy in the accumulators to force standard shape rams  4001 ,  4002  through the tubular  4003 , creating two sections  4003   a ,  4003   b , In  FIG. 5 , there is shown a tubular  5003  that has two laser cuts  5005   a ,  5005   b , removing about 80% of is cross sectional area. Standard shear rams  5001 ,  5002  are then forced into and through the cut, e.g., weakened area  5020  of the tubular, severing it into two sections  5003   a ,  5003   b . In  FIG. 6 , there is shown a tubular  6003  that has two laser cuts  6005   a ,  6005   b , removing about 80% of is cross sectional area. Tapered shear rams  6001 ,  6002 , e.g., ram wedges, are then forced into the cuts  6005   a ,  6005   b  forcing the tubular apart, along its longitudinal axis. The ram wedges  6001 ,  6002  move into and through the cut, e.g., weakened area of the tubular  6020 , severing it into two section  6003   a ,  6003   b.    
     In  FIG. 7 , there are provided computer simulation modeling of the three approaches shown in  FIGS. 4, 5, and 6 . Where line  7008  represents the approach of  FIG. 4 , line  7009  represents the approach of  FIG. 5 , and line  7010  represent the approach of  FIG. 6 . A comparison of these lines shows the considerable reduction in the force needed to sever the tubular after the tubular has been weakened by the laser cuts. Additionally, the peak force required to sever the cut tubulars,  7011  is reduced by about 75,000 lbs when the wedge rams  6001 ,  6002 , are used, compared to the peak force  7019  for convention rams  901 ,  902  (both still being significantly reduced by the laser cuts, when compared with the non-laser cut  7008 ). In the simulation of  FIG. 7  the pipe cross-section area reduction along shearing plane due to the laser cut is 80% laser cut. For the standard pipe simulation Ram Max. force (klbs) is 530.78 and Ram Avg. force (klbs) is 199.16. For the laser cut pipe simulation Ram Max. force (klbs) is 152.51 (a 71% reduction) and the Ram Avg. force (klbs) is 83.61 (a 58% reduction). For the laser cut pipe with modified blades simulation the Ram Max. force (klbs) is 82.33 (a 84% reduction) and the Ram Avg. force (klbs) is 49.08 (a 75% reduction). Turning to  FIG. 9  there is provided a schematic representation of an embodiment of a laser shear ram. The laser shear ram configuration  900  has a moving block  903  and a stationary block  905 . It being understood that a second moving block may be used. The moving block  905  has two laser delivery assemblies,  902 ,  903  associated with it. Each laser delivery assembly  901 , 902  is optically associated with a source of a high power laser beam to provide the delivery of a 10 kW, or greater, laser beam to the tubular  904 , which is located between the blocks  903 ,  905  in the BOP cavity  906 . In this embodiment each laser delivery assembly will deliver the laser beam to the pipe  904  in the BOP cavity. If a second moving block is used, that moving block may also have two laser delivery assemblies configured in a similar manner to delivery assemblies  901 ,  902 . In operation the laser beams are fired, i.e., the laser beams are propagated from the laser delivery assemblies  901 ,  902  and travel along their respective beam paths  907 ,  908  to strike and cut the tubular  904 . As block  903  moves forward, further into the cavity  906 , along the direction of arrow  909 , the laser beams are moved along, and through, the side of the tubular  904 , cutting a slot in the tubular  904 . In this embodiment the laser beams&#39; focal points are located at an area  910 , which is about where the beams first strike the tubular  904 , and preferably slightly behind the inside wall of the tubular. Thus, as the bock  903  moves forward the laser beams will be striking the tubular at locations along the beam paths that are progressively further removed from the beams focal points, providing for a slot that increases in width from its starting point to its endpoint. This increase in width is proportional to the focal length of the laser beams. 
     Examples of such varying width cuts are shown in  FIGS. 12, 13, 14, 15A, 15B, and 21 ; and examples of a uniform width cut is shown in  FIG. 21 . Thus, in  FIG. 12  there is shown a single cut  1201 , in tubular  1200 . The cut  1201  has a length shown by arrow  1210 , and a width. The width changes from narrow  1220  to wide  1221 . The wide end of the cut is essentially circular, but could be other shapes, e.g., oval, diamond, square, keyed, etc., based upon the shape and position of the laser beam. In  FIG. 13  there is shown a single cut, which may be viewed as two of the cuts of  FIG. 12  joined at their narrow ends. This type of cut may be formed by the embodiment of the laser shear ram of  FIG. 10 .  FIG. 14  is a view of a similar type of cut to the embodiment shown in  FIG. 13 . In the embodiment of  FIG. 14 , there are two cuts  1402 ,  1403  each having a narrow or neck center section and wider rounded ends.  FIGS. 15A and 15B  show that different cross-sectional areas of the tubular may be removed, e.g., cut out, by the laser, with a greater cross-sectional area being removed in  FIG. 15A  as compared to  FIG. 15B . Thus, at least about 10%, at least about 25%, at least about 50%, at least about 75%, at least about 80% and at least about 90%, or more, of the cross-sectional area may be removed by the laser cut (or slot). Viewing the same property in a different manner, the length of the laser slot or cut in the tubular may be about 10%, at least about 25%, at least about 50%, at least about 75%, at least about 80%, and at least about 90%, or more, of the outside circumference of the tubular. It being understood that less than 10%, e.g., a small penetrating shot, and 100%, i.e., the laser completely severing the tubular, may employed. 
       FIG. 10  is a perspective schematic view of an embodiment of a laser shear ram BOP, and  FIGS. 10A and 10B  are components of that shear ram BOP, which are all shown in ghost or phantom lines to illustrate both outer and inner components of the assembly. The laser shear ram BOP  1000  has a cavity  1002  that has a tubular, e.g., drill pipe  1004 , in the cavity. (The total length of the drill pipe is not shown in this drawing, and may be hundreds, thousands, and tens-of-thousands of feet.) The laser shear ram BOP  1000  has two piston assemblies  1006 ,  1008  that drive, e.g., move, laser shear rams  1020 ,  1030  respectively into and out of the BOP cavity  1002 . The pistons may be driven, for example, by an accumulator system, such as shown in the embodiment of  FIG. 8 . Turning to  FIG. 10A  there is shown, in ghost or phantom lines, the internal laser delivery assemblies for the rams  1020 ,  1030 . (which may also be referred to as ram blades, ram blocks, blades or blocks). Ram  1020  has a first laser delivery assembly  1021 , and a second laser delivery assembly  1022 . Each laser delivery assembly  1021 ,  1022 , is capable of, and propagates a laser beam  1023 ,  1023  respectively along laser beam paths  1024 ,  1026 . The laser beam and beam path may be along a fluid jet. Ram  1030  has a first laser delivery assembly  1031 , and a second laser delivery assembly  1032 . Each laser delivery assembly  1031 ,  1032 , is capable of, and propagates a laser beam  1033 ,  1033  respectively along laser beam paths  1034 ,  1036 . The laser beam and beam path may be along a fluid jet. High power optical cables,  1060 ,  1061 ,  1062 ,  1063  are shown and provide high power laser energy from a high power laser, and may also transport the fluid(s), for the formation of a fluid laser jet. 
     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  FIG. 10 , preferably are each about 10 kW. The laser beams may have different powers, e.g., one beam at 10 kW, two beams at 20 kW and a fourth beam at 5 kW, they may all have the same power, e.g., each having 10 kW, each having 15 kW, each having 20 kW. Greater and lower powers, and variations and combinations of the forgoing beam power combinations may be used.  FIG. 10B  shows the laser rams of  FIG. 10A  in the completely closed and sealing position after the pipe has been severed. 
       FIG. 11  is a schematic perspective view of the relative position and characteristics of the laser beam path  1026  and laser beam  1024  with respect to the pipe  1004  in the BOP cavity  1002 . For clarity, only one of the four laser beam paths and laser beams of the embodiment of  FIG. 10  is shown in  FIG. 11 . It being understood that for this embodiment the other three beam paths,  1025 ,  1035 ,  1036 , and the other three laser beams  1023 ,  1033 ,  1034  are the same. In other embodiments the beam paths and beams may be different, and more or less beams and beam paths my be utilized. The arrow showing 9.84 inches is the distance from the center of the BOP cavity (18¾ inch diameter) to the face of the laser jet. Which in this embodiment is about ½ inch removed from the cavity. The beam path angle  1070 , which in this embodiment is 85.00°, is the angle of the beam path with respect to the ram actuator centerline. 
     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&#39;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  FIG. 16B  there is provided a perspective view of rams engaging a cut tubular and in  FIG. 16A  a top view schematic of this configuration. Thus, Ram faces  1610 ,  1620  are engaging the tubular  1650  that has cuts  1601 ,  1602 , which are positioned normal to the ram actuator centerline  1670 . (It being noted that the remaining tubular cross sectional material, i.e., uncut material, is parallel to the ram actuator centerline.) 
     In  FIG. 17B  there is provided a perspective view of rams engaging a cut tubular and in  FIG. 17A  a top view schematic of this configuration. Thus, Ram faces  1710 ,  1720  are engaging the tubular  1750  that has cuts  1701 ,  1702 , which are positioned parallel to the ram actuator centerline  1770 , (It being noted that the remaining tubular cross sectional material, i.e., uncut material, is normal to the ram actuator centerline.) 
       FIG. 18  is an illustrated diagram of an embodiment of a section of a ram block  1801 , having a laser delivery device  1802  integrated into the block. The laser delivery device  1802  has a prism  1803 , a laser jet nozzle  1804  that is directed toward the pipe  1805  to be cut by blade face  1806 . 
     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  FIG. 23A , as a series of circles showing the distance of the rig form the centerline. Thus, the inner circle  2312  may correspond to a distance where the angle  2311  is not larger enough to prevent the connector from disconnecting and the outer circle  2313  is the farthest away from centerline where the connector can be safely and reliably disconnected. 
     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  FIG. 23A , laser devices may be associated with the connector  2307 . In this manner the laser beam may be directed to a specific component of the connector, severing that component, freeing the mechanical comments to then operate and disengage. In this manner the operating angle can be increased, and any damage to the connector from the laser minimized. The laser device, or a second laser device, may also be associated with the connector in a manner that completely cuts the connection, should the mechanical components fail to operate properly. 
     For example, turning to  FIGS. 24, 24A, 24B , there is shown cross section of connector  2307 , and detailed enlargements of the locking components of that connector in a locked position,  FIG. 24B , and an unlocked position,  FIG. 24A . The connector  2307  has attachment bolts  2401  positioned on a body  2402  that forms a cavity  2403 . The body  2402  engages a member  2404  from the lower BOP stack  2306 . The locking, engagement, mechanism, in general, has an engagement member  2405  that has an engagement surface  2405   a  and a locking surface  2405   b . As the engagement member  2405  is moved downwardly, engagement surface  2405   a  engage engagement surface  2406   a  on locking member  2406 , moving locking member  2406  into locking engagement with member  2404 . As engagement member  2405  moves further down locking surface  2405   b  is positioned adjacent locking surface  2406   b , holding locking member  2406  into locked engagement with member  2404 . A laser delivery device  2450  may be placed inside of the body  2402 , and a laser beam path provided in the body, such that the laser beam can be delivered to the internal locking and engagement components of the connector. Thus, for example the laser beam could be direct to the locking surfaces, to the locking member, to the engagement member, to the means to move the engagement member, to other components or structures associated therewith, and combinations and variations of these. The laser device may also be located, or a second laser device may be employed to cut other structures of the connector assembly to effect a disconnect, such as the bolts  2401 , the body  2402 , the member  2404 , or the member attached to bolts  2404  (but which is not shown in the figures), and combinations and variations of these. Preferably the laser beam device, laser beam path and intended target for the laser beam is a component, structure or area that causes minimal damage, is easily reparable or replaceable, but at the same, time provides a high likelihood of effecting a disconnect. 
       FIG. 19  is a perspective view of a riser section  1900  having a choke line  1901 , a boost line  1902 , a kill line  1903 , and a BOP hydraulics line  1904 . As discussed in these specifications these lines, or additional lines, could be used to carry or contain the high power laser fiber, the laser conduct, the fluid conveyance tubes, and in general the components and materials needed to operate the fluid laser jet(s). 
     Turning to  FIGS. 25A and 25B  there are face on view and a perspective view of a laser ram block in relations to a pipe. The ram block  2500  has two laser delivery assemblies  2502 ,  2503  are positioned in the block  2500  and deliver laser beams  2505 ,  2504  to pipe  2501 . The angle of the laser beams with respect to he longitudinal axis of the pipe (and in the illustration the cavity axis) can be seen. The laser beams  2505 ,  2504  have a slight downward angle, that may be at least about 2° below horizontal, at least about 5°, and at least about 10°. The laser beams make cuts  2525 ,  2526  in pipe  2501 . 
     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  2626   a , e.g., near the diverter  2601 ; at or near position  2626   b , e.g., below the space out joint  2603 ; at or near position  2626   c , e.g., below the tensioners  2606 ; or at or near position  2626   d , 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 . 
       FIG. 27  is a schematic view of an embodiment of a subsea system that may be used with a drilling rig, e.g., a drill ship, semi-submersible, jack-up, etc., and a laser BOP system, and may be used with the surface system of the embodiment of  FIG. 26 . The subsea system  2700  may have a riser joint  2701 , a flex joint  2702 , an annular preventer  2703   a , and an annular preventer  2703   b , an EDP hydraulic connector  2705 , BOP rams  2704   a ,  2704   b ,  2704   c ,  2704   d , and a hydraulic connector or a wellhead  2706 . The high power laser fiber, the high power laser fluid jet conduits, or conveyance structures, may enter into the subsea system  2700  at many points. One or more of the BOP rams and annular preventers may be laser rams and laser preventers. Thus, the laser fiber, fluid conveyance system and fluid laser jet conduit above the annular preventer, below the flex joint, below the annular preventer, between the annular preventer, at the annular preventer, at, above or below the EDP connector, and at or in the area of the BOP rams. 
     Turning to  FIG. 28  there is provided a cutaway perspective view of an embodiment of a laser annular preventer  2801 . The laser annular preventer  2801  may have an outer housing  2802 , a central axis  2803 , a cavity  2804 , an annular assembly  2805 . The annular assembly  2805  has an elastomeric body  2806 , which has several metal inserts, e.g.,  2807 , which are positioned in the elastomeric body  2806  and around that body. The assembly  2805  has a cavity  2808  that is connected to, and forms a part of cavity  2804 . A piston chamber  2809  is has a piston  2811 , and an external port  2810 . The piston  2811  drives wedges, e.g.,  2812  against the elastomeric body  2806  forcing it and the metal inserts, e.g.,  2807 , into cavity  2808 . There is also a retract port  2817  and a cavity  2820  that will be associated with the BOP cavity. Within the metal inserts  2807  that is a laser delivery assembly  2850 , which provides a laser beam path and delivers a high power laser beam into the cavity  2808 . Thus, as the wedge  2812  is driven up the elastomeric body  2806 , which carries the metal inserts moves into the cavity  2808  and movers closer to and seals against any tubular in the cavity  2808 . One metal insert may have a laser device, two metal inserts may each have a laser device, and three or more metal inserts may each have laser devices. The laser devices may be positioned around the cavity, opposite to each other, at thirds, quarters or other arrangements. More than one laser delivery device may be located in a metal insert. As the metal inserts are moved into the cavity the distance of the beam free path, the distance from when the laser beam leaves the laser device and strikes the pipe, is reduced and potentially reduced to essentially zero, as the metal insert mores toward and potentially contacts the pipe. Preferably the metal inserts are spaced a slight distance away from the pipe with the elastomer member forming a seal against the pipe and thus shielding the laser beam path to the pipe from the formation fluids, drilling fluids and pressures that are below the annular. Further, a second annular, or other type of sealing member may be located above the metal inserts. This second or upper sealing member can then be sealed against the pipe creating a sealed cavity that essentially isolates the laser beam path from conditions both above and below the cavity. A vent or relief valve preferably can be located in, or associated, with the upper sealing member to provide a relief port for the laser jet fluid that is used, added into the sealed cavity, during the laser cutting process. 
     Turning to  FIG. 29  is a cross section of an embodiment of a laser module an annular preventer. The laser modules  2926   a ,  2926   b  are located above the annular prevent elastomeric body  2902  and wedge  2993 . As the elastomeric body grabs and holds a pipe in the cavity  2901  it will center the pipe providing a constant distance for the laser beam path from the laser module to the pipe. The laser modules may rotate around the pipe providing for a complete cut. 
     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. 
     
       
         
           
               
               
               
               
               
               
               
               
               
               
             
               
                 TABLE 5 
               
               
                   
               
               
                 Sample 
                 Power 
                 Offset 
                 Time 
                 Beam Size 
                 Focal Length 
                 Nozzle Diameter 
                 Angular Offset 
                 Warm Up Time 
                 % Cross Section 
               
               
                   
               
             
            
               
                   
               
            
           
           
               
               
               
               
               
               
               
               
               
               
            
               
                 1 
                 10 kW 
                 .5″-2″ 
                 10 
                 0.18 
                 500 MM 
                 0.325 
                 10 Deg 
                 2 s 
                 50 
               
               
                 2 
                 10 kW 
                 .5″-2″ 
                 10 
                 0.18 
                 500 MM 
                 0.325 
                 10 Deg 
                 2 s 
                 50 
               
               
                 3 
                 10 kW 
                 .5″-2″ 
                 5 
                 0.18 
                 500 MM 
                 0.325 
                 10 Deg 
                 2 s 
                 25 
               
               
                 4 
                 10 kW 
                 .5″-2″ 
                 5 
                 0.18 
                 500 MM 
                 0.325 
                 10 Deg 
                 2 s 
                 25 
               
               
                 5 
                 10 kW 
                 .5″-2″ 
                 3 
                 0.18 
                 500 MM 
                 0.325 
                 10 Deg 
                 2 s 
                 12.5 
               
               
                 6 
                 10 kW 
                 .5″-2″ 
                 3 
                 0.18 
                 500 MM 
                 0.325 
                 10 Deg 
                 2 s 
                 12.5 
               
               
                 7 
                 10 kW 
                 .5″-2″ 
                 1.5 
                 0.18 
                 500 MM 
                 0.325 
                 10 Deg 
                 2 s 
                 6.25 
               
               
                 8 
                 10 kW 
                 .5″-2″ 
                 1.5 
                 0.18 
                 500 MM 
                 0.325 
                 10 Deg 
                 2 s 
                 6.25 
               
               
                 9 
                 TBD 
                 TBD 
                 TBD 
                 TBD 
                 TBD 
                 TBD 
                 TBD 
                 TBD 
                 TBD 
               
               
                 10 
                 TBD 
                 TBD 
                 TBD 
                 TBD 
                 TBD 
                 TBD 
                 TBD 
                 TBD 
                 TBD 
               
               
                 11 
                 TBD 
                 TBD 
                 TBD 
                 TBD 
                 TBD 
                 TBD 
                 TBD 
                 TBD 
                 TBD 
               
               
                 Rotary 
                 17.3 Kw   
                 .030″ 
                 7.5 
                 0.04 
                 250 MM 
                 0.06 
                  0 Deg 
                 5s 
                 100% 
               
               
                 Axial 
                 20 Kw 
                 .060″ 
                 40 
                 0.18 
                 500 MM 
                 0.325 
                  1 Deg 
                 5s 
                 100% 
               
               
                   
               
            
           
         
       
     
     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.