Abstract:
Existing BOP devices are complex electromechanical systems exploiting hydraulic activation of pipe rams and/or shear rams. With tens of thousands of oil wells in the 1,500 oil fields that account for 97% of global production of the over 40,000 oil fields identified to date and failure rates as high as 50% in disaster situations it is evident that a simpler, increased reliability approach would be beneficial to the oil and gas industries. It would be further beneficial if the BOP was automatic requiring no monitoring locally to the BOP or remotely from the rig or production facility.

Description:
CROSS-REFERENCE TO RELATED APPLICATIONS 
       [0001]    This patent application claims the benefit of U.S. Provisional Patent Application 61/481,798 filed May 3, 2011 entitled “Blow Out Preventer Method and Apparatus.” 
     
    
     FIELD OF THE INVENTION 
       [0002]    This invention relates to blowout preventers and more specifically to low complexity automatic blowout preventers. 
       BACKGROUND OF THE INVENTION 
       [0003]    Over the last two centuries, advances in technology have made our civilization completely oil, gas &amp; coal dependent. Whilst gas and coal are primarily use for fuel oil is different in that immense varieties of products are and can be derived from it. A “brief” list of some of these products includes gasoline, diesel, fuel oil, propane, ethane, kerosene, liquid petroleum gas, lubricants, asphalt, bitumen, cosmetics, petroleum jelly, perfume, dish-washing liquids, ink, bubble gums, car tires, etc. In addition to these oil is the source of the starting materials for most plastics that form the basis of a massive number of consumer and industrial products. 
         [0004]    Table 1 below lists the top 15 consuming nations based upon 2008 data in terms of thousands of barrels (bbl) and thousand of cubic meters per day.  FIG. 1A  presents the geographical distribution of consumption globally. 
         [0000]    
       
         
               
             
               
               
               
               
             
               
               
               
               
             
           
               
                 TABLE 1 
               
             
             
               
                   
               
               
                 2008 Oil Consumption for Top 15 Consuming Nations 
               
             
          
           
               
                   
                 Nation 
                 (1000 bbl/day) 
                 (1000 m 3 /day)            
               
               
                   
                   
               
             
          
           
               
                 1 
                 United States 
                 19,497.95 
                 3,099.9 
               
               
                 2 
                 China 
                 7,831.00 
                 1,245.0 
               
               
                 3 
                 Japan 
                 4,784.85 
                 760.7 
               
               
                 4 
                 India 
                 2,962.00 
                 470.9 
               
               
                 5 
                 Russia 
                 2,916.00 
                 463.6 
               
               
                 6 
                 Germany 
                 2,569.28 
                 408.5 
               
               
                 7 
                 Brazil 
                 2,485.00 
                 395.1 
               
               
                 8 
                 Saudi Arabia 
                 2,376.00 
                 377.8 
               
               
                 9 
                 Canada 
                 2,261.36 
                 359.5 
               
               
                 10 
                 South Korea 
                 2,174.91 
                 345.8 
               
               
                 11 
                 Mexico 
                 2,128.46 
                 338.4 
               
               
                 12 
                 France 
                 1,986.26 
                 315.8 
               
               
                 13 
                 Iran (OPEC) 
                 1,741.00 
                 276.8 
               
               
                 14 
                 United Kingdom 
                 1,709.66 
                 271.8 
               
               
                 15 
                 Italy 
                 1,639.01 
                 260.6 
               
               
                   
               
             
          
         
       
     
         [0005]    In terms of oil production Table 1B below lists the top 15 oil producing nations and the geographical distribution worldwide is shown in  FIG. 1B . Comparing Table 1A and Table 1B shows how some countries like Japan are essentially completely dependent on oil imports whilst most other countries such as the United States in the list whilst producing significantly are still massive importers. Very few countries, such as Saudi Arabia and Iran are net exporters of oil globally. 
         [0000]    
       
         
               
             
               
               
               
               
             
               
               
               
               
             
           
               
                 TABLE 2 
               
             
             
               
                   
               
               
                 Top 15 Oil Producing Nations 
               
             
          
           
               
                   
                 Nation 
                 (1000 bbl/day) 
                 Market Share 
               
               
                   
                   
               
             
          
           
               
                 1 
                 Saudi Arabia 
                 9,760 
                 11.8% 
               
               
                 2 
                 Russia 
                 9,934 
                 12.0% 
               
               
                 3 
                 United States 
                 9,141 
                 11.1% 
               
               
                 4 
                 Iran (OPEC) 
                 4,177 
                 5.1% 
               
               
                 5 
                 China 
                 3,996 
                 4.8% 
               
               
                 6 
                 Canada 
                 3,294 
                 4.0% 
               
               
                 7 
                 Mexico 
                 3,001 
                 3.6% 
               
               
                 8 
                 UAE (OPEC) 
                 2,795 
                 3.4% 
               
               
                 9 
                 Kuwait (OPEC) 
                 2,496 
                 3.0% 
               
               
                 10 
                 Venezuela (OPEC) 
                 2,471 
                 3.0% 
               
               
                 11 
                 Norway 
                 2,350 
                 2.8% 
               
               
                 12 
                 Brazil 
                 2,577 
                 3.1% 
               
               
                 13 
                 Iraq (OPEC) 
                 2,400 
                 2.9% 
               
               
                 14 
                 Algeria (OPEC) 
                 2,126 
                 2.6% 
               
               
                 15 
                 Nigeria (OPEC) 
                 2,211 
                 2.7% 
               
               
                   
               
             
          
         
       
     
         [0006]    In terms of oil reserves then these are dominated by a relatively small number of nations as shown below in Table 3 and in  FIG. 1C . With the exception of Canada the vast majority of these oil reserves are associated with conventional oil fields. Canadian reserves being dominated by Athabasca oil sands which are large deposits of bitumen, or extremely heavy crude oil, located in northeastern Alberta, Canada. The stated reserves of approximately 170,000 billion barrels is based upon only 10% of total actual reserves, these being those economically viable to recover in 2006. 
         [0000]    
       
         
               
             
               
               
               
               
             
               
               
               
               
             
           
               
                 TABLE 3 
               
             
             
               
                   
               
               
                 Top 15 Oil Reserve Nations 
               
             
          
           
               
                   
                 Nation 
                 Reserves (1000 bbl) 
                 Share 
               
               
                   
                   
               
             
          
           
               
                 1 
                 Saudi Arabia 
                 264,600,000 
                 19.00% 
               
               
                 2 
                 Canada 
                 175,200,000 
                 12.58% 
               
               
                 3 
                 Iran 
                 137,600,000 
                 9.88% 
               
               
                 4 
                 Iraq 
                 115,000,000 
                 8.26% 
               
               
                 5 
                 Kuwait 
                 104,000,000 
                 7.47% 
               
               
                 6 
                 United Arab Emirates 
                 97,800,000 
                 7.02% 
               
               
                 7 
                 Venezuela 
                 97,770,000 
                 7.02% 
               
               
                 8 
                 Russia 
                 74,200,000 
                 5.33% 
               
               
                 9 
                 Libya 
                 47,000,000 
                 3.38% 
               
               
                 10 
                 Nigeria 
                 37,500,000 
                 2.69% 
               
               
                 11 
                 Kazakhstan 
                 30,000,000 
                 2.15% 
               
               
                 12 
                 Qatar 
                 25,410,000 
                 1.82% 
               
               
                 13 
                 China 
                 20,350,000 
                 1.46% 
               
               
                 14 
                 United States 
                 19,120,000 
                 1.37% 
               
               
                 15 
                 Angola 
                 13,500,000 
                 0.97% 
               
               
                   
               
             
          
         
       
     
         [0007]    Therefore in the vast majority of wells are drilled into oil reservoirs to extract the crude oil. “Natural lift” production methods that rely on the natural reservoir pressure to force the oil to the surface are usually sufficient for a while after reservoirs are first tapped. In some reservoirs, such as in the Middle East, the natural pressure is sufficient over a long time. The natural pressure in many reservoirs, however, eventually dissipates. Then the oil must be pumped out using “artificial lift” created by mechanical pumps powered by gas or electricity. Over time, these “primary” methods become less effective and “secondary” production methods may be used. A common secondary method is “waterflood” or injection of water into the reservoir to increase pressure and force the oil to the drilled shaft or “wellbore.” Eventually “tertiary” or “enhanced” oil recovery methods may be used to increase the oil&#39;s flow characteristics by injecting steam, carbon dioxide and other gases or chemicals into the reservoir. In the United States, primary production methods account for less than 40% of the oil produced on a daily basis, secondary methods account for about half, and tertiary recovery the remaining 10%. 
         [0008]    An oil well is created by drilling a hole 5 to 50 inches (127.0 mm to 914.4 mm) in diameter into the earth with a drilling rig that rotates a drill string with a bit attached. After the hole is drilled, sections of steel pipe (casing), slightly smaller in diameter than the borehole, are placed in the hole. Cement may be placed between the outside of the casing and the borehole to provide structural integrity and to isolate high pressure zones from each other and from the surface. With these zones safely isolated and the formation protected by the casing, the well can be drilled deeper, into potentially more unstable formations, with a smaller bit, and also cased with a smaller size casing. Typically wells have two to five sets of subsequently smaller hole sizes drilled inside one another, each cemented with casing. 
         [0009]    During drilling, the drill bit, aided by the weight of thick walled pipes called “drill collars” above it, cuts into the rock and drilling fluid, commonly referred to as “mud”, is pumped down the inside of the drill pipe and exits at the drill bit. Drilling mud is a complex mixture of fluids, solids and chemicals that must be carefully tailored to provide the correct physical and chemical characteristics required to safely drill the well. Particular functions of the drilling mud include cooling the bit, lifting rock cuttings to the surface, preventing destabilisation of the rock in the wellbore walls and overcoming the pressure of fluids inside the rock so that these fluids do not enter the wellbore. 
         [0010]    Watching for abnormalities in the returning cuttings and monitoring pit volume or rate of returning fluid are imperative to catch “kicks” early. A “kick” is when the formation pressure at the depth of the bit is more than the hydrostatic head of the mud above, which if not controlled temporarily by closing the blowout preventers and ultimately by increasing the density of the drilling fluid would allow formation fluids and mud to come up through the drill pipe uncontrollably. The pipe or drill string to which the bit is attached is gradually lengthened as the well gets deeper by screwing in additional 30-foot (9 m) sections or “joints” of pipe under the kelly or topdrive at the surface. 
         [0011]    After drilling and casing the well, it must be ‘completed’. Completion is the process in which the well is enabled to produce oil or gas. In a cased-hole completion, small holes called perforations are made in the portion of the casing which passed through the production zone, to provide a path for the oil to flow from the surrounding rock into the production tubing. Finally, the area above the reservoir section of the well is packed off inside the casing, and connected to the surface via a smaller diameter pipe called tubing. This arrangement provides a redundant barrier to leaks of hydrocarbons as well as allowing damaged sections to be replaced. Also, the smaller cross-sectional area of the tubing produces reservoir fluids at an increased velocity in order to minimize liquid fallback that would create additional back pressure, and shields the casing from corrosive well fluids. 
         [0012]    In many wells, the natural pressure of the subsurface reservoir is high enough for the oil or gas to flow to the surface. However, this is not always the case, especially in depleted fields where the pressures have been lowered by other producing wells, or in low permeability oil reservoirs. Installing smaller diameter tubing may be enough to help the production, but artificial lift methods may also be needed. Common solutions include downhole pumps, gas lift, or surface pump jacks. 
         [0013]    The production stage is the most important stage of a well&#39;s life, when the oil and gas are produced. By this time, the oil rigs and workover rigs used to drill and complete the well have moved off the wellbore, and the top is usually outfitted with a collection of valves called a Christmas tree or Production tree. These valves regulate pressures, control flows, and allow access to the wellbore in case further completion work is needed. From the outlet valve of the production tree, the flow can be connected to a distribution network of pipelines and tanks to supply the product to refineries, natural gas compressor stations, or oil export terminals. As long as the pressure in the reservoir remains high enough, the production tree is all that is required to produce the well. If the pressure depletes and it is considered economically viable, an artificial lift method mentioned in the completions section can be employed. 
         [0014]    As outlined above the downhole fluid pressures are controlled in modern wells through the balancing of the hydrostatic pressure provided by the mud used. Should the balance of the drilling mud pressure be incorrect then formation fluids (oil, natural gas and/or water) begin to flow into the wellbore and up the annulus (the space between the outside of the drill string and the walls of the open hole or the inside of the last casing string set), and/or inside the drill pipe. This is commonly called a kick. If the well is not shut in (common term for the closing of the blow-out preventer valves), a kick can quickly escalate into a blowout when the formation fluids reach the surface, especially when the influx contains gas that expands rapidly as it flows up the wellbore, further decreasing the effective weight of the fluid. Additional mechanical barriers such as blowout preventers (BOPs) can be closed to isolate the well while the hydrostatic balance is regained through circulation of fluids in the well. 
         [0015]    A kick can be the result of improper mud density control, an unexpected over-pressured gas pocket, or may be a result of the loss of drilling fluids to a formation called a thief zone. If the well is a development well, these thief zones should already be known to the driller and the proper loss control materials would have been used. However, unexpected fluid losses can occur if a formation is fractured somewhere in the open-hole section, causing rapid loss of hydrostatic pressure and possibly allowing flow of formation fluids into the wellbore. Shallow over-pressured gas pockets are generally unpredictable and usually cause the more violent kicks because of rapid gas expansion almost immediately.[citation needed] 
         [0016]    The first response to detecting a kick would be to isolate the wellbore from the surface by activating the blow-out preventers and closing in the well. Then the drilling crew would attempt to circulate in a heavier kill fluid to increase the hydrostatic pressure (sometimes with the assistance of a well control company). In the process, the influx fluids will be slowly circulated out in a controlled manner, taking care not to allow any gas to accelerate up the wellbore too quickly by controlling casing pressure with chokes on a predetermined schedule. 
         [0017]    In a simple kill, once the kill-weight mud has reached the bit the casing pressure is manipulated to keep drill pipe pressure constant (assuming a constant pumping rate); this will ensure holding a constant adequate bottom hole pressure. The casing pressure will gradually increase as the contaminant slug approaches the surface if the influx is gas, which will be expanding as it moves up the annulus and overall pressure at its depth is gradually decreasing. This effect will be minor if the influx fluid is mainly salt water. And with an oil-based drilling fluid it can be masked in the early stages of controlling a kick because gas influx may dissolve into the oil under pressure at depth, only to come out of solution and expand rather rapidly as the influx nears the surface. Once all the contaminant has been circulated out, the casing pressure should have reached zero. 
         [0018]    Sometimes, however, companies drill underbalanced for better, faster penetration rates and thus they “drill for kicks” as it is more economically sound to take the time to kill a kick than to drill overbalanced (which causes slower penetration rates). 
         [0019]    In deep subsea applications, a number of problems may arise. Firstly, because of the pressures involved, everything becomes significantly more complicated. The pressure that bears down on the formation includes the weight of the drilling mud, whereas the pressure in the shallow formations is dictated by the weight of seawater above the formation. Because of the higher pressures involved, the drilling mud may actually be injected into the formation, fracture it and may even clog or otherwise foul the formation itself, severely impairing potential production. 
         [0020]    Within the prior art there are disclosed a wide variety of blowout (or blow out) preventers (BOPs) and tubular-shearing blades for BOPs. Typical BOPs have selectively actuatable rams housings secured to the body which are either pipe rams (to contact, engage, and encompass the pipe and/or tools to seal a wellbore) or shear rams (to contact and physically shear a tubular, casing, pipe or tool used in wellbore operations). Rams typically upon activation and subsequent shearing of a tubular, are designed to seal against each other over a center of a wellbore so that the pipe is sealed. 
         [0021]    BOPs and tubular-shearing blades for them are disclosed in many U.S. patents, including, but not limited to, U.S. Pat. Nos. 2,752,119; 3,272,222; 3,554,278; 3,561,526; 3,692,316; 3,736,982; 3,744,749; 3,817,326; 3,827,668; 3,863,667; 3,946,806; 3,955,622; 4,043,389; 4,057,887; 4,081,027; 4,132,265; 4,132,267; 4,313,496; 4,253,638; 4,347,898; 4,476,935; 4,492,359, 4,504,037, 4,523,639, 4,537,250; 4,540,046; 4,550,895; 4,554,976; 4,558,842; 4,646,825; 4,923,005; 4,923,008; 4,969,390; 5,013,005; 5,025,708; 5,056,418; 5,360,061; 5,400,857; 5,505,426; 5,515,916; 5,529,127; 5,575,451; 5,575,452; 5,653,418; 5,655,745; 5,713,581; 5,918,851; 5,979,943; 6,044,690; 6,158,505; 6,173,770; 6,244,336; 7,032,691; 7,207,382; 7,234,530; 7,354,026; 7,367,396; 7,703,739; and 7,814,979 as well as US Patent Application Nos. 2005/0,092,522; 2006/0,021,749; 2006/0,038,147; 2006/0,090,899; 2006/0,144,586; 2006/0,191,716; 2008/0,001,107; 2009/0,127,482; 2009/0,314,544; and 2010/0,319,906. 
         [0022]    Blowouts, originally known as gushers were an icon of oil exploration during the late 19th and early 20th centuries, producing large amounts of oil, often shooting 200 feet (60 m) or higher into the air. Despite being originally symbols of new-found wealth, gushers are dangerous and wasteful. They can kill oil workers involved in drilling, destroy equipment including complete oil rigs, see for example Deepwater Horizon in Gulf of Mexico in April 2010, and coat the landscape with thousands or tens of thousands of barrels of oil per day. In addition, output of a well blowout might include sand, mud, rocks, drilling fluid, natural gas, water, and other substances. Blowouts will often be ignited by an ignition source, from sparks from rocks being ejected, or simply from heat generated by friction. 
         [0023]    Whilst surface blowouts on oil wells drilled on land can be difficult to deal with it is very difficult to deal with a blowout in very deep water because of the remoteness and limited experience with this type of situation. Using the world&#39;s most authoritative database of oil rig accidents, a Norwegian company, Det Norske Veritas, focused on some 15,000 wells drilled off North America and in the North Sea from 1980 to 2006 in analyzing blowouts. They found 11 cases where crews on deepwater rigs had lost control of their wells and then activated BOPs to prevent a spill. In only six of those cases were the wells brought under control, leading the researchers to conclude that in actual practice, BOPs used by deepwater rigs had a “failure” rate of 45 percent.” 
         [0024]    A 2002 study commissioned by the U.S. Minerals Management Service, the agency that oversees the offshore oil industry, found that 50 percent of the shear rams tested failed to cut through pipe and halt the flow of oil. Additionally the U.S. Minerals Management Service has identified 117 failures of BOPs during a two-year period in the late 1990s on the outer continental shelf of the United States. The unclassified version of the report identifying that the failures involved 83 wells drilled by 26 rigs in depths from 1,300 feet to 6,560 feet. A similar report released by the agency in 1997 found that between 1992 and 1996 there were 138 failures of BOPs on underwater wells being drilled off Brazil, Norway, Italy and Albania. 
         [0025]    Shanks et al in “Deepwater BOP Control Systems—A Look at Reliability Issues” (2003 Offshore Technology Conference, Paper 15194) and considered the reliability of components within the BOP on the basis of a 5 year deployment and with regular testing. For offshore floating drilling operations, especially in deepwater, Shanks considered a BOP control system associated with dynamically positioned (DP) rigs is typically a Multiplexed Electro-Hydraulic (MUX) Control System as depicted in  FIG. 1D . The demand on the subsea control system is initiated at the surface. The demand signal is multiplexed down the control umbilical to the subsea control system. There, the signal is decoded, confirmed, and performed. For a demand that requires a BOP Ram to close, for example, the multiplex signal would be received at the subsea control pod and decoded. The decoded signal would cause a solenoid to be opened electrically which would send a hydraulic pilot signal to the proper hydraulic valve. This pilot signal would cause the hydraulic valve to shift and send stored and pressurized hydraulic fluid to the BOP Ram to be closed. 
         [0026]    Therefore, the subsea BOP control system consists of two basic elements: electrical and hydraulic components. Historically more subsea problems have been associated with the hydraulic components than the electrical. In routine production failures of a BOP may result in the BOP and riser being retrieved for repair resulting in significant revenue loss to the oil production company. In other instances these failures may lead to catastrophic consequences such as witnessed with the Deepwater Horizon disaster and the subsequent damage to marine ecosystems and economic damage to entire regions of the U.S. gulf coast. 
         [0027]    Each subsea BOP system has two complete control pods. Each pod is capable of performing all necessary functions on the BOP. While these systems may be considered redundant, any major problem associated with one pod will cause the system to be retrieved to the surface for repair. If a major problem is found, the control of the subsea BOP is transferred to the other pod and preparations will be made to retrieve the lower marine riser package (LMRP) and riser to surface. Some minor problems may not require the system to be retrieved if considered not necessary for critical operations. 
         [0028]    Shanks assessed the BOP as comprising 24 accumulators, 22 check valves, 6 pilot check valves, 38 dual action pilot valves, 42 single action pilot valves, 12 regulators, 74 shuttle valves and 142 solenoid valves. Based upon the 5 year deployment scenario and regular testing these accounted for over 87,000 operations subsea where at any point flawless operation in a real event would be required. 
         [0029]    Accordingly it would be evident that existing BOP devices are complex electromechanical systems exploiting hydraulic activation of pipe rams and/or shear rams. With tens of thousands of oil wells in the 1,500 oil fields that account for 97% of global production of the over 40,000 oil fields identified to date and failure rates as high as 50% in disaster situations it is evident that a simpler, increased reliability approach would be beneficial to the oil and gas industries. It would be further beneficial if the BOP was automatic requiring no monitoring locally to the BOP or remotely from the rig or production facility. 
         [0030]    BOPs according to the prior art with shear rams are single occurrence devices intended to shear and block the riser pipe. It would be beneficial if the BOP allowed multiple operations and reset under a relaxation of the pressure within the riser. 
       SUMMARY OF THE INVENTION 
       [0031]    It is an object of the present invention to mitigate one or more disadvantages of the prior art with respect to blowout preventers and more specifically to low complexity automatic blowout preventers. 
         [0032]    In accordance with an embodiment of the invention there is provided a method comprising:
   providing a ring assembly attached to the inner surface of a pipe comprising an opening of predetermined geometry;   providing a compliant structure, a first distal end abutting the ring assembly in a manner not restricting the opening and having a predetermined length versus force characteristic;   providing a plug assembly abutting a second distal end of the compliant structure and comprising a plug forming a predetermined portion of the plug assembly having an external geometry over a predetermined portion of the plug to fit in abutting relationship to the opening.   
 
         [0036]    In accordance with an embodiment of the invention there is provided a method comprising:
   a ring assembly attached to the inner surface of a pipe comprising an opening of predetermined geometry;   a compliant structure, a first distal end abutting the ring assembly in a manner not restricting the opening and having a predetermined length versus force characteristic;   a plug assembly abutting a second distal end of the compliant structure and comprising a plug forming a predetermined portion of the plug assembly having an external geometry over a predetermined portion of the plug to fit in abutting relationship to the opening.   
 
         [0040]    Other aspects and features of the present invention will become apparent to those ordinarily skilled in the art upon review of the following description of specific embodiments of the invention in conjunction with the accompanying figures. 
     
    
     
       BRIEF DESCRIPTION OF THE DRAWINGS 
         [0041]    Embodiments of the present invention will now be described, by way of example only, with reference to the attached Figures, wherein: 
           [0042]      FIG. 1A  depicts the geographical distribution of consumption globally; 
           [0043]      FIG. 1B  depicts the geographical distribution worldwide of oil production; 
           [0044]      FIG. 1C  depicts the geographical distribution worldwide of oil reserves; 
           [0045]      FIG. 1D  depicts a Multiplexed Electro-Hydraulic (MUX) Control System according to the prior art; 
           [0046]      FIG. 2  depicts a BOP according to the prior art of Hynes in U.S. Pat. No. 4,476,935; 
           [0047]      FIG. 3  depicts a shear ram according to the prior art of Whitby in U.S. Pat. No. 5,400,857; 
           [0048]      FIG. 4  depicts a shear ram according to the prior art of Urrutia in US Patent Application 2006/0,144,586; 
           [0049]      FIG. 5  depicts shear rams according to the prior art of Judge in U.S. Pat. No. 7,703,739; 
           [0050]      FIG. 6  depicts a shear ram according to the prior art of van Winkle in US Patent Application 2010/0,319,906; 
           [0051]      FIG. 7  depicts a BOP according to an embodiment of the invention; 
           [0052]      FIG. 8  depicts a BOP plug according to an embodiment of the invention; 
           [0053]      FIG. 9  depicts a BOP according to an embodiment of the invention; 
           [0054]      FIG. 10  depicts a BOP plug according to an embodiment of the invention; 
           [0055]      FIG. 11  depicts a BOP according to an embodiment of the invention; 
           [0056]      FIG. 12  depicts a BOP according to an embodiment of the invention used in conjunction with a pressure blowout element; 
           [0057]      FIG. 13  depicts a BOP according to an embodiment of the invention in conjunction with a flow director element; 
           [0058]      FIG. 14  depicts a BOP according to an embodiment of the invention in conjunction with a flow director element wherein the BOP and flow director element can be programmed to operate at different pressures; 
           [0059]      FIG. 15  depicts a BOP according to an embodiment of the invention; 
           [0060]      FIG. 16  depicts a BOP according to an embodiment of the invention allowing a drill string to be operated through the BOP; 
           [0061]      FIG. 17  depicts a BOP according to an embodiment of the invention allowing a drill string to be operated through the BOP; 
           [0062]      FIG. 18  depicts a BOP according to an embodiment of the invention allowing a drill string to be operated through the BOP; 
           [0063]      FIG. 19  depicts a BOP according to an embodiment of the invention allowing a drill string to be operated through the BOP; 
           [0064]      FIG. 20  depicts a cascaded BOP according to an embodiment of the invention allowing a drill string to be operated through the BOP; and 
           [0065]      FIG. 21  depicts a BOP according to an embodiment of the invention allowing a drill string to be operated through the BOP. 
       
    
    
     DETAILED DESCRIPTION 
       [0066]    The present invention is directed to blowout preventers and more specifically to low complexity automatic blowout preventers. 
         [0067]      FIG. 2  depicts a BOP according to the prior art of Hynes in U.S. Pat. No. 4,476,935. Accordingly a production BOP  10  is shown after production tubing and other apparatus has been inserted into the well through the BOP stack  11  and after a production tree  13  has been attached for controlling the production of gas and fluid from the well. A tubular extension may be provided between the production tree  13  and the blowout preventer  10  providing a safe distance between the tree  13  and its valves which may leak and be subject to a fire and the production blowout preventer  10  which is adapted to close off flow in production tubing during an emergency. A tubular extension also allows the blowout preventer to be located on a lower deck and the production tree on an upper deck as is common on offshore production platforms. 
         [0068]      FIG. 3  depicts a shear ram according to the prior art of Whitby in U.S. Pat. No. 5,400,857 wherein a shearing assembly  10  which may comprise a blowout preventer body  12  having an upper portion  14  for receiving shearing ram subassemblies discussed subsequently, and a lower portion  18  for receiving sealing ram subassemblies also discussed subsequently. The body portions  14  and  18  may be formed separately or as an integral member, and include an upper flange  16  and a lower flange  17  for sealed engagement with related wellhead equipment conventionally mounted to the BOP body  12 . The body  12  of the shearing assembly  10  includes a vertical through bore  44  having a generally cylindrical configuration, and that the oilfield tubular member or pipe P as shown in  FIG. 3  passes through this bore in a conventional manner while the tubular is run in or pulled out of the wellbore. 
         [0069]    A pair of upper shear ram subassemblies  20  and  22  are mounted to the upper body  12 , with each shear ram subassembly including a respective piston  36  and  38  for moving respective shear blades  40  and  42  linearly from an open position to a closed position. Each ram subassembly  20  and  22  may be powered by a hydraulic fluid source which simultaneously moves the shear blades  40  and  42  radially inward and outward. A suitable fluid power source for linearly moving the ram pistons  36  and  38  within the subassemblies  20  and  22  is disclosed in U.S. Pat. No. 4,923,008. Except for the configuration of the shearing blades, the ram subassemblies  20  and  22  may be of the type conventionally utilized in blowout preventers. The assembly  10  also includes opposing lower sealing ram subassemblies  24  and  26 , which are similarly fluid powered and include ram pistons Z 8  and  32  each powering a respective sealing assembly  30  and  34 . The pistons  28  and  32  and the sealing assemblies  30  and  34  are of the type which are conventionally used in blowout preventers, and further details regarding such equipment are disclosed in U.S. Pat. No. 3,590,920. The upper ram pistons  36  and  38  may be simultaneously activated for shearing the tubular P in an emergency, but that normally the shear blades  40  and  42  are retracted into the body of the BOP, as shown in  FIG. 3 . 
         [0070]    The lower sealing assemblies  24  and  26  may similarly be retracted into the body of BOP as the tubular is passed through the cylindrical bore  44 , although the pistons  28  and  32  may be simultaneously activated at selected times to move the respective sealing assemblies  30  and  34  radially inward and into sealing engagement with the pipe P as shown in  FIG. 3 , so that the annulus between the pipe and the body  12  of the assembly is reliably sealed. In a typical application, the assembly as shown in  FIG. 3  may be part of a subsea wellhead assembly, with the pipe P extending from a ship into a wellbore beneath the seabed. During a storm or other emergency, it may be necessary for the rig to be structurally released quickly from the wellhead, in which case the upper ram assemblies  20  and  22  may be activated for shearing the pipe P. 
         [0071]      FIG. 4  depicts a shear ram according to the prior art of Urrutia in US Patent Application 2006/0,144,586 wherein an isometric view of a ram type blowout preventer  10  used in oil and gas drilling operations is shown. The ram type blowout preventer  10  includes a body or housing  12  with a vertical bore  14  and laterally disposed ram guideways  16 . Bonnet assemblies  18  are mounted to the body  12  with bolts  20  and aligned with laterally disposed guideways  16 . Each bonnet assembly  18  includes an actuation means  22 , including a piston  24  and connecting rod  26 . While only one guideway  16  and actuation means  22  is shown, it is understood by those of ordinary skill in the art that there is a pair of opposed guideways  16  and actuation means  22 . Connecting rods  26  are connected to upper ram assembly  28  and lower ram assembly  30  to form shearing blind ram assembly  32 . Actuation means  22  allows shearing blind ram assembly  32  to be reciprocated within guideways  16 . 
         [0072]      FIG. 5  depicts shear rams according to the prior art of Judge in U.S. Pat. No. 7,703,739 in a perspective view. Ram blocks  201 ,  202  are shown separate from a BOP for ease of understanding. Second ram block  202  includes a connector  211  where the ram block  202  may be connected to a driving rod or piston (not shown) or other device for forcing the ram block  202  into a closed position. A similar connector (not shown) may be present on the first ram block  201 . Still referring to  FIG. 5 , ram blocks  201 ,  202  comprise shear elements  203 ,  204 , respectively, which are attached to a vertical face of each ram block  201 ,  202 . Shear elements  203 ,  204  are configured to engage when the BOP is in a closed position thereby shearing any piping or tools in the wellbore as well as sealing it off. Further, the ram blocks  201  and  202  include seal elements  208  and  209 . Furthermore, first ram block  201  comprises load intensifying members  205  configured to engage rectangular receptacles (not shown) on ram block  202 . While receptacles are described as rectangular, other appropriate configurations may be used. 
         [0073]      FIG. 6  depicts a shear ram according to the prior art of van Winkle in US Patent Application 2010/0,319,906 wherein the BOP comprises a body  32  with a bore  34  oriented along an axis  36 . Coiled tubing  38  is positioned through the BOP aligned along the axis  36 . Bolted to the side of the body  32  is a ram-receiving chamber  40  mounted to the body  32  with a set of mounting bolts  41  or other appropriate means. Opposite the ram-receiving chamber  40  is a bonnet which is arranged to support and guide the operable components of the shear/seal ram portion of the BOP. The bonnet may be mounted to the body with a plurality of bolts or other appropriate means. The bonnet defines a bore there through which is adapted to receive a ram  76  operatively coupled to a rod  48  which is moved transversely back and forth by a piston  50  retained within a cylinder. 
         [0074]    The BOP may include a self-contained hydraulic cylinder system to open and close the bonnet of the BOP to replace rams in the field. Actuation of the hydraulic cylinder system pulls the bonnet back away from the body  32 , bringing the ram  76  with it, so that the ram can be changed. The body also defines a severed tubing receiving cavity  54  which defines an angled upper surface  56 . The cavity  54  provides a volume to receive the upper portion of the severed coiled tubing. The ram includes a ram bore  52  such that when the shear/seal ram is in the open position the coiled tubing  38  passes through the ram bore  52 . The ram bore  52  also defines a knife edge  54  in operable position to shear the coiled tubing when the shear seal ram is actuated. As the knife edge  54  shears the coiled tubing, the upper portion of the coiled tubing is moved to the left into the cavity  54 . The bore  52  forms a knife edge  54  with a pair of opposing substantially straight edges  55  which provide a guillotine action against the coiled tubing when the ram is shut. Once the ram is shut, if pressure is higher below the ram than above the ram, a shear seal ring  66  is pressed against an underside  68  of the ram to seal in the pressure under the ram within an annulus  69 . The seal ring  66  is spring loaded by a Bellville spring  70  which is supported on a shoulder  72  extending outwardly from the bore  13 . 
         [0075]      FIG. 7  depicts a BOP according to an embodiment of the invention in open  700 A and closed  700 B states. Referring to open  700 A a riser  710  is depicted surrounded by a casing  750  having upper and lower threaded holes  752  and  754  allowing the casing  750  to be mounted to structures above and below respectively such as other portions of a production tree for example. Disposed with the riser  710  is annular ring  720  and plug  730  wherein there are disposed springs  740  between the lower surface of the annular ring  720  and upper surface of the plug  730 . Within the descriptions of the embodiments of the invention upper and lower shall be employed with respect to the cross-sectional view as portrayed with the oil reservoir below the structure as shown with flow upwards towards the production/drilling rig above the structure as shown. Accordingly when the oil pressure is low the springs  740  are uncompressed and the oil flows through the plug  730  from the oil reservoir to the rig above. 
         [0076]    Under increased pressure, at a pressure exceeding the design specification of the BOP the pressure from the oil is sufficient to push the plug  730  compressing the springs  720  such that the plug  730  fits within the opening  725  of the annular ring  720  sealing it, as shown in closed  700 B. Accordingly, it would be evident that if the pressure reduces the plug  730  will be returned towards its fully open state by the springs  720 . As such the BOP provides a limiting function, restricting oil flow as pressure increases, and stop function when the pressure exceeds a predetermined threshold. 
         [0077]    Referring to  FIG. 8  there is depicted a BOP plug such as plug  730  described above in respect of  FIG. 7 . According to an embodiment of the invention the BOP plug comprises a solid bottom  830 , designed to mate with the opening within the annular ring, for example opening  725  of annular ring  720 , and an upper ring  810  which engages on the lower side as shown the springs of the BOP and the upper side provides part of the surface defining the force that is applied to the BOP plug by the oil. The plug  830  is connected to the upper ring  810  by a series of members  820 . Accordingly oil may flow through the opening  815  in the upper ring  810  and then the openings  840  between the members  820 . 
         [0078]    Now referring to  FIG. 9  there is depicted a BOP according to an embodiment of the invention in open  900 A and closed  900 B states. Referring to open  900 A a riser  710  is depicted surrounded by a casing  950  having upper and lower threaded holes  952  and  954  allowing the casing  950  to be mounted to structures above and below respectively such as other portions of a production tree for example. Disposed with the riser  910  is annular ring  920  and plug  930  wherein there are disposed buffers  960  between the lower surface of the annular ring  920  and upper surface of the plug  930 . Within the buffers  960  is disposed a compressible material at a predetermined volume. Accordingly when the oil pressure is low the buffers  940  are uncompressed and the oil flows through the plug  930  from the oil reservoir to the rig above. 
         [0079]    Under increased pressure, at a pressure exceeding the design specification of the BOP the pressure from the oil is sufficient to push the plug  930  compressing the compressible materials within the buffers  720  such that the plug  930  fits within the opening  925  of the annular ring  920  sealing it, as shown in closed  900 B. Accordingly, it would be evident that if the pressure reduces the plug  930  will be returned towards its fully open state by the buffers  920 . As such the BOP provides a limiting function, restricting oil flow as pressure increases, and stop function when the pressure exceeds a predetermined threshold. 
         [0080]    Referring to  FIG. 10  there is depicted a BOP plug such as plug  930  described above in respect of  FIG. 9 . According to an embodiment of the invention the BOP plug comprises a solid bottom  1030 , designed to mate with the opening within the annular ring, for example opening  925  of annular ring  920 , and an upper ring  1010  which has formed upon the lower surface plungers forming part of the buffers. The upper surface of the upper ring  1010  and bottom  1030  provide the surfaces defining the force that is applied to the BOP plug by the oil. The plug  1030  is connected to the upper ring  1010  by a series of members  1020 . Accordingly oil may flow through the opening  1015  in the upper ring  1010  and then the openings  1040  between the members  1020 . 
         [0081]    Referring to  FIG. 11  there is depicted a BOP according to an embodiment of the invention in open and closed states  1100 A and  1100 B respectively. In overall construction the BOP is of similar construction to the BOP depicted supra in respect of  FIG. 9 . However the ring  1140  now has a continuous recess  1120  around the edge or at predetermined points around the outer edge. Similarly the riser now contains a sprung wedge  1110 . Accordingly as the BOP moves from open  1100 A to closed  1100 B the sprung wedges  1110  is pushed back into the riser until the plug is sitting in the opening wherein the sprung wedges  1110  release so that they are within the recess  1120 . By appropriate design of the sprung wedge  1110  and recess  1120  the movement of the plug pushes the sprung wedge  1110  into the riser as the oil pressure increases but once sprung into the recess  1120  reduction in oil pressure and action of the buffer is not able to push the spring wedge  1110  back into the riser again. For example the upper surface of the sprung wedge may be substantially parallel to the lower surface of the outer ring of the plug whilst the lower surface tapers allowing the plug to slide along. 
         [0082]    Now referring to  FIG. 12  there is depicted a BOP according to an embodiment of the invention used in conjunction with a pressure blowout element  1210 . Accordingly there is shown inner riser  1250  and outer riser  1260 . Disposed within the inner riser  1250  is a BOP such as described supra in respect of  FIG. 10  using buffers. Also disposed within the wall of inner riser  1250  are pressure blowout elements  1220 . At low pressure the BOP is open and oil flows. As pressure rises the BOP begins to close and then closes. Subsequently as the pressure increases still further the pressure blowout elements  1220  rupture allowing the oil to flow into the region between inner liner  1250  and outer liner  1260 . Accordingly recovery of the oil from the reservoir can then proceed to be restored. 
         [0083]    Referring to  FIG. 13  there is depicted a BOP according to an embodiment of the invention in conjunction with a flow director element wherein the BOP is shown in normal  1300 A, closed  1300 B and bypass  1300 C states. Accordingly a pressure initiated riser closer, shown as open closer  1310 A and closed closer  1310 B respectively in these three states, is disposed within a vertical riser wherein oil flows or is intended to flow. Pressure initiated riser closer for example being as depicted above in respect of  FIGS. 9 and 11 . In normal  1300 A the pressure initiated riser closer is shown in its open state as open  1310  allowing flow of liquid from the oil reservoir up through the riser to the drilling/production rig. Disposed to the side of the riser just below the pressure initiated riser closer is a relief valve shown as closed valve  1320 A and open valve  1320 B in the three states. As shown the relief valve is of a hydraulic form wherein hydraulic rams maintain the position of a plug into the opening  1340  in the riser. The hydraulic rams being in engaged position  1325 A when the relief valve is in the closed state and reduced state  1325 B when the relief valve is in the open state. The hydraulic rams being coupled to hydraulic control system  1330 . 
         [0084]    When pressure in the riser increases above the predetermined limit of the drilling/production system, represented by closed  1300 B, the pressure initiated riser closer transitions to a closed state as shown by closed closer  1310 B. At this point the relief valve is also in its closed position as shown by closed valve  1320 A, the default condition for the relief valve and associated hydraulic control system  1330 . If the pressure in the riser reduces below the predetermined closing pressure then the pressure initiated riser closer will re-open allowing liquid to reflow vertically. As such pressure initiated riser closers according to embodiments of the invention may automatically close in the event of a kick. 
         [0085]    Upon issuance of a relief command being sent to the hydraulic control system  1330  the hydraulic pressure within the hydraulic rams may be controllably reduced thereby allowing the pressure of the liquid to push the plug and open the flow of liquid into the second piping system attached to the relief valve but not shown for clarity. As such the hydraulic rams transition to disengaged state  1325 B and the relief valve is now open valve  1320 B. 
         [0086]    Optionally the buffers, such as buffers  960 , in the pressure initiated riser closer may also be hydraulic rams. In a common configuration all the hydraulic rams are controlled from a single control system  1410  as depicted in first configuration  1400 A of  FIG. 14  or coupled to separate hydraulic controllers  1420  and  1430  as shown in second configuration  1400 B of  FIG. 14 . It would be evident to one skilled in the art that by introducing such control systems the liquid pressure at which the BOP triggers may be adjusted or reset. Accordingly, if a kick is detected the BOP may be triggered allowing time for the mud pressure to be increased before adjusting the BOP hydraulic pressures allow the BOP to re-open in a slow controlled manner. 
         [0087]    Referring to  FIG. 15  there is presented a BOP according to an embodiment of the invention wherein a plug assembly  1530  is disposed within a riser  1510  in conjunction with an annular ring  1520  that provides an opening  1525 . Plug assembly  1530  for example being of a similar design to the plug presented supra in  FIG. 8  but the upper ring  1550  is now affixed to the inside of the riser  1510 . Accordingly at low liquid pressure as depicted in normal configuration  1500 A the plug assembly  1530  is fixed in place and the liquid flows through it and through the opening  1525 . However, as the liquid pressure increases the force applied to plug  1540  of the plug assembly  1530  increases until a predetermined threshold is reached at which point the members  1560  between the plug  1540  and upper ring  1550  shear releasing the plug  1540  that is then pushed into the opening  1525  sealing it. This being shown in stopped configuration  1550 B in  FIG. 15 . 
         [0088]    Now referring to  FIG. 16  there is depicted a BOP according to an embodiment of the invention in open and closed states  1600 A and  1600 B respectively wherein the BOP is established to operate between a drill string  1620  and casing  1610 . Such a configuration occurring for example during drilling as evident from the drill bit  1630  disposed at the end of the drill string  1620 . The BOP comprising an annular ring  1650  designed to fit the inner diameter of the casing  1610  having an opening  1670  through which the drill string  1620  passes. The BOP also comprising a plug  1640  comprising a bore, not identified for clarity, for the drill string. The plug  1640  and annular ring  1650  being coupled via springs  1660  in a similar manner to the BOP presented supra in  FIG. 7 . Accordingly the BOP transitions from open state  1600 A to closed state  1600 B as the pressure increases in the casing  1610  thereby increasing the force applied to the plug  1640  and compressing the springs  1660 . The BOP may be deployed on the drill string  1620  as the drilling operation progresses and automatically operated whilst the drill string  1620  is still in place. 
         [0089]    Plug  1640  being designed for example as depicted supra in respect of  FIG. 8  to allow liquid flow under normal operation from the region around the drill bit up past the plug when not in closed state  1600 B and upwards along riser  1620  towards drilling rig as well as providing the solid section to block the flow and the predetermined surface area to generate the force under operation to compress the spring and restrict/close the BOP. It would be evident that the BOP can be placed onto the drill string during operations and may accordingly be placed at a predetermined distance from the drill bit  1830  as drilling continues rather than at the top of the well either on land or at the bottom of the sea. Upon reduction of pressure in the casing  1710  the BOP will re-open allowing liquid to reflow. 
         [0090]    Referring to  FIG. 17  there is depicted a BOP according to an embodiment of the invention in open and closed states  1700 A and  1700 B respectively wherein the BOP is established to operate between a drill string  1720  and casing  1710 . Such a configuration occurring for example during drilling as evident from the drill bit  1730  disposed at the end of the drill string  1720 . The drill string  1720  having an integral annular protuberance  1740 . Disposed around the drill string  1720  is spring  1750  that fits between annular protuberance  1740  and plug  1760 . Accordingly in open state  1700 A liquid from below the BOP flows through the channels within the plug  1760 . 
         [0091]    As pressure increases the plug  1760  applies increasing force to the spring  1750  compressing it and thereby initially limiting, and then closing the BOP as the plug  1760  closes the opening between the annular protuberance  1740  and casing  1710 . Plug  1760  being designed for example as depicted supra in respect of  FIG. 8  to provide the solid plug, openings for liquid passage but modified to provide the central opening allowing the drill string  1720  to pass through. It would be evident that the BOP can be placed onto the drill string during operations and may accordingly be placed at a predetermined distance from the drill bit  1730  as drilling continues rather than at the top of the well either on land or at the bottom of the sea. Upon reduction of pressure in the casing  1710  the BOP will re-open allowing liquid to reflow. 
         [0092]    Referring to  FIG. 18  there is depicted a BOP according to an embodiment of the invention in open and closed states  1800 A and  1800 B. As shown in open state  1800  a riser  1810  has disposed within a drill string  1820  terminating in a drill bit  1830 . The drill string  1820  has an annular protuberance  1840  disposed at one region and a plug assembly comprising plug  1850  and sacrificial mounting  1860  below at a predetermined separation. Accordingly in operation the liquid flows through openings in the plug  1850 . As pressure increases to and exceeds the predetermined trigger pressure of the BOP the sacrificial mounting  1860  releases the plug  1850  such that it is pushed up the casing  1810  and engages the annular protuberance  1840 , as shown in closed state  1800 B thereby closing the BOP and stopping liquid flow up the riser  1810 . 
         [0093]    Plug assembly being designed for example as depicted supra in respect of  FIG. 8 , and as shown on  1800 C, wherein a plurality of radial members  1870  connect the plug  1850  to the sacrificial mounting  1860 . It would be evident that the BOP can be placed onto the drill string during operations and may accordingly be placed at a predetermined distance from the drill bit  1830  as drilling continues rather than at the top of the well either on land or at the bottom of the sea. Upon reduction of pressure in the casing  1810  the BOP will re-open allowing liquid to reflow. 
         [0094]    Now referring to  FIG. 19  there is depicted a BOP according to an embodiment of the invention depicted in open and closed states  1900 A and  1900 B respectively. As shown in open state  1900 A a drill string  1920  terminating at its lower end with drill bit  1930  is disposed within casing  1910 . Mounted to the drill string  1920  is BOP frame  1960  to which spring  1950  is mounted and extends downwards towards drill bit  1930 . At the other end of spring  1950  there is disposed pressure plate  1940 . As pressure within the casing increases the force applied to the pressure plate  1940  increases thereby compressing the spring 1950  as the spring  1950  is rigidly held by the BOP frame  1960 . Accordingly, the pressure plate  1940  moves upwards along the drill string  1920  until the pressure reaches the designed closing pressure for the BOP at which point the spring  1950  is fully compressed, as shown in closed state  1900 B, thereby closing the BOP. 
         [0095]    Referring to  FIG. 20  there are shown first and second BOP units  2010  and  2020  deployed upon the same drill string  2030 . The first and second BOP units  2010  and  2020  may optionally be designed to operate at the same pressure, such that there is dual redundancy or alternatively they may be designed to operate at different pressures. It would be evident to one skilled in the art that such automatic reversible BOPs may be deployed within the drill string. 
         [0096]    Now referring to  FIG. 21  there is shown a drill string  2100  comprising a reversible hydraulic BOP  2120  unit deployed on a drill bit  2130  at the bottom of the drill piping, not shown for clarity. Reversible hydraulic BOP  2120  being of a design such as shown above in  FIG. 9 . Accordingly the reversible hydraulic BOP  2120  allows “kicks” back up the drill string to be stopped at the drill bit  2130  rather than at a conventional BOP installed at the surface of the drilling either on land or at the seabed. 
         [0097]    It would be apparent to one skilled in the art that multiple BOP unit may be deployed both within the drill string and between the drill string and the casing and that the designs of the multiple BOPs may be the same or different from amongst the embodiments of the invention presented in respect of  FIGS. 7 through 21  Likewise where pressure relief structures are employed in conjunction with an inline BOP the operating mechanisms of the inline BOP and relief valve may the same or different. Similarly multiple BOP devices and relief valves may be designed to operate at the same pressure or different pressures. Whilst deployment of the BOPs and relief valves has been primarily described in respect of deployments within portions of the oil/gas well underground they may be equally applied to other portions of the overall oil/gas well. Likewise embodiments of the invention presented without a drill string in place may be modified to support a drill string and those shown with a drill string may be modified to be operate without a drill string. Such variants being within the scope of the invention. 
         [0098]    It would also be apparent that the pressure valves of embodiments of the invention described in respect of  FIGS. 7 through 21  may be employed in a wide variety of other gas/liquid piping systems where closure of the system at critical pressures is required. Beneficially, embodiments of the invention limit flow prior to closure in a gradual manner. 
         [0099]    It would be evident that the BOP devices presented supra may be disposed within standard lengths of piping or that they may be manufactured as discrete elements that are assembled onto the drill string or production tubing and hence may be shorter sections of piping. In this manner multiple BOPs may be added to drilling or production tubing with the same or different closing pressures according to the activities being performed and the requirements for back-up BOPs and redundancy. 
         [0100]    Whilst within the embodiments of the invention relating to relief valves the control mechanisms have been considered as hydraulic rams it would be evident that alternative structures may be employed including but not limited to linear translation stages for example. Optionally the plug may be made from a magnetic material such that the movement of the plug relative to the annular ring and the opening may be monitored by a magnetic sensor disposed outside the pipe. 
         [0101]    The above-described embodiments of the present invention are intended to be examples only. Alterations, modifications and variations may be effected to the particular embodiments by those of skill in the art without departing from the scope of the invention, which is defined solely by the claims appended hereto.