Terral
Terral Corp CEO
- Mar 4, 2009
- 2,493
- 92
- 83
- Banned
- #1
Greetings to All:
Florida Congressman Bill Young's Office sent me an email with instructions to present a White Paper to the U.S. Government with details of my BP Gulf Oil Spill Solution (my Topic), according to new guidelines established for this BP Gulf Oil Crisis, saying,
Contents
1. The BP Gulf Oil Crisis Solution.
2. The April 20, 2010 Solution.
3. Interrupting Fluid Column Momentum-To-Blowout Scenario
Response Sent To: RDC BAA Submission Form
1. The BP Gulf Oil Crisis Solution.
The BP Gulf Oil Crisis Solution is realized by the marriage of Fluid Dynamics and Pressure-Sheath Technology. The critical overlooked problem facing BP and everyone involved with the BP Gulf Oil Crisis is the presence of the 14,000 feet vertical fluid column that has gained momentum since the initial blowout on April 20, 2010. BP initially estimated that 5000 barrels of oil was escaping into the Gulf of Mexico, while recent estimates are far greater, because the massive fluid column had very little momentum in the early days of this crisis. However, this situation has every opportunity to grow into a literal nightmare, if BP and those in authority do not recognize the true solution and ensure that sufficient countermeasures are in place.
Pressure-Sheath Technology relates to methods and apparatus for creating ‘Controlled Pressurized Environments’ (CPEs) inside and outside the body using dilator cuffs on scopes and probes for superior outcomes (See information at Link #1). This solution description assumes the Examiner understands Pressure-Sheath Technology Fundamentals from that linked Presentation. The same rules for creating, maintaining and utilizing CPE’s inside the human body apply to situations within the earth, even if on a much larger scale. We have a 21-inch vertical pipe that is 14,000 feet long that contains and ‘active fluid column’ moving upwards to the sea floor. The fluid column has gathered momentum over a period of time and time is required to slow the momentum down, before eventually the flow can be stopped. The moving fluid column is racing upwards to the sea floor like a freight train and must be slowed down in increments through a series of stages, or the momentum may continue to increase beyond the limits of system and sea floor integrity.
The top diagram shows a Remote Probe with five dilator cuffs connected to a series of brackets with Hydraulic Cylinders. Simply inserting the Remote Probe into the broken pipe will create resistance and backpressure, so time is a very important part of the BP Solution Equation. A series of Temporary Brackets should be installed and connected to the vertical supports holding the pipe in place to provide maximum control over the newly created CPE we are attempting to manage. This particular situation may require a much longer Remote Probe utilizing a dozen or more inflatable dilator cuffs depending on how much momentum the fluid column has gathered and according to the desired timeframe for reducing fluid column momentum to zero.
Hydraulic Cylinder Devices are attached to the Temporary Bracket Network (on left) and to the Bracket Assembly on the Remote Probe. All Dilator Cuffs are hydraulically activated through a series of hydraulic lines (not shown) for maximum control of pressures within the pipe. Simply capping the pipe and using vents (BP’s current method) places too much pressure upon the pipe outer rim and offers insufficient environmental control using primitive vents. In fact, the only reason this temporary cap remained intact is because trapped gasses now compressing within the pipe are playing the role of shock absorber. However, with the cap in place, those pressures are increasing and the natural gas fluid-to-gas ratio within the pipe are decreasing, which means the fluid column is gathering even more mass in preparation of potentially blowing a very large hole in the sea floor.
The middle diagram shows how the Piston Rods are retracted to bring the multi-cuffed probe into position within the pipe. Evacuation/vacuum Ports are contained within the Integrated Sheath Receiver Coupling, holding the Remote Probe in place, allowing excess oil and gas to be transported to a waiting tanker on the surface. Many dilator cuffs are used to slow fluid column momentum, utilizing as much internal pipe surface area as possible, which potentially reduces the timeframe of the overall operation. Internal CPE pressures must be monitored throughout the operation to ensure system integrity, or pressures may build towards yet another blowout. Pipe vibration monitors should be installed and watched carefully for signs of system integrity breach.
The third diagram (bottom) shows how the dilator cuffs are filled to stop the oil from exiting the pipe, but again, time is the crucial factor and the dilation process in this case can take days or even more than a week to cancel out fluid column momentum. Until the massive force of the out-of-control fluid column has been neutralized, the dilator cuffs are dilated and oil escaping outside the Remote Probe is redirected into the internal Evacuation/vacuum Port and channeled to the surface; which essentially stops the oil from escaping into the Gulf at some point in this operation. Pumping the oil manually at the surface can actually reduce pressures within the broken pipe and help the operator maintain CPE control and system integrity more efficiently throughout the operation; especially where multiple Remote Probes are utilized at separate wellhead/blowout locations.
The ‘Top Kill’ Method was doomed to fail, because there was no provision for slowing down fluid column momentum in incremental stages. Placing a cap at the wellhead location may have been possible on April 20, 2010 before the fluid column gathered momentum. However, trying to cap the well today is like placing a barricade in front of a 3-mile long locomotive at full speed and expecting the train to stop. The U.S. Government should be made aware of the fact that a Point Of No Return Situation is possible for every potential oil reservoir, supply pipe line and wellhead scenario. In other words, if the fluid column momentum is allowed to gather enough strength where force exceeds system integrity parameters, then a system blowout will eventually take place. If memory serves, the Russians have used nuclear devices to seal runaway blowouts on six separate occasions, because the technology to interrupt the fluid column momentum-to-blowout cycle has thus far remained unavailable.
Capping the wellhead and allowing gas pressures to increase brings us nearer to the Point Of No Return where system breach is inevitable. Trapped gas within the 14,000-foot uncapped pipe is displacing fluid volume and interrupting the fluid column’s ability to gather momentum. However, capping the pressurized environment within the pipe is causing the gases to compress and take up a smaller percentage of space, which is actually providing an optimum environment for the fluid column to gather mass and momentum. In fact, highly compressed gases from capping the system can convert the natural gas back into a liquid state and remove the helpful shock absorber effect from the equation. This means larger sections of pipe below the sea floor will gather areas of solid fluid having no gas at all, gather increased momentum, and place much-increased pressure upon the area of capped pipe directly below the sea floor possibly damaged in the original accident.
2. The April 20, 2010 BP Solution.
The oil/gas mixture within the 14,000-foot pipe from the reservoir to the sea floor had virtually no momentum on April 20, 2010, as the flow rate was governed by the pressure differential between the reservoir and the broken pipe at the wellhead location. I admit to being mystified by the fact that nobody has talked about positioning a new platform at the surface for mounting a new supply line. Rather than cap the broken pipe, remove the broken section, rethread and replace the pipe and add couplings to a new supply line to the surface. A Pressure-Sheath Technology Method to replace the broken pipe at the wellhead is shown in the diagram above. The Multi-Cuffed Remote Probe is sent through the new pipe section and coupling for positioning inside the broken pipe that has been cut and rethreaded. Inflatable O-ring Seals (not shown) are fixed to the far end of the new pipe section allowing operator control over the newly created CPE. The new coupling is connected to the existing rethreaded pipe and the new supply pipe is connected to the new coupling for oil/gas redirection.
3. Interrupting Fluid Column Momentum-To-Blowout Scenario
BP has capped the 14,000-foot wellhead pipe using robot-assisted ventilation methods and internal CPE pressures are increasing. One reason that ‘the solution’ to this BP Gulf Oil Spill Crisis has eluded the most brilliant engineers in the world is due to the many variables making up the many equations. Oil and natural gas are joined together in the reservoir, but the gas is currently being released from the liquid-to-gas transition like the fizz escaping from your glass of soda somewhere within the 14,000-foot pipe. Natural gas in liquid form expands 600 times when converting to a gaseous state, which is currently the blessing that allows the temporary cap to remain connected to the broken pipe. However, internal pressures are increasing within the 14,000-foot pipe and environmental conditions within the BP-created CPE may very well become optimal for the natural gas reversion back into a liquid form and without adequate CPE countermeasures in place.
Allowing the natural gas to re-liquefy randomly is by far the most dangerous scenario that anyone can imagine, because the haphazard oil/gas sloshing effect currently protecting system integrity is lost. Returning the natural gas to a liquid state allows Fluid Column Momentum to also increase randomly to the point that any weaknesses in system integrity will be tested well beyond our ability to control; even with all Pressure-Sheath Technology Control Measures in place. We should expect that the greatest pressures within the 14,000-foot pipe are at the bottom near the reservoir, which means the newly created fluid column will initially reform at that location. We should also expect that the reforming fluid column will begin displacing the lighter air pockets from the system, which will reveal itself by the lack of oil evacuating from the vents. The sudden reduction in pressure near the wellhead will allow the fluid column to gather even more momentum, until violently impacting the cap and rupturing any weak connections within the system.
Interrupting the Fluid-Column Momentum-To-Blowout Scenario requires the use of advanced Pressure-Sheath Technology Methods and Apparatus including a Stationary Multi-compartment Surface Tanker with high-vacuum/compression compartment capabilities. The Multi-cuffed Remote Probe is in position within the broken pipe and oil/gas is siphoned through the Vacuum/Evacuation Channel into the decompressed Vacuum Compartment. Vacuum Station pumps are evacuating the depressurized environment much faster than oil is escaping from the broken pipe on the seabed floor, which means we now have the tools to lower pressure within the broken pipe CPE.
Natural gas is released into the atmosphere and the separated oil is pumped into the Compression Compartment for transmission to the Oil Compartment, or for reinjection through the Irrigation Channel in the Remote Probe into our 14,000-foot CPE below the seabed floor. Excess oil is pumped from the Oil Compartment to waiting tankers as needed to ensure availability of adequate oil storage space on the Multi-compartment Surface Tanker. High-capacity pumps are used to compress the newly created CPE within the Compression Compartment for oil reinjection into the supply pipe below the seabed, because this ‘separated oil’ has all natural gas removed at the surface; which means we now have the tools to increase pressure within the broken pipe CPE and create a valuable fluid column to cancel the effect of the naturally-created oil/gas fluid column from the reservoir.
The high-pressure methane/oil fluid column is entering the 21-inch pipe at the reservoir location, some 14,000 feet below the sea floor, but the methane is changing to a gas at some point along the way. In other words, the liquid oil/methane mix is entering the pipe at one speed, but the methane transition into a gas speeds up the flow in direct proportion to the liquid-to-gas transition rate. Decreasing the pressure at the wellhead on April 20, 2010 allowed the methane liquid-to-gas transition to speed up at the seabed location, which reduced the pressure and helped fluid column momentum to increase. Placing the cap at the wellhead location is allowing internal pressures to grow, which slows the methane liquid-to-gas transition and allows the fluid column from below to grow in increments towards the wellhead location. However, BP’s current methodology will never allow complete control over their pressurized environment within the supply pipe, because the oil they are trying to contain includes the methane liquid transitioning into gas and multiplying the volume by hundreds of times.
The solution to this problem is to completely seal the cap at the wellhead location, while redirecting the oil/gas through the Evacuation/vacuum Channel. At the same time, separated oil (methane removed) is reinjected at high velocity through the Irrigation Channel for the creation of a retrograde fluid column that does not allow for the expansion of the CPE through the methane liquid-to-gas transition. Sitting at my computer today, I have no clue as to whether the front line of the methane liquid-to-gas transition is taking place at 10,000 feet, or 5,000 feet, or 1,000 feet from the wellhead location. However, we should expect that the transition location is constantly changing (up and down the supply pipe) with fluctuating pressures associated with capping the pipe and adjustment of the ventilation ports.
The objective is to raise internal pressures in stages to test system integrity for signs of a new blowout. Raising the pressure also raised the elevation of the methane fluid-to-gas transition point to a location nearer to the wellhead, which reduces the volume of natural gas in our CPE equation. When the conditions are optimal (stabilized CPE) and the methane fluid-to-gas transition point is nearest the wellhead, then we begin the process of vacuuming out the environment and simultaneously reinjecting the separated oil to create our retrograde fluid column, until the two fluid columns are allowed to commingle and the methane fluid-to-gas transition cycle is eventually stopped.
Link #1: PressPresentation.docx - DivShare
Terral (info removed)
Florida Congressman Bill Young's Office sent me an email with instructions to present a White Paper to the U.S. Government with details of my BP Gulf Oil Spill Solution (my Topic), according to new guidelines established for this BP Gulf Oil Crisis, saying,
This is my reply:
The BP Gulf Oil Crisis Solution:
Pressure-Sheath Technology
Terral Corporation
St. Petersburg, FL 33714
Pressure-Sheath Technology
Terral Corporation
St. Petersburg, FL 33714
White Paper
Contents
1. The BP Gulf Oil Crisis Solution.
2. The April 20, 2010 Solution.
3. Interrupting Fluid Column Momentum-To-Blowout Scenario
Response Sent To: RDC BAA Submission Form
1. The BP Gulf Oil Crisis Solution.
The BP Gulf Oil Crisis Solution is realized by the marriage of Fluid Dynamics and Pressure-Sheath Technology. The critical overlooked problem facing BP and everyone involved with the BP Gulf Oil Crisis is the presence of the 14,000 feet vertical fluid column that has gained momentum since the initial blowout on April 20, 2010. BP initially estimated that 5000 barrels of oil was escaping into the Gulf of Mexico, while recent estimates are far greater, because the massive fluid column had very little momentum in the early days of this crisis. However, this situation has every opportunity to grow into a literal nightmare, if BP and those in authority do not recognize the true solution and ensure that sufficient countermeasures are in place.
Pressure-Sheath Technology relates to methods and apparatus for creating ‘Controlled Pressurized Environments’ (CPEs) inside and outside the body using dilator cuffs on scopes and probes for superior outcomes (See information at Link #1). This solution description assumes the Examiner understands Pressure-Sheath Technology Fundamentals from that linked Presentation. The same rules for creating, maintaining and utilizing CPE’s inside the human body apply to situations within the earth, even if on a much larger scale. We have a 21-inch vertical pipe that is 14,000 feet long that contains and ‘active fluid column’ moving upwards to the sea floor. The fluid column has gathered momentum over a period of time and time is required to slow the momentum down, before eventually the flow can be stopped. The moving fluid column is racing upwards to the sea floor like a freight train and must be slowed down in increments through a series of stages, or the momentum may continue to increase beyond the limits of system and sea floor integrity.
The top diagram shows a Remote Probe with five dilator cuffs connected to a series of brackets with Hydraulic Cylinders. Simply inserting the Remote Probe into the broken pipe will create resistance and backpressure, so time is a very important part of the BP Solution Equation. A series of Temporary Brackets should be installed and connected to the vertical supports holding the pipe in place to provide maximum control over the newly created CPE we are attempting to manage. This particular situation may require a much longer Remote Probe utilizing a dozen or more inflatable dilator cuffs depending on how much momentum the fluid column has gathered and according to the desired timeframe for reducing fluid column momentum to zero.
Hydraulic Cylinder Devices are attached to the Temporary Bracket Network (on left) and to the Bracket Assembly on the Remote Probe. All Dilator Cuffs are hydraulically activated through a series of hydraulic lines (not shown) for maximum control of pressures within the pipe. Simply capping the pipe and using vents (BP’s current method) places too much pressure upon the pipe outer rim and offers insufficient environmental control using primitive vents. In fact, the only reason this temporary cap remained intact is because trapped gasses now compressing within the pipe are playing the role of shock absorber. However, with the cap in place, those pressures are increasing and the natural gas fluid-to-gas ratio within the pipe are decreasing, which means the fluid column is gathering even more mass in preparation of potentially blowing a very large hole in the sea floor.
The middle diagram shows how the Piston Rods are retracted to bring the multi-cuffed probe into position within the pipe. Evacuation/vacuum Ports are contained within the Integrated Sheath Receiver Coupling, holding the Remote Probe in place, allowing excess oil and gas to be transported to a waiting tanker on the surface. Many dilator cuffs are used to slow fluid column momentum, utilizing as much internal pipe surface area as possible, which potentially reduces the timeframe of the overall operation. Internal CPE pressures must be monitored throughout the operation to ensure system integrity, or pressures may build towards yet another blowout. Pipe vibration monitors should be installed and watched carefully for signs of system integrity breach.
The third diagram (bottom) shows how the dilator cuffs are filled to stop the oil from exiting the pipe, but again, time is the crucial factor and the dilation process in this case can take days or even more than a week to cancel out fluid column momentum. Until the massive force of the out-of-control fluid column has been neutralized, the dilator cuffs are dilated and oil escaping outside the Remote Probe is redirected into the internal Evacuation/vacuum Port and channeled to the surface; which essentially stops the oil from escaping into the Gulf at some point in this operation. Pumping the oil manually at the surface can actually reduce pressures within the broken pipe and help the operator maintain CPE control and system integrity more efficiently throughout the operation; especially where multiple Remote Probes are utilized at separate wellhead/blowout locations.
The ‘Top Kill’ Method was doomed to fail, because there was no provision for slowing down fluid column momentum in incremental stages. Placing a cap at the wellhead location may have been possible on April 20, 2010 before the fluid column gathered momentum. However, trying to cap the well today is like placing a barricade in front of a 3-mile long locomotive at full speed and expecting the train to stop. The U.S. Government should be made aware of the fact that a Point Of No Return Situation is possible for every potential oil reservoir, supply pipe line and wellhead scenario. In other words, if the fluid column momentum is allowed to gather enough strength where force exceeds system integrity parameters, then a system blowout will eventually take place. If memory serves, the Russians have used nuclear devices to seal runaway blowouts on six separate occasions, because the technology to interrupt the fluid column momentum-to-blowout cycle has thus far remained unavailable.
Capping the wellhead and allowing gas pressures to increase brings us nearer to the Point Of No Return where system breach is inevitable. Trapped gas within the 14,000-foot uncapped pipe is displacing fluid volume and interrupting the fluid column’s ability to gather momentum. However, capping the pressurized environment within the pipe is causing the gases to compress and take up a smaller percentage of space, which is actually providing an optimum environment for the fluid column to gather mass and momentum. In fact, highly compressed gases from capping the system can convert the natural gas back into a liquid state and remove the helpful shock absorber effect from the equation. This means larger sections of pipe below the sea floor will gather areas of solid fluid having no gas at all, gather increased momentum, and place much-increased pressure upon the area of capped pipe directly below the sea floor possibly damaged in the original accident.
2. The April 20, 2010 BP Solution.
The oil/gas mixture within the 14,000-foot pipe from the reservoir to the sea floor had virtually no momentum on April 20, 2010, as the flow rate was governed by the pressure differential between the reservoir and the broken pipe at the wellhead location. I admit to being mystified by the fact that nobody has talked about positioning a new platform at the surface for mounting a new supply line. Rather than cap the broken pipe, remove the broken section, rethread and replace the pipe and add couplings to a new supply line to the surface. A Pressure-Sheath Technology Method to replace the broken pipe at the wellhead is shown in the diagram above. The Multi-Cuffed Remote Probe is sent through the new pipe section and coupling for positioning inside the broken pipe that has been cut and rethreaded. Inflatable O-ring Seals (not shown) are fixed to the far end of the new pipe section allowing operator control over the newly created CPE. The new coupling is connected to the existing rethreaded pipe and the new supply pipe is connected to the new coupling for oil/gas redirection.
3. Interrupting Fluid Column Momentum-To-Blowout Scenario
BP has capped the 14,000-foot wellhead pipe using robot-assisted ventilation methods and internal CPE pressures are increasing. One reason that ‘the solution’ to this BP Gulf Oil Spill Crisis has eluded the most brilliant engineers in the world is due to the many variables making up the many equations. Oil and natural gas are joined together in the reservoir, but the gas is currently being released from the liquid-to-gas transition like the fizz escaping from your glass of soda somewhere within the 14,000-foot pipe. Natural gas in liquid form expands 600 times when converting to a gaseous state, which is currently the blessing that allows the temporary cap to remain connected to the broken pipe. However, internal pressures are increasing within the 14,000-foot pipe and environmental conditions within the BP-created CPE may very well become optimal for the natural gas reversion back into a liquid form and without adequate CPE countermeasures in place.
Allowing the natural gas to re-liquefy randomly is by far the most dangerous scenario that anyone can imagine, because the haphazard oil/gas sloshing effect currently protecting system integrity is lost. Returning the natural gas to a liquid state allows Fluid Column Momentum to also increase randomly to the point that any weaknesses in system integrity will be tested well beyond our ability to control; even with all Pressure-Sheath Technology Control Measures in place. We should expect that the greatest pressures within the 14,000-foot pipe are at the bottom near the reservoir, which means the newly created fluid column will initially reform at that location. We should also expect that the reforming fluid column will begin displacing the lighter air pockets from the system, which will reveal itself by the lack of oil evacuating from the vents. The sudden reduction in pressure near the wellhead will allow the fluid column to gather even more momentum, until violently impacting the cap and rupturing any weak connections within the system.
Interrupting the Fluid-Column Momentum-To-Blowout Scenario requires the use of advanced Pressure-Sheath Technology Methods and Apparatus including a Stationary Multi-compartment Surface Tanker with high-vacuum/compression compartment capabilities. The Multi-cuffed Remote Probe is in position within the broken pipe and oil/gas is siphoned through the Vacuum/Evacuation Channel into the decompressed Vacuum Compartment. Vacuum Station pumps are evacuating the depressurized environment much faster than oil is escaping from the broken pipe on the seabed floor, which means we now have the tools to lower pressure within the broken pipe CPE.
Natural gas is released into the atmosphere and the separated oil is pumped into the Compression Compartment for transmission to the Oil Compartment, or for reinjection through the Irrigation Channel in the Remote Probe into our 14,000-foot CPE below the seabed floor. Excess oil is pumped from the Oil Compartment to waiting tankers as needed to ensure availability of adequate oil storage space on the Multi-compartment Surface Tanker. High-capacity pumps are used to compress the newly created CPE within the Compression Compartment for oil reinjection into the supply pipe below the seabed, because this ‘separated oil’ has all natural gas removed at the surface; which means we now have the tools to increase pressure within the broken pipe CPE and create a valuable fluid column to cancel the effect of the naturally-created oil/gas fluid column from the reservoir.
The high-pressure methane/oil fluid column is entering the 21-inch pipe at the reservoir location, some 14,000 feet below the sea floor, but the methane is changing to a gas at some point along the way. In other words, the liquid oil/methane mix is entering the pipe at one speed, but the methane transition into a gas speeds up the flow in direct proportion to the liquid-to-gas transition rate. Decreasing the pressure at the wellhead on April 20, 2010 allowed the methane liquid-to-gas transition to speed up at the seabed location, which reduced the pressure and helped fluid column momentum to increase. Placing the cap at the wellhead location is allowing internal pressures to grow, which slows the methane liquid-to-gas transition and allows the fluid column from below to grow in increments towards the wellhead location. However, BP’s current methodology will never allow complete control over their pressurized environment within the supply pipe, because the oil they are trying to contain includes the methane liquid transitioning into gas and multiplying the volume by hundreds of times.
The solution to this problem is to completely seal the cap at the wellhead location, while redirecting the oil/gas through the Evacuation/vacuum Channel. At the same time, separated oil (methane removed) is reinjected at high velocity through the Irrigation Channel for the creation of a retrograde fluid column that does not allow for the expansion of the CPE through the methane liquid-to-gas transition. Sitting at my computer today, I have no clue as to whether the front line of the methane liquid-to-gas transition is taking place at 10,000 feet, or 5,000 feet, or 1,000 feet from the wellhead location. However, we should expect that the transition location is constantly changing (up and down the supply pipe) with fluctuating pressures associated with capping the pipe and adjustment of the ventilation ports.
The objective is to raise internal pressures in stages to test system integrity for signs of a new blowout. Raising the pressure also raised the elevation of the methane fluid-to-gas transition point to a location nearer to the wellhead, which reduces the volume of natural gas in our CPE equation. When the conditions are optimal (stabilized CPE) and the methane fluid-to-gas transition point is nearest the wellhead, then we begin the process of vacuuming out the environment and simultaneously reinjecting the separated oil to create our retrograde fluid column, until the two fluid columns are allowed to commingle and the methane fluid-to-gas transition cycle is eventually stopped.
Link #1: PressPresentation.docx - DivShare
Terral (info removed)
Last edited:
