Blow out protector valve employing ball baffle assembly for use with high-pressure fluids

A Ball Baffle Blowout Preventer (BBBOP) (102) or shut-off valve generally comprises a housing (106) and a baffle (108) secured within the housing and containing a plurality of holes. The housing is mounted in the path of the well pipe but the holes in the baffle allow normal production fluid to pass. One or more ball dispensing mechanisms (BDM) (110, 112) are connected to the housing. Each BDM contains a plurality of balls (114) and one or more valves (196). When a blowout condition occurs, a plurality of balls (114) are released beneath baffle (108) and are carried upward by the upwardly gushing fluid to plug the holes. The balls (114) are held in place by the pressure differential below and above the baffle. The balls can be removed from the baffle by the forcing fluid down the well. All operations can be controlled undersea by remotely operated vehicles (ROVs). A plurality of BBBOPs can be stacked and each can be set to operate at a different pressure and flow rates. The BBBOP may also include a Threshold Pressure Detection Unit for actuating the BDM that requires no electro-mechanical components; it uses only the energy of pressurized fluids in a well bore. The manual and self-actuating BDMs are not disabled by slow leaks of ambient well pressures past the hydraulic seals used therein. In another embodiment an additional baffle (250) can be provided below the first baffle (108) to contain the balls after they are released from the first baffle.

BACKGROUND

Sources and deposits of oil and gas are found below land and below the floor of the oceans and other bodies of water (hereinafter seas). Such deposits are often highly pressurized due to their depth. When oil companies drill wells at great depth, they must take care to contain these highly pressurized sources at all times so that they do not gush up and “blowout” of the well at the well head, where the well pipe reaches the surface. Special equipment called “Blowout Preventers” (BOPs) are normally installed at well heads to stop the uncontrolled flow of oil and/or gas.

When there is a sudden uncontrollable increase of pressure in a well, called a “kick,” standard BOPs in use today are designed to cut and seal off, crush, and/or otherwise seal a well casing so that the oil and/or gas cannot escape rapidly (blowout or gush). Such blowouts are particularly dangerous and harmful when they occur deep underwater, as happened in 2010 in the Gulf of Mexico. The 2010 Gulf Oil Spill demonstrated how difficult and expensive it is to stop the oil and gas gushing from a well deep under water when existing BOPs fail to operate properly. In addition, such gushers cause great ecological and economic damage and can cause loss of human, as well as animal, life.

There are three major components of a BOP system: a Blow-Out Detector, a Flow Stoppage Valve, and an Actuator.A Blowout Protector (BOP) is a robust and reliable valve mechanism that can stop the flow of oil or gas in a well.A Blowout Detector is a device(s) that measures pressures in a well bore and other conditions, such as fluid leakage, that indicate an impending blow-out condition.A BOP Actuator is a device that actuates a BOP when dangerous well pressures are detected.

The BOP is essentially a large shut-off valve in line with a well casing that is used in emergencies to stop an uncontrollable upward flow of high-pressure oil or gas. During drilling of the well, the BOP is normally open in the axial direction to permit insertion of drill pipes and drilling tools down the well casing. When the well is producing oil or gas, there is usually no drill pipe inside the BOP and the well casing above the BOP (the riser pipe) that is delivering the product. BOPs are typically affixed on top of a well casing at or slightly above ground or at sea floor level. For redundancy and reliability, two or more independent BOP units are usually mounted one on top of the other in a massive cast steel structure called a BOP stack. The typical BOP stack looks like a stack of enormous steel donuts. The stack can weigh several hundred tons and tower 50 feet or more in height. A typical BOP stack must have such great weight to counter the upward hydraulic force of the greatest fluid pressures that can occur in a well; such upward force can push a BOP stack off of the well casing if the stack does not weigh more than the upward hydraulic force.

Standard BOP valves require large hydraulic and mechanical forces to cut and seal off, crush, or otherwise seal a well pipe. The actuating forces are supplied by conduits from remote locations (like the sea surface) or by backup energy sources stored in or near the BOP stack.

Well bore pressures are measured and blow out conditions are detected by a variety of Blow-Out Detectors, which often are electro-mechanical devices that require external power.

BOPs are generally actuated by remote operators using control conduits connected to the BOP stack. For example, when blowout conditions are detected the remote operator sends a signal via the conduit to the BOP stack; the signal actuates one or more BOPs in the stack, causing a blockage in the well bore to prevent oil or gas flow up through the stack. Some control equipment can actuate BOPs automatically when blowout conditions are detected.

One standard BOP in use today is called an annular BOP. An annular BOP uses an elastomeric toroidal seal (usually made of rubber), called a packing unit. The packing unit is reinforced with steel ribs. Its outer circumference is restrained within the BOP housing. The inner diameter is sufficient to allow the passage of drill pipe and the joints which attach one piece of drill pipe to the next. In its inactivated state, the BOP allows rotation and vertical motion of the drill pipe. When the BOP is activated, the toroidal seal is squeezed from above and below in an axial direction by an activating mechanism. This squeezing (a) causes the inner diameter of the seal to decrease until it contacts the drill pipe, and (b) forces the outer circumference of the seal against the inside wall of the BOP housing, thus forming a tight seal around the drill pipe. If gas continues to flow up the drill pipe, mud can be forced down the drill pipe at sufficient pressure to stop this flow. At this point, drilling can resume. If no drill pipe is present, the annular BOP should still be able to completely close the well casing orifice. Knox, in U.S. Pat. No. 2,609,836 (1952), shows an annular BOP.

The other principal type of BOP is called a ram-type BOP since it uses one or more rams as explained in the next paragraph. An early one of these is taught by Abercrombie and Cameron in U.S. Pat. No. 1,569,247 (1926).

Four principal types of BOPs are in use today: pipe, blind, shear, and blind shear. All of these comprise pairs of radially disposed, opposing jaws with either seals or shears that are normally retracted and out of the way during drilling. Powerful hydraulic rams force seals or shears to move radially inwardly toward the center of the well casing or outward away from the center of the casing; the rams are supplied with actuating force, usually in response to a control signal from a remote location. The following is a brief discussion of these four principal types:

Pipe Ram BOP—When activated, the pipe ram BOP is designed to squeeze around the drill pipe and also to block the annulus between the drill pipe and the well casing. Elastomeric seals are used in conjunction with the squeezing mechanism to prevent leaks in these areas.

Blind Ram BOP—This type is similar to the pipe ram BOP, except that it seals the well casing when there is no drill pipe present.

Shear Ram BOP—This type is used to cut through and block the drill string or the well casing. A pair of shears cut through the pipe, followed by a pair of blind ram jaws that close on one-another, pinching the pipe shut and closing the annulus to any flow. Standard Shear Ram BOPs are destructive. They damage the drill pipe and/or the well casing within the BOP Stack in order to stop the flow of oil and gas through the BOP Stack. These pipes must be replaced in the BOP stack before normal well operations can continue.

Blind Shear Ram BOP—This type cuts through the drill pipe and blocks the annulus between the drill pipe and the casing, thereby sealing the well shut.

The above prior-art BOP mechanisms require great mechanical or hydraulic actuating forces. These forces must be supplied by force generating equipment within the BOP stack or by external means. Today, undersea wells are tended by Remotely Operated Vehicles (ROVs). In the case of these wells, an ROV cannot provide the forces necessary to operate the BOPs when their force generating equipment fails. The 2010 Gulf Oil Spill demonstrated the great difficulty and enormous expense required to repair and/or actuate conventional BOPs after they fail to operate properly, especially when the well head is deep underwater.

From my review of major oil spills, in particular the 2010 Gulf Oil Spill, I believe that existing BOP systems suffer from one or more of the following deficiencies or disadvantages:1. The BOP may require a separate or a remote electro-mechanical apparatus to detect dangerous pressures (kicks or blowouts) in the well casing to which it is attached.2. The BOP may require great mechanical or hydraulic forces to actuate its oil and gas flow stoppage valve mechanism.3. The BOP may need a backup power supply, such as batteries, so that it can actuate automatically when well pressures reach dangerous levels.4. The BOP may not be actuable manually by remote control lines or ROVs operating at great depths underwater.5. The BOP may damage the well casing or drill pipe when it is actuated.6. The BOP, once closed or in an obturating condition, may not be openable or reversible very easily to resume all other well operations.7. The BOP may be too expensive to be added to thousands of existing BOP Stacks on producing oil and/or gas wells to provide additional measures of safety.8. The BOP may be complex and not fail-safe, preventing it from being employed long-term and unattended on thousands of “capped” wells from which expensive BOP Stacks have been removed.

While all of the above disadvantages are significant, I presently believe that disadvantage 7—the high cost of BOPs—is one of the paramount concerns. The deep underwater oil and gas exploration business is in jeopardy until an economical and reliable BOP becomes available. The 2010 Gulf Oil Spill has demonstrated the need for additional blow-out protection on existing underwater oil wells with supplemental BOPs that can be actuated, adjusted, and repaired by ROVs working deep underwater.

I also believe that disadvantage 8—complexity and lack of fail-safe operation—is also highly important. There are no safeguards on thousands of supposedly “capped” wells that will eventually leak into the environment when their concrete plugs and even their steel well casings deteriorate.

SUMMARY

In one embodiment, my BOP comprises a foraminous plate or baffle that is positioned in the well pipe or a container or housing in series with the well pipe. The plate has an array of holes of a predetermined diameter. Adjacent and below the container or portion of the pipe containing this plate is a source of obturating balls that have diameters slightly greater than the holes in the plate. When a blow-out condition occurs, the balls are released under the plate so that the upward flow of fluid in the well pipe forces the balls upward against the plate where they lodge in the holes and thus cause the plate to block further fluid flow and prevent any blow-out.

ADVANTAGES OF VARIOUS ASPECTS AND EMBODIMENTS

I have developed improved BOP systems for use in the drilling and management of oil wells that, in one or more aspects, resolves to a significant extent, one or more of the above-listed deficiencies or disadvantages with standard BOPs in use today. In one or more embodiments, my BOP:a. is self-actuated when well pressures exceed specified limits that indicate a possible blowout; also the well-pressure threshold that triggers this BOP can easily be adjusted by remote control;b. can seal a well in a non-destructive manner, i.e., without causing damage to the well casings or riser pipe;c. can be opened after sealing (reversed) to allow normal well operation by simply pumping high pressure mud fluid down the well pipe above the BOP. This is the normal and usual “top kill” procedure whereby pressurized mud fluid is pumped into a well casing through a “mud port” in the BOP Stack to counteract the pressures in a well (controlling the well) after a BOP has been activated to stop a blowout. However no other expensive well structure repair or re-work actions are necessary to return the well to normal operation;d. embodies a unique and robust pressure detection apparatus (BDM112inFIG. 1) that requires no electro-mechanical components. Its only power source comes from the fluid pressure in a well casing. This purely mechanical Pressure Detection Unit (PDU) can reliably operate for long periods of time in a hostile oil well environment. It is very inexpensive. In addition to actuating a BOP, this autonomous PDU can provide pressure threshold signals for any other purpose in oil well operations.e. can be added easily and inexpensively to the ram-type BOP stacks on top of existing or future oil wells as an added measure of safety that the oil industry and government regulatory agencies desire for underwater wells. My BOP can be actuated quickly and reliably by light-weight ROVs operating in deep water to stop the flow of oil and/or gas when other BOPs fail, as happened in the 2010 Gulf Oil Spill.f. can be applied in its simplest and least expensive form to thousands of “capped” and abandoned oil and gas wells throughout the world that now rely only on concrete plugs in well casings to prevent oil and/or gas leakage into the environment. Expensive BOP Stacks have been removed from most of these capped wells. The concrete plugs in these wells and the steel well casings themselves will deteriorate with time. These “capped” wells will begin to leak unless there are flow stoppage devices such as my BOP on the well casings at the well heads.

The mechanisms disclosed can also function as valves for high-pressure conduits, which valves have certain advantages.

Further advantages of various aspects will be apparent from a consideration of the ensuing description and accompanying drawings.

DRAWING FIGURE REFERENCE NUMERALS

DETAILED DESCRIPTION

My apparatus uses a foraminous plate or baffle in conjunction with a plurality of balls to block the unwanted flow of fluids from a well. To distinguish my apparatus from prior-art BOPs, I call it a Ball Baffle Blowout Preventer (BBBOP). The baffle or plate of my BBBOP is positioned in a housing that is inserted into any BOP stack, oil well riser pipe, or well casing. The baffle is a thick metal disc or plate (much like a thick steel manhole cover) that has an array of holes drilled through it so that liquid and gas can pass through it without great restriction. To stop the flow of all fluids and gas through the baffle, its holes become tightly plugged by the release of solid balls into the oil or gas flow entering the baffle. The fluid flow forces the balls lodge firmly in respective holes in the baffle to stop the flow of oil and/or gas.

I also provide simple but very reliable Ball Dispensing Mechanisms (BDMs) that require very little energy or force to actuate. One BDM embodiment is fail-safe. It is self-actuating by well pressures that indicate blowout conditions in the oil well. It requires only energy supplied by the pressurized oil or gas in the well casing to which it is attached. The threshold pressures for automatic activation can be adjusted before installation or later by an ROV operating underwater. Another BDM can be actuated manually by control conduits to a distant control center or by an ROV that injects a small amount of pressurized fluid into a port on the BOP (like a grease gun operation). This operation is easily preformed by an ROV operating at great depths under water. Neither of these BDMs utilizes electro-mechanical components. Both of these BDMs will operate properly over long periods of time in the hostile oil well environment, even when their hydraulic seals are leaking slowly.

The flow stoppage performed by this Ball Baffle BOP (BBBOP) can be reversed by simply pumping mud fluid into the well pipe above the BBBOP and reversing the flow through the BBBOP to release the balls from the baffle and sweep the balls from the BBBOP housing. My BBBOP is very unlikely to destroy or damage the well pipe in which it is installed. Operating or actuating my BBBOP does not require large mechanical or hydraulic forces and/or sophisticated control systems, as is the case for the shear rams and other devices in the BOPs commonly used in the oil well industry today. This relatively inexpensive BBBOP is easily added to existing BOP stacks at the well head or it can be installed as a modular insert in the well casing below the BOP stack or the riser pipe leaving a BOP stack.

First Embodiment

Description

FIG. 1is an elevated, sectional view that shows a typical riser pipe or well casing with a lower section100that extends downward into the well, and a section100A that extends upward above a BBBOP102. Pipe100is transporting fluids104, indicated by dashed lines and comprising mainly oil and gas, upward from an oil well. Pipe section100-100A can be the passageway in a conventional BOP stack mounted above a well head, or in the riser pipe above the BOP stack. Additional BOPs can be inserted in the casing above or below BBBOP102. BBBOP102performs the same function as the blind ram BOP described above, i.e., it is used when the well has been drilled and producing oil and/or gas and a drill pipe is not present inside casing100-100A.

The present embodiment comprises a housing or container106, a foraminous baffle or plate108, one or more ball dispensing mechanisms (BDMs)110and112, each with a group of balls114. Housing106has an outlet192with a valve196. Valve196has a large throat so that when it is in an open condition, balls114can pass out through it unimpeded. In addition, valve196has a simple actuating handle198that can be grasped by the robotic hand of an ROV or a person when the BBBOP is used in shallow water or above ground. Outlet192allows balls114to be swept out of housing106by injection of mud fluid downward through casing100A from the top in order to “reset” the BBBOP, that is, unplug baffle108and allow oil and/or gas to flow freely through baffle108. Outlet192is more fully described below in connection withFIGS. 2 and 3.

All components comprising BBBOP102and its various fittings are preferably made of steel (either stainless or coated to prevent corrosion) and are of sufficient thickness and strength to withstand the high pressures that are encountered deep undersea and within well bores. The diameter of housing106is generally greater than that of casing100and ranges generally from 20 to 200 cm, although other sizes may be used. The remaining components shown inFIG. 1scale accordingly.

Baffle or plate108is circular and is securely held within housing106. It can be welded in place, or inserted into a circumferential groove. Baffle108contains numerous holes116which allow fluids104to pass upward and downward through baffle108without significant restriction or pressure drop. Holes116are preferably tapered outward at the bottom side and sized so as to admit and gently capture balls114, but not allow them to pass through holes116.

The present embodiment is for use during the production of oil and gas. Thus the casing does not contain a drill pipe and baffle108does not have a central hole for one. The aggregate area of holes116should be equal to or greater than the area of pipe100in order to ensure that baffle108does not interfere with flow in pipe100. For example, a pipe100with a diameter of 28 cm has area equal to about 615 cm2. If each hole116has a diameter of 5 cm, then the area per hole will be about 20 cm2. Thus if there are 31 holes116, they will have an aggregate area that is equal to the area of pipe100. The diameter of baffle108is determined in part by the strength required to block the high pressures encountered during a blowout. If holes116are too closely spaced, baffle108will not have sufficient strength. Thus some solid area will be required between the holes. If baffle108has a diameter of 64 cm for an area of 3,215 cm2the area of solid metal will be 5 times that of the 31 holes116, which should be sufficient. Because of the weight required at the well head, BOPs are generally much larger with typical diameters of 200 cm. Preferably the ratio of baffle area to hole area are used to select the diameter, thickness, and material strength required for baffle108. The holes116in baffle108are sufficiently sparse compared to the total area of baffle108that no loose ball114that reaches the surface of baffle108will be trapped between balls already lodged in holes116. Any loose ball has ample open surface on baffle108to move toward an open hole116. Under high flow conditions, the fluid pressure is much less near open holes116where there is a large flow velocity increase compared to other surface areas on baffle108. Hence, loose balls114move toward holes116that are open.

Ball Dispensing Mechanisms

BDMs110and112are part of BBBOP102. BDM110is manually actuated, while BDM112is self-actuated. Although two are shown, additional BDMs of either type can be attached to BBBOP102for backup purposes. BDMs110and112are located beneath the level of baffle108. Each holds a plurality of balls114. In one embodiment balls114all have the same diameter, which is slightly greater than holes116in baffle108. Balls114are typically made of metal such as stainless steel, although other materials can be used. They can be hollow or solid. If they are hollow, they must withstand extremely high blowout pressures in an oil well without collapsing. The density of balls114can be designed so that balls114will fall down casing100when they are not otherwise urged upward or contained by an additional baffle250(described below). In other applications, it may be desirable for balls114to float in any oil present below baffle108. The ball density can be predetermined, as described below.

The number of balls114in each of BDMs110and112is greater than the number of holes116in baffle108so that there is high probability that all holes116in baffle108will be plugged by balls114when the flow of fluids or gas104is at a blowout rate. In the above example, baffle108contains 31 holes116. For this case, BDMs110and112would each contain at least 40 balls.

BDM110has a simple and basic design for manual activation. It comprises a cylindrical tube118that is secured in a generally horizontal position to housing106at a position lower than baffle108. Balls114can be released under baffle108from tube118by a hydraulic piston assembly described below. The interior of tube118that holds balls114opens into the region below baffle108via a spring-loaded trap door120. An optional space is shown in tube118to the left (in front of) balls114to decrease the likelihood that the balls will fall out accidentally, i.e., the space insures that the balls have a lower probability of being expelled unless piston122is deliberately moved to the left.

In BDM110, a plunger122is attached to the left end of a shaft124. The right end of shaft124is attached to a piston126so that plunger122, shaft124, and piston126move together within tube118. Shaft124and piston126are supported by O-ring seals128and130, respectively. Seal128is supported at the central axis of tube118by a fixed support132. A chamber134A between support132and piston126contains a spring134. Spring134urges piston126to its rightmost position, i.e., at which plunger122rests against support132within tube118. A threaded cap136with an orifice138closes tube118at the right end, enclosing a hydraulic chamber140between the right end of piston126and the interior of cap136. Chamber134A has an exhaust port134B with a one-way or check valve134C so that any fluid or gas inside of chamber134A can be expelled when piston126is urged toward support132.

Dispensing Balls From BDM110

At the upper right inFIG. 1, conduit142with shut-off valve141is connected to port138. A one-way injection port143is also connected to chamber140. When a blow-out condition occurs or the well operator otherwise desires to dispense balls114into BBBOP102from BDM110, a small amount of pressurized fluid or gas is injected into chamber140. The fluid or gas can be supplied through conduit142from a remote location such as a ship or platform (rig) or it can be supplied from an ROV (not shown) via one-way port143. This fluid or gas enters chamber140and urges piston126to move forward, i.e., to the left, compressing spring134. The force constant of spring134is selected to hold piston126back, i.e., to the right, until the fluid pressure in chamber140reaches a level sufficient to move rod124and plunger122to the left against the hydrostatic pressure inside casing100. There is sufficient space in tube118so that balls114are not expelled out of tube118until spring134is compressed more than half way, as explained below in connection with BDM112. When the pressure in chamber140fully compresses spring134, plunger122has moved to the left and balls114are forced out through spring loaded trap door120. Door120is held shut with sufficient spring force to prevent balls114from entering housing106until they are pushed out by plunger122.

One ball114A is illustrated in chamber106to show that when balls114are dispensed by BDM110into housing106under high, upward flow of oil or gas104, they are forced upwardly toward holes116because the pressure is lower at the entrance to a hole than the pressure elsewhere in housing106. Ball114will lodge in one of holes116in baffle108so long as there is significant flow of oil or gas.

When a plurality of balls114are released from below baffle108by BDM110, the balls will be forced upwardly by the upward fluid flow, into the holes in baffle108. The upward fluid flow will carry the balls upwardly to any holes that are open so that the balls will seal all of the open holes. Thus baffle108will become essentially completely obturating, thereby forming an effective blowout preventer and preventing any further upward fluid flow. I.e., the released balls114will plug holes116in baffle106to stop all fluid and gas flow through the baffle.

BDM110is a modular assembly that can be removed from housing106and reloaded with balls when necessary. This can be done easily by an ROV at great depths under water.

Dispensing Balls From BDM112

The other ball dispensing mechanism112inFIG. 1is self-actuating. It is actuated automatically when a predetermined pressure that represents a blowout condition occurs in casing or pipe100. It can also be actuated manually at any time by additional apparatus shown inFIG. 1A.

BDM112comprises an inlet conduit144, first and second tubular sections146and148, respectively, a first fluid chamber150, a second fluid chamber151, a spring152, and a piston-shaft-piston assembly154,156, and158, respectively. O-ring seals160and162on piston154and plunger162separate chamber150from chamber151and the upper portion of tubular section148, preventing fluid flow between the two chambers. Conduit144is preferably secured to casing pipe100by a sealed joint164and tubular section148is preferably secured to the bottom of housing106by a sealed joint166. As with BDM110, a spring-loaded trap door168retains balls114in place until they are pushed out by piston158. The space above balls114in tube148is more important in BDM112because any increase in pressure P104will compress spring152. However the balls should not be expelled (i.e., baffle108should not be plugged by the balls) until P104reaches the threshold pressure that will compress the spring at least half way and cause further increase in well pressure P104, etc.

Assembly112is connected to casing or pipe100by conduit144which allows pressurized oil and/or gas to reach piston154and apply hydraulic force to piston154. Because of seals160and162, fluid chamber151between pistons154and158is not subjected to the instant oil and/or gas pressure P104in casing100. However, oil or gas104from casing100can slowly leak by these seals into chamber151. Vent conduit172connected to chamber151keeps the pressure in chamber151equal to pressure P300of the environment outside BDM112.

The outsides of pistons154and158are subjected to the same oil and/or gas pressure P104that is present in casing100. The inside surfaces of pistons154and158facing chamber151are subjected to the pressure in chamber151. Vent conduit172keeps the pressure inside of chamber151the same as P300, the ambient pressure outside of BDM112and well casing100. Hence, the net hydraulic force F154on piston assembly154-158is determined by the difference between pressures P104and P300and the difference in the surface areas of pistons154and158. The surface area of piston154is greater than that of piston158, as shown. The cylinder for smaller piston158is narrower than that for piston154. The junction between these cylinders comprises a shoulder that retains spring152. When pressure P104is greater than P300, the net hydraulic force F154is always upward as shown inFIG. 1.

Connected pistons154and158are restrained from moving upward by spring152. Spring152resists the net hydraulic force F154. Pistons154and158and spring152are designed such that spring152is fully compressed when the well casing100pressure P104reaches a preset threshold pressure, Pt, that indicates a dangerous or blow out condition. Spring152will be compressed to some degree by any net force F154. Spring152will be compressed 50% when well casing pressure P104reaches some level less than but close to the threshold pressure Pt. Tubular chamber148has sufficient empty space such that balls114therein are not expelled until spring152is compressed more than 50 percent. For each installation of BDM112, spring152is designed such that it is at least 50% compressed when well pressure P104approaches the threshold pressure Pt which indicates a blow out or dangerous condition for which the flow of oil and gas must be stopped in casing100A.

The dynamic of how BDM112operates is as follows: Spring152is fully compressed when well casing pressure P104reaches a predetermined threshold “blow out” pressure Pt. At some pressure P104approaching Pt, spring152is compressed more than 50% and some balls114are expelled. The first balls114released will partially close baffle108. Under blow out conditions (high fluid flow upward), pressure P104will increase rapidly due to restricted flow in casing100. This increase in P104will fully compress spring152and force all balls114to be expelled by BMD112. Balls114then completely block baffle108.

When chamber151is full of incompressible fluid, the time required for release of balls114will normally be dictated by the time it takes to expel the fluid out through vent172. Vent172can be sized such that very short transient P104pressure increases that are not dangerous by themselves (spikes) will not expel balls114. When BDM is above ground and chamber151is full of air at low pressure, the finite compression time of spring152allows BDM112to experience transient pressure increases or “spikes” of very short duration without releasing balls114.

Another very important feature of BDM112is that vent172keeps the pressure in chamber151constant, equal to the outside ambient pressure P300. P300is known for any given location where a BBBOP102with BDM112is installed (above ground or at a known depth underwater). Hence, BDM112with vent172can be designed to activate and expel balls114at a fixed blowout threshold pressure P104.

The use of vent172or its equivalent for equalizing pressure in chamber151is important because over a long period of time in the hostile environment of an oil or gas well, particularly underwater, seals160and162around pistons154and158will begin to leak, at least slowly. Oil or gas104will infiltrate chamber151. Without vent172, the net force F154generated by a given pressure P104will vary depending on the contents of chamber151. If a closed chamber151is filled with incompressible fluid, for instance, then BDM112becomes completely inoperable at any blowout pressure P104since piston154cannot move forward. If a closed chamber151is filled with gas, then the net force F154for a given threshold pressure P104will vary depending on how much gas has leaked out (or into) chamber151due to “leaky” seals160and162. Neither of these conditions, unknown pressures from varying amounts of fluid or gas in chamber151, allows BDM112to be adjusted or set to activate properly for a fixed blowout threshold pressure. However, with vent172and a constant known pressure P300inside chamber151, BDM112can be designed or set to release balls114at a fixed blowout threshold pressure Pt in well casing100. Thus it is not necessary to maintain or adjust BDM112to account for deterioration of the seals160and162and slow leakage of oil or gas into chamber151since vent172keeps the hydraulic pressure in chamber151at the ambient outside pressure P300at all times.

Alternative Embodiments with Activation Threshold Adjustment—BDM112

FIG. 1Ashows an alternative embodiment of BDM112in which the predetermined blowout threshold pressure P104for release of balls114can be adjusted after BDM112is installed, including manual adjustment and adjustment by ROVs operating deep underwater. Two blowout threshold pressure adjustment modalities are shown. The first uses an incompressible fluid and the second uses a compressible gas. Both modalities are shown inFIG. 1Afor convenience and their use can be combined; however preferably only one or the other of them is used at any one time.

Activation Threshold Adjustment by an Incompressible Fluid

As described above in connection withFIG. 1, changing the fluid or gas pressure in chamber151changes the net force F154produced by a given well casing pressure P104. The pressure in chamber151can be varied by filling chamber151with either liquid or gas. Consequently, the threshold pressure P104in well casing100that activates BDM112can be changed by changing the pressure in chamber151. The small amount of liquid or gas injected into chamber151via inlet174or from source200can be precisely controlled by a conduit from a remote location or by an ROV operating deep underwater.

InFIG. 1A, an additional valve170is connected to chamber151of BDM112via conduit172. Valve170is an adjustable pressure relief valve comprising a stopper182, a spring184, a plate186that is urged against spring184by a screw188, and an orifice190. An inlet174with a one-way check valve176, also connected to chamber151via conduit, allows the injection of pressurized fluid through inlet174into chamber151in the same manner that pressurized fluid is injected into BDM110through injection port138, as described above. The release pressure at which pressure release valve170opens is adjusted by turning an adjustment screw188that controls the compression force of spring184on pressure release valve stopper182.

When chamber151is filled with incompressible fluid via inlet174, piston154can only move forward when the fluid pressure in chamber151forces open relief valve170. Hence, changes in the release pressure setting of valve170change threshold blowout pressure P104(Pt) that activates BDM112. When chamber151is filled with an incompressible fluid, spring152is not compressed by transient increases in pressure P104that are less than necessary to open relief valve170. Spring152can only be compressed when P104is high enough to force open relief valve170. Thus, the setting of relief valve170determines the threshold pressure at which BDM112is activated. Normally, the Pt “blow out” threshold pressure setting (determined by the setting of valve170) will result in complete compression of spring152. Thus in a blowout condition BDM112activates suddenly and completely to expel all balls114. In this case, spring152acts only as a “cushion” to slow the speed at which piston154moves forward in a time equal to the full compression time of spring152.

Activation Threshold Adjustment by a Gas

In an alternative aspect of the present embodiment, a tank200provides gas at a predetermined pressure in chamber151in order to allow adjustment of the effective blowout threshold pressure at which BDM is activated. Using gas instead of an incompressible fluid causes BDM112to activate in a more gradual fashion than with fluid in chamber151.

Tank200contains a pressurized gas such as nitrogen that can be delivered to chamber151through conduit172. Tank200has a shut-off valve205, a regulating valve210, and two pressure gauges215and220. The outlet of regulating valve210is connected to conduit172via a port225and a valve230. Valves205,210, and230all have simple adjustment handles that are suitable for operation by the robotic hand of an ROV. Regulator210ensures that the pressure inside chamber151remains at a predetermined level for an extended period of time. This is desirable since seals such as160and162and valve170can leak over time.

The gas pressure in chamber151at any time contributes to the downward force on piston154and therefore determines the force necessary to move piston154upward. A compressible gas in chamber151provides a “cushion” against forward movement of piston154and provides a time delay so that balls114will not be immediately released into housing106when high blowout pressure P104forces piston154forward. The gas pressure in chamber151can be adjusted in conjunction with relief valve170to dictate the threshold pressure on piston154that is required to move piston154forward and release balls114. The gas pressure in tank200must be greater than the normal well head pressure P104in well casing pipe100in order to prevent incompressible fluid from the well from leaking past seals160and162and filling chamber151. For a well that is 1.5 km (5,000 ft) under water, the pressure required in tank200can be as high as 345 bars (5,000 psi). It will be much lower for a surface well head with normal oil and gas pressure.

Attaching tank200to BDM112provides an alternative way to maintain a constant pressure in chamber151so that a constant blowout threshold pressure Pt setting can be maintained for BDM112. Tank200eliminates the need for an open vent172as inFIG. 1that communicates with the outside pressure P300. An open vent172can be clogged with debris in dirty environments. Normally, the pressure of the gas maintained in chamber151by tank200will be greater than the average well casing pressure P104. With this pressure difference there will be little or no leakage of fluid from well casing100past the seals160and162into chamber151.

Both threshold pressure adjustment modalities170and200for BDM112are shown inFIG. 1Afor convenience and their use can be combined. However, preferably only one or the other of them is used at any one time.

BDM112is a modular assembly that can be removed from housing106and reloaded with balls when necessary. This exchange of BDMs112can be done easily by an ROV at great depths underwater. Several BDMs112can be mounted on a BBBOP casing106for backup and redundancy.

In addition to being able to dispense balls when a predetermined pressure P104is reached, BDM112also provides a very reliable, robust general-purpose threshold pressure detector that can be used for many additional purposes. E.g., when piston158moves up in response to a pressure threshold being exceeded at P104, it will move upward a predetermined distance. This movement can be used to generate an increased pressure in conduit148, creating a pressure signal which can be sensed to cause an electromagnetic signal to be transmitted, any mechanical device to be actuated, etc. BDM112is purely mechanical and does not require or use any electronic components. It can survive long periods in hostile, high-pressure environments such as an oil well, because its seals can leak slowly, as described, without harming its operation, even if the pressure outside suddenly exceeds a threshold.

While BDM112has upper and lower ports that are connected to the lower end of chamber106and a point in casing100below chamber106, these two ports can be connected at alternative locations, such as upper and lower apertures on chamber.

Alternative Embodiment

FIGS.2-4—Description and Operation

FIGS. 2 and 3are sectional, side views of a first alternative embodiment in which a second baffle250is rigidly secured below baffle108to prevent balls114from falling down well casing100when they are not urged against holes116in baffle108by high velocity upward flow of oil or gas. Thus balls114are normally captured within the volume between baffles108and250. InFIG. 2, baffle250preferably contains a plurality of slots255as shown inFIGS. 2A and 3. The combined area of slots255is greater than the combined area of holes116so that flow through baffles108and250is not impeded so that downward flow of mud fluid, when necessary, can continue even when balls114are resting on baffle or plate250. The width of slots255is less than the diameter of balls114so that balls114are unable to pass through or lodge within slots255. Baffle250is tilted at an angle, θ, e.g., 15 degrees and preferably between 0 and 30 degrees. InFIG. 3, balls114will be urged down to baffle250and toward outlet192when pressurized mud fluid is forced down well pipe100A and through baffle108and baffle250.

When it is desired to unblock baffle108, balls114are removed from housing106as shown inFIG. 3. A conduit300is affixed to outlet192in place of cap194(FIG. 2). Fluid, such as a mixture of water and drilling mud, is pumped into pipe100A from above as indicated at305. The pressure at which the fluid is pumped downward is greater than that of the fluid that is urged to flow upward in casing100(a normal “top kill” well control procedure). Thus a net downward flow of fluid occurs, urging balls114to fall downward out of holes116toward baffle250. At this time, valve196is opened and the fluid flow indicated at305exits housing106via outlet192, valve196, and conduit300. Balls114are entrained in this flow and are thus removed from chamber106. The slope of baffle250aides in urging balls114toward outlet192.

In an alternative aspect, conduit300can be omitted and balls114can be discarded outside housing106if desired.

Outlet192is equivalent to the standard “mud” or “choke” ports on existing BOP stacks that are used to inject and extract fluids from the well at the BOP stacks. There may be additional mud and or choke ports positioned on housing106between baffle108and baffle250for the purpose of re-circulating mud fluid and/or pressure testing the integrity of the BBBOP assembly in the same standard fashion that conventional BOPs are pressure tested.

FIG. 5shows an alternative aspect of the first alternative embodiment. This embodiment provides a passive, fail-safe BBBOP or shut off valve for thousands of abandoned wells that have been capped with concrete plugs in their well casings. Expensive BOP stacks have been removed from most capped wells. But these “dead” wells may come alive again someday and leak when their concrete plugs and steel well casings deteriorate. The “capped well” BBBOP embodiment inFIG. 5provides an inexpensive means to prevent serious leakage from capped wells, in particular underwater wells that have been capped and abandoned.

InFIG. 5, instead of injecting balls114via BDMs110or112during a blowout as inFIG. 1, a plurality of balls114are simply left in chamber106where they remain between baffle108and baffle250. The density of balls114is designed such that any substantial upward flow of oil or gas will cause balls114to plug the holes116in baffle108. Balls114can be designed (as described inFIG. 9below) such that they normally float in water or oil so that only a slight upward flow force on the balls will cause them to plug holes116in baffle108. Hence, the BBBOP embodiment ofFIG. 5is a passive one-way valve that allows sea water or other fluids to enter well casing or riser pipe100A or port192at all times but stops any substantial upward flow of oil or gas. When balls114rest on slots255in baffle250, they do not occlude the slots. Therefore fluid can flow freely downward through the spaces in baffle250when balls114are present.

A valve500is inserted into riser pipe100A and closed by turning an actuator505. Actuator505is sized and shaped so that it can be operated by the robotic hand of an ROV (not shown). Valve500is normally open at all times to allow free flow of liquids down pipe100A. Valve500can be used to close pipe100A when there is no great pressure against the valve. Valve500can be closed to stop slow leakage from the well that does not actuate the BBBOP ofFIG. 5or when the well is being reworked through port192with no great upward pressure at the well head.

The one-way valve BBBOP embodiment ofFIG. 5allows free flow of sea water down pipe100A at all times for underwater wells that have been capped and abandoned. A sea water column in the well casing provides pressure atop the concrete plugs to counteract the pressure of oil and gas forcing the plugs upward. The well casing at the top of underwater plugged wells is normally open for this reason. This is done to maintain a column of sea water above the concrete plugs in the well casing. If the well is closed at the top, the essential sea water column in the well casing can dissipate over time.

Outlet192is normally kept closed by a cap194for this “capped well” BBBOP. It can be opened and used in case rework of the well is necessary or desired in the future by injecting mud fluid down the well to control it, that is, stop the upward flow of oil or gas. In this and the other embodiments of the BBBOP, outlet192can be used for purposes other than purging balls114from housing106, such as servicing the well. For example, cap194can be removed and a conduit (not shown) containing mud fluid can be attached. When valve196is opened, the mud fluid can be forced into the well. In this case, port192becomes a standard “mud port” as found on standard BOP stacks.

The capped well BBBOP will normally be encased in a very heavy block of steel or concrete similar to the weight of the standard steel BOP stack that was in place during drilling and production of the well. This heavy encasement is necessary to counteract the substantial upward hydraulic force at the well head exerted by a blowout that bypasses the concrete plugs and pushes out the sea water column above them. The blowout upward force can be of the order of 0.9 meganewton (100 tons). Hence, the encasement around the BBBOP must be even heavier. This capped well BBBOP would normally be encased in a heavy concrete block sitting on top of the well head instead of much more expensive steel as is used for standard BOP stacks.

Second Alternative Embodiment

The previous BBBOP embodiments are designed to prevent blowouts of producing or capped wells from which the drill pipe or other production pipes have been removed.FIGS. 6 through 8show an embodiment of the BBBOP that accommodates drill pipes of various predetermined diameters inside well casing100,FIG. 1, and internal pipes in casing106′ inFIGS. 7 and 8. This embodiment accommodates drill pipes of various predetermined diameters by adjusting the central hole size of the baffles to fit the drill pipe diameter so that a tight seal can be obtained during a blowout. A first drill pipe having one diameter can be withdrawn and replaced with another one having a different diameter.

FIG. 6is a perspective view showing upper and lower baffles108′ and250′, respectively, which are assembled from a plurality of wedge-shaped pieces600and605that are arranged to surround a drill pipe610. Housing106′ has been omitted from this figure for clarity. Wedges600include a plurality of holes116that are sized and shaped to accept and be obturated by balls114, as above. Wedges605include a plurality of slots255′ that are sized as in the previous embodiments to permit flow of fluids while preventing balls114from falling down into the well.

One or more tools615are shaped for easy grasping by the robotic hand of an ROV. In use, tool615is slidably inserted into a mating hole620or625in respective wedges600and605. Wedges600and605are then inserted into BBBOP housing106′ through removable ports700and705(FIG. 7), respectively. Ports700and705are slightly wider than the outer edge of wedges600and605. Once wedges600and605are inserted into ports700and705, tool615is used to push the wedges to the right or the left in order to make room for the tip of the next wedge to be inserted. When the tip of the next wedge is forced inward, it will cam all wedges presently inside housing106′ to the right and/or to the left in order to make room for this next wedge. When insertion of this next wedge is completed and the rest of the previously inserted wedges are pushed around as far as possible, tool615is removed and used to insert another wedge. Additional wedges600and605are inserted and pushed around until baffles108′ and250′ are complete.

FIG. 7is a cross-sectional, side view of a BBBOP according to one aspect of the present embodiment. Wedges600and605have been inserted through ports700and705. Wedges600are preferably nominally trapezoidal when seen from above and from the side and include an elastomeric seal710at the lower end near pipe610. An elastomeric bumper715is secured to the top of each of wedges600. These bumpers compress and lie flat during insertion of wedges600through port700. Once wedges600are in place, bumpers715expand to their original shape and bear against the upper, inner wall of housing106′, preventing wedges600from vibrating under varying pressures in the well. During normal use, wedges600are tilted downward near pipe610to provide an open area for the flow of oil and to avoid wear due to contact with pipe610. During a blowout, balls114block holes116′ and wedges600are forced upward, pressing seal710tightly against pipe610(FIG. 8) and stopping the flow of oil and gas.

The underside of each of upper set of wedges600includes a curved, recessed slot720that mates with a raised ring725in housing106′. Regions720on each of wedges600seat on ring725so that wedges600are normally held out of contact with pipe610. Similarly lower set of wedges605include a curved, recessed slot730that mates with a raised ring735around the lower, inner surface of housing106′. Wedges705are held away from pipe610at all times.

After all of wedges600and605are in place, plugs740and745are slidably inserted into ports700and705and bolted in place by bolts750. As with other movable parts, the heads of bolts750are shaped for easy rotation by the robotic hands of an ROV.

Operation Of Second Alternative Embodiment

FIG. 8is a cross-sectional view of a portion of housing106′ of the present embodiment during prevention of a blowout. Increased pressure and flow from the well, indicated by dashed arrows755, has caused balls114to rise within housing106′ and block holes116′ in upper baffle wedges600. Balls114were either (a) dispensed automatically by BDM112, (b) could have been left in the space between baffles108′ and250′ to be deployed automatically, or (c) dispensed manually by BDM110.

Wedges600have been forced upward by the well pressure, pivoting around the outer edge adjacent the inner surface of housing106′ and moving from a downward slanted position to horizontal. The upward pressure has compressed bumpers715, causing them to spread out and form a seal between wedges600and housing106′. With wedges600in this position, elastomeric seals710impinge tightly against pipe610, completing the sealing of the well.

When it is desired to remove or replace pipe610with another of a different size, ports700and705are opened and wedges600and605are first removed. Then pipe610is replaced, and finally a new set of wedges600′ and605′ (not shown) properly sized for the new pipe (not shown) are inserted. Finally ports700and705are again closed by plugs740and745.

Ball for Use in all Embodiments

FIG. 9shows a cross-sectional view of one composite version of ball114that may be used in the various embodiments of the BBBOP described above. Ball114comprises a core900, a shell905, and an outer surface910.

Core—The material comprising core900is used in part to determine the density of ball114. If core900is absent, the density of ball114is low and is determined by the density and thickness of shell905in combination with surface material910. Core900can be solid material of any sort or it can be filled with a high-pressure gas or an incompressible fluid to resist crushing of ball114when it wedges in a hole116of baffle108(FIG. 1).

Shell—Shell905is made of a hard material such as a strong metal, ceramic, or plastic. This is necessary to prevent the collapse or distortion of ball114when it is in use.

Surface—The outer surface910of ball114comprises a thin sealant layer of elastomeric material. When ball114is forced into hole116, surface910conforms to any irregularities in the surface of the entrance to hole116, thereby preventing any upward leaks of oil or gas.

Strong balls114that will not be crushed in the holes116of a BBBOP can be designed to have densities more or less than oil or any other fluid by selection of the appropriate core, shell and surface materials.

I have provided a Ball Baffle Blowout Protector (BBBOP) for oil and gas wells and a shut-off valve for high pressure pipelines that, in one or more embodiments, can be actuated more reliably, is less likely to fail, is a simple, fail-safe system, requires no great mechanical or hydraulic force to operate properly, and is self-actuated when well pressures exceed specified limits that indicate a possible blowout. The pressure threshold is easily adjusted by remote control and can be activated by an ROV deep underwater. The BBBOP can seal a well in a non-destructive manner and can be opened (reversed) to allow normal well operation. The BBBOP is easily added to the top of existing and conventional BOP Stacks to provide the added measure of safety for deep underwater wells that the world hopes can be achieved. One embodiment provides an extremely important, inexpensive, fail-safe BOP (shut off valve) for thousands of capped wells that will leak or blowout someday when their concrete plugs and steel well casings deteriorate.

The embodiments described are so inexpensive that multiple Ball Baffle BOPs (BBBOP) can be stacked on top of one-another as is presently done with conventional shear-ram BOPs. Each BBBOP in a stack can operate independently of the others, with no interference from one to another. When multiple BBBOPs are stacked, each can be set to self-actuate at a different well bore pressure if desired by adjusting the threshold ball release pressure of BDM112. Alternatively, an ROV can manually activate any of the BBBOPs using BDM110. The “blowout” pressure detection apparatus in the self-activating BBBOP is immune to inevitable fluid and gas leaking by its hydraulic seals.

While the above description contains many specificities, these should not be construed as limitations on the scope, but as exemplifications of some present embodiments. Many other ramifications and variations are possible within the teachings of the invention. For example, the material of the balls can be changed, the balls can be made of a solid metal or a composite as illustrated inFIG. 9, or can have a hollow core. The balls can be made of a hard metal or a soft metal or other material so as to conformingly mate with the any irregular holes in the baffle. The activating mechanisms can be varied, as can the shapes of the components. The BBBOP can be used with gas, oil, or combined wells, either underwater or on land. The holes in the baffle and the diameters of the balls can be non-uniform in size. The holes in the baffle can be made non-circular in order to permit a partial seal that would release pressure while slowing flow. The sizes and shapes and materials of all components can be varied. The BBBOP can be used as a general purpose shutoff valve. For example, it can economically replace standard ball or gate valves in very large water or gas pipes. It can be operated manually or automatically to control flow in pipes of any sort that carry fluids. While the embodiments with two baffles are described for use in blocking upward fluid flow, they can also be used to block fluid flow in the downward direction or either horizontal direction if the conduit is horizontally oriented. To block flow in either of two directions, the lower or second baffle should be provided with holes (like the upper baffle) that can be obturated with balls. By injecting or providing a plurality of balls between the baffles, the fluid flow will carry them to the downstream baffle, where they will mate in respective holes and cause that baffle to become obturating. In lieu of a spring-loaded trap door to hold balls114in tube118(FIG. 1) any other type of openable ball retainer, such as a friable barrier, can be provided.

Thus the full scope should be determined not by the specifics given but by the appended claims and their legal equivalents.