John D. McLain and Darrell G. Foreman
C. Jim Stewart & Stevenson, Inc.
From 1955 to 1963, the control system design used in subsea drilling was basically a land rig or "closed-type" system. A hydraulic power unit provided fluid to a shipboard mounted control valve manifold. Hydraulic power lines were run from this manifold directly to each BOP stack function. These hydraulic lines were either run down the riser, were an integral part of the riser, or were huge independent hose bundles, Actuation of a control valve directed fluid to the respective stack function. The opposite function on that ram or other stack component discharged back through the respective power line, through the shipboard mounted control valve, and into the reservoir of the hydraulic power unit.
The drilling water depths during the initial years of this period were relatively shallow and the use of the field proven land rig components was a natural design decision. Closing times on the blowout preventers were reduced by using larger
I.D, power hoses from vessel to subsea stack. Koomey Division of Stewart and Stevenson designed the first 3,000 psi working pressure accumulator system during this period. Larger volumes of fluid could be stored under pressure in less space, and with the addition of a pressure reducing and regulating valve, actual working pressure of the control fluid could be maintained within the limits of the stack components.
As the water depths increased, serious problems developed with this type system. One, the huge hose bundles used between vessels and BOP stack were not adequate due to vulnerability to currents and the forces of the sea. Also shipboard handling procedures were long and costly. However, to reduce overall O.D. was impossible because with the greater water depths came dangerously longer closing times for critical BOP functions.
In March, 1963, a new concept was designed and put into operation by Payne Manufacturing Company. Subsea pilot operated control valves were installed on the BOP stack. Power fluid was directed to this manifold of subsea valves from the vessel through a single 1 inch hose. One-eighth inch I.D. hoses were used to transmit hydraulic pilot signals from the vessel to the subsea control valves. Additionally, the subsea control valves were designed to "vent to sea" the discharging fluid from a ram or stack component when actuated. Closing times were drastically reduced. The subsea control valves were installed in a retrievable connector called a pod.
Thus, the advent of what is called the "open type" system. This is the most commonly used type system today, Koomey, Cameron-Payne, Valcon, and Hydril Company offer this pod type system. Hydril Company offers the pod in electro-hydraulic form only. Electro-hydraulics will be covered later in detail.
In the past five years much has been done to reduce the actuation or closing times on subsea BOP stacks. By 1968-1969 drilling water depths had gradually increased to a 600 foot maximum. Then, a major oil company outfitted two floating drilling rigs in the Santa Barbara Channel with subsea equipment capable of drilling in up to 1500 feet of water.
Closing times, even with the subsea pilot operated pod valve systems as available, were no longer acceptable simply because of the greater water depths. Kick detection on a floating drilling rig is far more difficult than on a land rig. The flow indicator commonly used on land to monitor flow out of the bell nipple is not accurate on a floater, because the rig's heave causes the flow out of the bell nipple to vary erratically. Also, an increase in the rate of penetration is difficult to detect because the bumper subs must "drill off before a substantial change in rate of penetration is detected.
One of the other commonly used methods of kick detection, the pit level indicator, is also affected by the vessel motion. Because of the kick detection problems on a floating drilling vessel more extraneous fluids can enter the well bore and rise farther up the well bore before being detected than on a land rig. To offset the lack of speed and accuracy in kick detection, coupled with the greater water depths, a faster actuation of the subsea BOP's was essential.
Koomey introduced the first solution to reduction in BOP closing times in 1969 in the Santa Barbara Channel. Previous pilot hoses were all Vfe inch I.D. Koomey's solution was a hose bundle of mixed pilot hose sizes—Va inch continued to be used on functions not requiring speedy reaction times (surface command to subsea pod valve shifting time), and a new 3ke inch I.D. pilot hose on stack functions requiring fastest possible reaction times (BOP's). Construction details directly responsible for this faster reaction time with 3/ie inch I.D. hoses and discussed in the following BOP control systems component breakdown.
Today, acceptable closing times can be achieved by proper design and installation of the control system and the related piping for the hydraulic power fluid. However, fast closing times alone are not the only factor to be considered in designing a control system on a floating rig. Overall safety in component layout must be given prime consideration.
Today, there are three basic component layout designs offered. Figure 3-15 shows the most basic and least expensive. However, it is also the least acceptable by the industry today. In this system, the Driller's Panel is the shipboard mounted hydraulic pilot valve control manifold. Located at the driller's position on the rig floor, it is in the most hazardous area of operation on a drilling rig. Destruction ot damage to this panel destroys
Koomey Hydraulic Control System With Hydraulic Operated Driller's Panel
1. Hydraulic Power Unit with Pumps
Fig, 3-15 Koomey hydraulic control system with hydraulic operated driller's panel.
the entire BOP control system's capabilities. An electric remote panel, usually located in the tool pusher's office, gives a second point of control under emergency conditions as long as the Hydraulic Driller's Panel is operable.
Figure 3-16 shows the shipboard mounted hydraulic pilot valve control manifold located in a safe yet accessible area and remotely operated by an Air Master Panel located at the driller's position. Remote operation is accomplished by sending an air signal through air tubing to an air operator mounted on the hydraulic pilot valve mounted on the pilot valve manifold. Operation of this valve sends the hydraulic pilot signal through the hose bundle to the subsea control valve located in the pod on the BOP stack. An electric remote gives a third point of control. Loss of the Air Master Panel does not negate the BOP control system and there remain two points of control.
Figure 3-17 shows the BOP control system most preferred by the industry today. The pilot valve control manifold is located in a safe area and remotely controlled from the driller's position by an Electric Driller's Panel. This panel is totally explosion-proof and has two distinct advantages over the previously described Air Master Panel: (1) it does not require the multi-tube air cables run between driller's position and pilot valve control manifold, (2) most important, it gives immediate response from command at Electric Driller's Panel to pilot valve shift at Hydraulic Manifold.
On most Air Master Panel installations a time lag of from two to five seconds is required from command to pilot valve shift at Hydraulic Manifold depending on distance and length required on interconnecting air cables.
Remote operation from the Electric Driller's Panel is accomplished by sending an electric signal from the Electric Driller's Panel to an ah solenoid valve located in an explosion-proof box on the Hydraulic Control Manifold. The air from the solenoid actuates the air operator on the hydraulic pilot valve sending a hydraulic pilot signal through the hose bundle to the subsea control valve located in the pod on the BOP stack. Again, an electric remote gives a third point of control. An emergency power pack is provided with the system that automatically gives battery reserve power to the two remote panels should rig power
1, Hydraulic Power Unit with Pumps
2, Hydraulic Jumper Hose Bundles
3, Subsea Hose Fieels (with Manual Control Manifold)
4, Subsea Hydraulic Hose Bundles Subsaa Control Pods
Koomey Hydraulic Control System With Electric Operated Driller's Panel
Rg, 3-17 Koomey hydraulic control system with electric operated driller's panel.
be lost. The following is a breakdown of each component in a hydraulic BOP control system with recommended sizing specifications and formulas.
This unit consists of the hydraulic reservoirs, mixing/proportioning system for the power fluid, pumps and accumulators. Sizing of all the individual components is directly related to the size and working pressure of the BOP stack to be controlled.
Blowout preventer control systems, like other hydraulic systems, need a high quality fluid to perform their operations satisfactorily. The hydraulic fluid lubricates all the valves in the control system and acts as a corrosion inhibitor for subsea internal parts. Most drilling contractors have been using water soluble cutting oils mixed at various concentrations for their BOP control fluids. Recent domestic legislation regarding the dumping of any oil base fluid in our offshore waters, coupled with the problems encountered with existing fluids, have prompted Koomey, in conjunction with a major chemical company, to develop a nonpullutant hydraulic fluid for BOP control systems. Cameron-Payne now has a similar fluid on the market.
One of the main problems encountered with the old fluids is the formation of undesirable precipitates when the fluids become contaminated, most notably with sea water. A precipitation problem is also created when hard make-up water is used. The precipitates formed decrease the overall efficiency of the system and have, on occasion, completely plugged the pilot lines in the hose bundles. All of the hydraulic fluids must be compatible with ethylene glycol to prevent freezing.
Regardless of the fluid used, a 40 micron filter system should be used downstream of the pumps. Filters should be connected in parallel so one can be cleaned without closing down the entire system. The make-up water used on a rig should come from a distillation unit on board. Water brought from shore on a workboat should not be used. Periodic flushing of all hoses is also good practice.
The hydraulic fluid previously mentioned is pumped from the mixing reservoir to accumulators, which are nothing more than sources of stored hydraulic energy. There are two basic types of accumulators, the bladder type and the guided float type. Both types used today are precharged with nitrogen to a given pressure [1,000 psi in 3,000 psi working pressure hydraulic control systems) then filled with hydraulic fluid to some higher pressure (3,000 psi), compressing the gas.The gas acts as a spring and forces the hydraulic fluid out of the accumulator.
in the guided float type accumulator, the gas actually comes in contact with the hydraulic fluid. Both Cameron-Payne and Koomey offer the guided float type accumulator in both spherical and cylindrical forms. Koomey recommends and offers a bladder type accumulator for positive separation of gas préchargé and hydraulic fluid. The bladder type is also field repairable whereas the guided float type is not.
All accumulators behave in accordance with the universal gas law:
R= Universal gas constant m= Mass
For a given mass, the Tight-hand side of Eq. (1) will have a constant value regardless of the PVT interaction. If we assume that the accumulator operates isothermally (temperature of the gas remains constant during compression or decompression), the P-V relationship can be written as:
where the subscripts designate two different sets of conditions.
Some accumulators during charging and discharging tend to act adiabatically. In this condition, the gas does not lose or gain any heat during compression or decompression, and consequently temperature varies. If heat cannot enter or exit, Eq. (2) will not describe the reaction. Separator types of accumulators, especially bladder and diaphragm types, exhibit this type of action. The following equation must be used to describe the pressure volume discharge characteristics:
where y is the ratio of the specific heat at a constant presure to the specific heat at a constant volume for a given gas. Nitrogen is used as the precharge gas because it is an inert gas. For nitrogen, y is 1.40. When any accumulator discharges, it will react in accord with Eq. (2), (3), or a combination of both.
All accumulators should be precharged with nitrogen, which provides a safe source of potential energy. In an accumulator, the higher the precharge, the less fluid volume the accumulator can hold.
Sizing of the BOP control system components is directly related to the size and working pressure of the BOP stack to be controlled. Once the stack has been defined the first component to be sized should be the accumulator capacity, Koomey recommends, as do most major operators, the accumulator capacity to provide fluid to open and close all ram type preventers and the primary annular preventer plus 50% reserve,
A quick method to determine the volume of accumulators on a given BOP stack is to determine the fluid volume required to open and close the preventers w/50% reserve. Multiply this figure by 1.98 to determine the total accumulator volume.
A portion of the accumulator capacity should be placed on the BOP stack. The reason for this is to reduce closing times. By placing a portion of these accumulators as close to the pod valves as possible the friction loss experienced with all accumulators on surface is reduced. In testing a 163A inch 5,000 psi working pressure BOP stack during rig-up, the subsea accumulators were isolated from the system and the annular preventer closed and timed. Hose bundle length was 750 feet with approximately 100 feet of jumper hose bundle between hydraulic manifold and hose reel. The subsea accumulators were then opened to the system and the test repeated. With no subsea accumulators the closing time on the annular preventer was 30
seconds. With subsea accumulators the closing time was reduced to 14,8 seconds.
Further testing is being done at present to determine the accumulator volume required subsea to give optimum closing times on any given size preventer at any given water depth.
When the subsea accumulators are precharged, the hydrostatic pressure due to the working water depth must be added to the préchargé pressure to compensate for the loss of fluid caused by the hydrostatic head. There is a substantial difference in the volume change as water depth increases.
The préchargé on all accumulators should be checked every time the stack is on the surface. Those accumulators permanently mounted on board the vessel should have their préchargé checked at least once a week. An easy method for checking the surface accumulators is to isolate the individual banks of accumulators and bleed them down separately. As you are bleeding the pressure off, observe the pressure gauge on the unit labelled "Accumulator Pressure." This gauge will slowly fall to the préchargé pressure and then fall immediately to zero as the accumulators close. If the gauge slowly falls below 1,000 psi before dropping rapidly to zero, one or more accumulators is not fully precharged to l ,000 psi. The subsea accumulators must be checked individually with a pressure gauge each time the stack is on the surface.
Pumps should be provided with a dual power source for safety. The accepted standard is to provide both air powered and electrically driven pumps on the accumulator unit. Both the air powered and electrically driven pumps should be 3,000 psi working pressure. In sizing the pumps, a recovery time from 0 to 3,000 psi of the accumulator volume should be 10 to 15 minutes. Two middle-sized pumps generally are preferred to one master pump for the safety in redundancy. The electric pumps should always be connected to an auxiliary generator for use in emergency conditions.
The mixed fluid reservoir should be sized to hold adequate fluid to completely charge the accumulators from 0 to 3,000 psi. The mixing system should be designed to have a mixing rate at least equal to the maximum pumping rate of the pumps.
This is truly the "heart of the system." As previously discussed, it is a recommended and accepted practice now to place this item in a safe, yet accessible, location on the vessel. Contained in the hydraulic manifold are pilot control valves (normally one per hydraulically actuated stack component) complete with air operators and hydraulic pressure gauges foT the various pressures required on the BOP stack, complete with pressure transmitters to convert these hydraulic pressures to either air signals or electric signals and transmit them to either the Air Master Panel or the Electric Driller's Panel.
Also located on this item are the pilot regulators that remotely control the subsea hydraulic regulators located in the pod. These pilot regulators are remotely controlled from the Driller's Panel (Air or Electric). There are normally three regulators on each Hydraulic Control Manifold—one for the ball joint, one for the annular preventer(s), and one for the remaining stack functions. Explosion-proof boxes containing pressure switches are included for remote panel indicating light operation, and air solenoid valves enable remote operation of the pilot control valves and pilot regulators.
Hydraulic hose bundles are used to transmit pilot signals and power fluid from the Hydraulic Control Manifold to subsea pods. At present there is only one accepted manufacturer of hydraulic hose bundles for use in subsea BOP control systems: Samuel Moore Company, maker of synflex hose. Synflex hose consists of an inner nylon tube wrapped in from one to four braided sheets, then covered with polyurethane. The two sizes of pilot hoses used in the subsea bundles are the Va inch I. D. 3130 series and 3Iinch I.D. 3300 series.
The Vb inch pilot hose inner nylon tube is wrapped in two braided sheets, while the 3/ie inch pilot hose inner nylon tube is wrapped in four braided sheets. This allows the Va inch pilot hose to have a greater expansion characteristics than the 3/i6 inch pilot hose. The greater the expansion, the more fluid is required to generate a signal and completely actuate the subsea pod valve.
In May 1974, Samuel Moore introduced a new 3ii6 inch hose. It has a maximum O.D. of 0.358 inches where the old 3/i& inch hose was 0.523 inches O.D. The O.D. of the new 3/is inch hose compares very closely to the old Vb inch hose which is 0.334 inches. The new 3Iis inch hose allows the hose bundle to be all 3Ii6 inch hoses and have a smaller diameter than a mixed hose bundle formerly did. The smaller O.D. allows more hose on the same size hose reel and improves the overall signal time for all functions on a blowout preventer stack,
The subsea pod contains the pilot operated control valves and pilot operated regulators required to direct the hydraulic fluids to the various stack functions. Pods may be eitheT of the retrievable or nonretrievable type. The advantages of the retrievable type pod greatly outweigh the nonretrievable type, and it is the most commonly accepted by the industry. The retrievable male portion of the pod contains all pod valves, regulators, and the hose bundle junction box. Should a pod valve, regulator, or hose bundle malfunction, it is less costly to retrieve the pod than to retrieve the riser and upper stack assembly.
Retrievable pods are of two different designs. Koomey offers the male portion in the form of a tapered single stab with packer type face seals. Cameron-Payne offers the male portion in the form of multiple pin type stabs looking down from the valve compartment. Seals on these pin stabs are optional: O-ring or chevron packing, Koomey uses a patented subplate mounted (SPM) poppet type pod valve. The valve block is drilled, tapped and ported to contain these valves. Cameron-Payne offers a shear seal type pod valve. These valves are manifolded in a compartment and piped direct to the pin type stabs. Both Koomey and Cameron-Payne manufacture subsea regulators. A readback is strongly recommended downtream from the subsea regulator to insure that the proper pressure is attained.
All subsea control systems being manufactured today have 100% redundant hose bundles and pods for safety.
Shuttle valves are used to isolate the pod not in use. Redundancy ends at the shuttle valve. It is strongly recommended that the shuttle valves be piped directly into the part on the stack function rather than packing them at one location and then running hose to the function.
The stack plumbing should be sized and run carefully to eliminate all flow restrictions.
The electro-hydraulic control system is similar to the hydraulic system, except that an electric signal is sent subsea to a solenoid valve which supplies hydraulic pilot pressure to the subsea control valves. One of the main advantages in the elec-trohydraulic system is the reduction in signal time to almost zero for any water depth. The electro-hydraulic control system costs are higher than the costs of comparable all-hydraulic systems for shallow water application, but the reverse begins to be true for water depths between 1500 and 2000 feet. Another advantage of the electro-hydraulic system is that it has more readback capabilities.
There are now two types of electro-hydraulic control systems offered by all control system manufacturers. One is the multi-wire electro-hydraulic and the other is the multiplex electro-hydraulic. Multi-whe means there is at least one, or perhaps two, wires per solenoid. The multiplex control system uses from six to twelve wires for all the solenoids. This means the signal for each solenoid must be a coded signal for that particular solenoid. The multi-wire electro-hydraulic control system uses more wires but has fewer electronic components, whereas the multiplex control system uses more electronic components on the surface and subsea, but has fewer wires in the cable.
In 1970 when the current electro-hydraulic control systems came out on the floating drilling rigs, the systems were all multi-wire control systems. The reason for going to the multi-wire system was that the industry did not feel it was ready for sophisticated electronics on a drilling rig. All electro-hydraulic systems worked after modifications to the original electro-hydraulic cable. The biggest problem with the electro-hydraulic was the cable; the remainder of the system was highly reliable. The cable's biggest problems were in the "end terminations" and the "limited bend radius" of the cable.
After the electro-hydraulic system proved to be reliable, more commands to the BOP stack and more monitoring of BOP stack functions were requested by the industry. With the request for more capability, a larger cable than before would be required, with an even greater limited bend radius. This resulted in a trend towards a multiplex or coded system, which did not require the number of wires but required more electronics on the surface and subsea. At the time of this writing there are no field proven multiplex systems, but every control company has its own multiplex system. At present there are four multi-wire electro-hydraulic control systems working in the field.
As deeper water depths are attempted from 2000 feet to 10,000 feet, electro-hydraulic controls are the only way for the industry to go. The main reasons for this are: (l) signal time is reduced to almost zero, (2) more commands are needed on the BOP stack, and (3) more monitoring devices are needed on the BOP and riser.
As these deeper depths are attempted, multiplex offers more advantages to the industry than disadvantages. Those interested in deep water application are encouraged to look at multiplex electro-hydraulic control systems, but the straight hydraulic control system is recommended for water depths of 2000 feet and less.
Subsea Production and Diving Operations
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