Accumulator Drawdown Test

¡verter line

Close bag ''Open valves Open bag ^' Close valves fnr" " --- Preventer valve

Diverter line

Fig. 16-68 Typical diverter stack (Courtesy PennWell Publishing)

The lines should be as large as possible with a suggested minimum ID of 6 in. Angles and bends should be minimized in the diveiter lines to avoid unnecessary restrictions. The preventer may be a low-pressure sphcrical preventer or some type of diverter bag used to direct the flow into the lines.

Choke Manifold. The choke manifold is an arrangement of valves, lines, and chokes designed to control the flow of mud and kick fluids from the annulus during the killing process. Some of the conditions that the manifold may be called upon to work under are a variety of fluids such as mud, oil, water, or gas, high pressures, upstream flow rates, downstream velocities, and obstructions in the produced fluids such as sand, shale, 01 pipe protector rubbers. The manifold should control pressures by using one of several chokes. It should divert flow to one of several areas including a burning pit, the reserve pit, a mud pit, or overboard a drilling vessel when applicable. The choke should have pressure ratings at least equal to the preventer stack and should meet all pressure testing specifications imposed on the preventers. It should be suitably anchored to prevent movement during the killing operation. The choke should feature easy access to every manifold component, with all lines constructed as straight as possible. All lines and valves should have the same consistent inner diameter to minimize turbulent erosion at diameter changes.

Manifold Design. The principle applied to blowout preventer stack design also will be applied in designing the choke manifold. The proper procedure is to ensure that a backup system is available should the primary tool fail. Also, it is a good practice initially to use the manifold necessary to reach the total depth to avoid installing a different manifold with each casing setting depth.

Fig. 16-69 illustrates a choke manifold used in many drilling operations. Note that this design meets all of the requirements for choke manifolds. Buffer chambers are used at the downstream connections to act as hydraulic cushions and to minimize erosion. A tap may be provided to allow for manifold pres-surization to prevent pressure surges when opening the valves near the stack. Two h and-adjustable chokes may be provided due to their high stem and seat erosion rates and due to their tendency to pack off with cuttings. A current, and more appropriate, practice is to use two remote hydraulic adjustable chokes and a single manual chokc. A direct line from the preventer stack to the burning pit for gas is provided should it become necessary to divert the well temporarily. Note that this design does not constitute a true diverter system.

Accumulator Systems. The accumulator system provides closing energy to all members of the BOP stack. This is usually done with a hydraulic system designed and built to provide closing power to the equipment in 5 sec or less and to maintain the required pressures as desired.

The working of the accumulator is a function of hydraulic oil stored under a compressed inert gas, usually nitrogen. As hydraulic oil is forced into a vessel (bottle) by a small-volume-output, high-pressure pump, the nitrogen is compressed and stores potential energy. When the preventers are actuated, the pressured oil is released and opens or closes the preventers. Hydraulic pumps replenish the accumulator with the same amount of fluid as was used to work the preventers. Fig. 16-70 shows an accumulator, which includes the bottle, pumps, controls, and a hydraulic oil tank.

A préchargé pressure is generally applied to the nitrogen to ensure that all the oil can be forced from the bottle when necessary. The préchargés may range from 500-3,000 psi, with the desired precharged pressure dependent on the service conditions during fluid drawdown. Fig, 16-71 is a drawdown curve for three different préchargé pressures and is used to size preventers with respect to accumulator pressure.

The accumulator must be equipped with several pressure-regulating devices so that different stages of pressure can be maintained with the unit. For example, an accumulator pressure of 3.000 psi is recommended in most eases, but the pressure must be regulated to provide 1,500 psi to the sphericals. Accordingly, other stack members may require different operating pressures. A bypass valve is built into the accumulator for use should it become necessary to use the full pressure to close the preventers in emergency conditions.

Another purpose of this hydraulic system is to maintain constant pressure when stripping pipe through the spherical preventer. As tool joints are stripped through the packing element, the accumulator must allow the excess fluid pressure to move from the annular closing chamber. Where the tool joint passes through

Cameron Iron Works
Fig. 16-69 Typical choke manifold design (Courtesy Cameron Iron Works)
Bop Accumulator Drawdown TestAccumulator Unit Drilling Oil Well
Fig. 16-71 Drawdown curves (Courtesy PennWeli Publishing Co.)

the packing element, the accumulator must force additional iluid back into the spherical preventer to maintain a constant pressure.

Design Procedures. The accumulator should be able to close a minimum of three metnbers of the stack, one of which must be the annular preventer, without having to recharge the accumulator. Many operators require that the accumulator close all members of the stack without recharging. A total of 50% of the original fluid should remain as a reserve after accumulator activation. A minimum final pressure of 1,200 psi is required to ensure the preventers remain closed.

Degassers, The degassers remove air or gas entrained in the mud system to ensure that the proper density mud is recirculated clown the drillpipe. If the gas or air is not removed, the mud weight measured in the pits may be misleading. This will result in the addition of unnecessary amounts of weight material, thereby giving true mud densities downhole that are more than desired. The most common types of degassers are the vacuum and atmospheric types.

The atmospheric separator, or poor-boy degasser as it is often called, is probably the first line of defense on gas removal in most well control operations. A typical unit schematic is shown in Fig. 16-72, The mud and gas enter the top and are allowed to separate through gravity segregation. The unit is useful because of its ease of operation, maintenance, and construction as well as its ability to remove large volumes of gas. Note that the vent line should be long enough to ensure that gas is not vented near the rig floor, i.e., to the top of the derrick.

Problems associated with this unit are degasser body construction that is not sufficiently large, small-diameter vent lines, or gas flow rates through the degasser that perhaps should be flared at gas-to-surface conditions.

The vacuum degasser {Fig. 16-72) consists of a vacuum-generating tank that, in effect, pulls the gas out of the mud due to gravity segregation. Some degassers have a small pump to create a vacuum, while others {similar to the one shown) use the centrifugal mixing pumps to create a vacuum. It is important to note that most degassers, regardless of type, have a minimum required mud throughput for efficient operation.

There are several other types of degassers available, such as the centrifugal spray type or the pressurized separator. The centrifugal spray type has Ihe desirable characteristic of easy installation and operation. The pressurized separator is perhaps the best degassing tool for severe gas kick control and has a good service record under these conditions. The unit is somewhat complex in operation and maintenance.

Mud Monitoring Equipment. Monitoring the mud system is an important task that must be fulfilled to maintain well control. The mud gives warning signs and indications of kicks that can be used to reduce the severity of the kicks by early detection and resultant shutin before a large inllux is taken. If this system

Poor Boy Horizontal Degasser
Fig. 16-72 Atmospheric degasser (Courtesy N.L. iîaroid)

is properly monitored, other drilling problems such as lost circulation can be minimized.

Flow Detectors. When a kick occurs, one of the primary warning signs will be an increased llow rate leaving the well. A flow monitor gauges the rate of mud flow and, should any abnormal changes occur, the monitor records the changes and sounds an alarm, notifying the crew. The flow detector also warns of kicks and lost circulation should the flow rate decrease.

Swaco Vacuum Degasser
Fig, 16-73 Vacuum degasser (Courtesy Swaco, Inc.)

The most common type of flow detector is a flapper placed in the flow line. A tension spring is attached to the flapper and adjusted to the warning device. If the Slow rate increases, the flapper changes position and creates a new tension on the spring, which is recorded by the monitor. The reverse is true when lost circulation occurs.

Pump stroke counting is a viable procedure for filling the hole as the pipe is pulled. The flow monitor can be synchronized with the mud pumps to signal that mud is flowing out of the bell nipple and then can automatically shut down the pumps and record the number of pump strokes required to (ill the hole.

Pit Monitors. Another key warning sign of a kick is an increased pit volume. As the formation fluid enters the borehole, an equal volume of mud is displaced into the pits, which can be recorded by the proper type of detection equipment.

The basis of most pit monitoring systems is a float level m the mud pit attached to a calibrated recorder. In many operations, especially floating drilling, the recorder should have a pit volume totalizing (PVT) feature that will compensate for pit level changes due to ship heave and roll.

Gas Detectors, Several gas detectors are available that function on different principles. However, they all generally report the gas content as units of gas in the mud stream. (It is interesting to note that the exact value of one unit of gas is vague.) When a certain amount of gas has been sensed, an alarm will sound or a light will signal the crew. The disadvantages of gas detectors are maintenance problems, the general inability to function in large concentrations of gas, and a misleading nature in kick detection.

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  • Prima
    What is the minimum ID for a diverter line according to MMS?
    9 years ago
  • maci
    2 years ago
  • payton
    What is the accumulator drawdown test?
    2 years ago
  • haben
    How often is BOP accumulator drawdown test required?
    12 months ago
  • osman
    What is a bop drawdown tgest?
    9 months ago
  • marcelina
    How to tst the accumulator unit in a BOP stack?
    5 months ago
  • edoardo
    How to perform a bop accumulator drawdown test?
    5 months ago
  • Aman
    How to conduct draw down test?
    2 months ago

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