Choke Manifold Complete Guide (Part...
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Choke Manifold Complete Guide (Parts, Function & IADC Recommendations)The choke manifold is an arrangement of valves, fittings, lines, and chokes that provide several flow routes to control the flow of mud, gas, and oil from the annulus during a kick ( Kick warning signs – Causes of kick in drilling). Here you shall learn choke manifold parts, function & IADC recommendations in drilling.
When a kick occurs, control of the well is maintained by shutting in the well (i.e. secondary well control) ( hard shut in well procedure – Soft shut in well procedure). It is then necessary to regain primary well control as soon as possible.
Check Also: Choke Manifold Testing & Acceptance Procedures
If the shut-in pressure gets too high before primary well control can be achieved, there is a possibility that a complete blow-out will occur. To prevent this, chokes are used to bleed of drill fluid to maintain the pressure below the MAASP, while heavier mud is being pumped into the hole to replace the lighter mud to regain primary well control.
It is important not to bleed of more drill fluid than is necessary, as this allows the lighter fluid mixed with gas to further unbalance hydrostatic pressures.
A high-pressure choke low line leads to the choke manifold, the design of which includes:
Note: Chokes are used to release fluid at a controlled rate to limit the pressure on the casing ( casing design calculations) and allow the mud in the hole to be replaced with heavier mud.
If the hydrostatic head of the drilling fluid is insufficient to control subsurface pressure, formation fluids will flow into the well. To maintain well control, back pressure is applied by routing the returns through adjustable chokes until the well flow condition is corrected. The chokes are connected to the blowout preventer stack through an arrangement of valves, fittings, and lines which provide alternative flow routes or permit the flow to be halted entirely. This equipment assemblage is designated the “choke manifold.”
A choke manifold is an assembly of valves, through which the return flow from the well is routed when the blowout preventers are closed, with the purpose of applying calculated backpressure. Choke manifolds may be assembled in a variety of layouts but they will always include at least two adjustable chokes. In some cases, this may be one manual choke and one remote-controlled choke as shown in Figure 2.2. The manifold provides alternative flow paths for the fluid so that if necessary chokes can be changed and valves repaired without stopping the flow. All the high-pressure parts of the manifold should have the same working pressure rating as the BOP stack.
The Main Components Of the Choke Manifold are:
The choke is normally an adjustable orifice installed in the return line. It is used to restrict the flow area so that the pressure drop of the returns through this line can be regulated while a kick is circulated out. Three types of chokes may be encountered in choke manifolds:
Figure 2. 7 shows a typical needle valve type manual adjustable choke. The stem and seat area are of tungsten carbide to make them more wear resistant; it must be understood that a choke is not meant to be used as a valve. The tool is designed to create a flow restriction and not to provide a high-pressure seal. Washed-out sealing areas are also common. Therefore the choke must be used for initial closing in only and should immediately be backed up by closing the upstream valve. This type of choke should not be left “closed” for long periods of time. Temperature expansion of the needle can damage the seat and the needle may “freeze” in the seat.
Manual Adjustable ChokeInstead of using an adjustable spindle valve, the seat can be replaced by different sizes of “beans”. Such chokes are used only if the well returns will have to be produced at a constant rate over a considerable period of time, such as is common during production tests. Fixed chokes are sometimes referred to as positive chokes.
The choke body in such a set-up is provided with a cap instead of a needle assembly
Remote-controlled chokes are operated from a panel, usually on the rig floor (see Figure 2.8). This operating panel should include:
There are different remote-controlled chokes, some of which have specific operating characteristics that may affect the well killing operation. It is therefore important to check the details of the unit installed.
remote-controlled chokesOwing to area and contractor specific requirements, it is not feasible to specify a standard layout, but the following minimum requirements should be adhered to:
Note: Choke manifold design should consider such factors as the anticipated formation and surface pressures, method of well control to be employed, surrounding environment, corrosivity, volume, toxicity, and abrasiveness of fluids.
Of the two choke line valves on or adjacent to the stack, the inner manual valve is kept open, and the second (the remotely controlled hydraulically acti vated gate valve) kept closed during drilling. All other valves and chokes in the line to the mud/gas separator, are kept open with the exception of the valve immediately upstream of each of the chokes and the second valve in the bypass line after the cross (the centre fl.ow line, the one without a choke)
Wherever two valves are fitted it is standard practice that the second valve is the one operated and the first one used as backup, in case the second one fails.
When two manual chokes are installed either one can be used. When a manual choke and a remote-controlled choke are installed, the remote-controlled choke is the one normally used, keeping the manual choke as a standby choke. Before taking over the shift the driller should make sure that all the valves on the· choke manifold are set as described above.
Recommended practices for planning and installation of choke manifolds for surface installations include:
The choke manifold should be tested in two-stage, at a low-pressure test of 200 to 300 psi and then at maximum test pressure. Both pressures holding periods should not be less than three minutes. A 5 or 10 minute holding period is common.
Choke manifold should be tested to full working pressure upon:
Routine ram and choke manifold maximum test pressure should be limited to the lesser of:
Refinements or modifications such as additional hydraulic valves and choke runs, wear nipples downstream of chokes, redundant pressure gauges, and/or manifolding of vent lines will be dictated by the conditions anticipated for a particular well and the degree of protection desired. The guidelines discussed and illustrated represent typical industry practices.
For economic reasons, it may be desirable at the beginning of a drilling operation to install a manifold with a pressure rating equivalent to that of the highest pressure rated system which will be used on that well. This will preclude the necessity of always matching manifolds with BOP stack ratings, minimizing time lost changing choke manifolds, and reduce the number of manifolds held in inventory.
Screwed connections are optional for only the 2M manifold; all others shall be welded or flanged. IADC recommended configurations are shown in Figures 1, 2, and 3, for 2M and 3M, 5M, 10M, and 15M manifolds respectively.