The placement of the elements of a BOP stack (both rams and circulation lines) involves a degree of judgement, and eventually compromise. However, the placement of the rams and the choke and kill line configuration should be carefully considered if optimum flexibility is to be maintained. Although there is no single optimum stack configuration, consider the configuration of the rams and choke and kill lines in the BOP stack shown in Figure 27:

1. There is a choke and kill line below each pipe ram to allow well killing with either ram.
2. Either set of pipe rams can be used to kill the well in a normal kill operation (Figure 28).
3. If there is a failure in the surface pumping equipment at the drillfloor the string can be hung off the lower pipe rams, the blind rams closed and a kill operation can be conducted through the kill line (Figure 29).
4. If the hydril fails the pipe can be stripped into the well using the pipe rams. In this operation the pipe is run in hole through the pipe rams. With the pressure on the pipe rams being sufficient to contain the pressure in the well. When a tooljoint reaches the upper pipe ram the upper ram is opened and the tool joint allowed to pass. The upper pipe ram is then closed and the lower opened to allow the tool joint to pass (Figure 30). This operation is known as ram to ram stripping.

This arrangement is shown as an illustration of considerations and compromise and should not be considered as a ‘standard’.

BOP stack

The placement of the choke and kill lines is also a very important consideration when designing the stackup. Ideally these lines are never made up below the bottom ram. However, compromise may be necessary.

normal kill operation

The following general observations can be made about the arrangement detailed in Figure 27:

1. No drilling spools are used. This minimises the number of connections and chances of flange leaks.
2. The double ram is placed on top of a single ram unit. This will probably provide sufficient room so that the pipe may be sheared and the tool joint still be held in the lower pipe ram.
3. Check valves are located in each of the kill wing valve assemblies. This will stop flow if the kill line ruptures under high pressure killing operations.
4. Inboard valves adjacent to the BOP stack on all flowlines are manually operated ‘master’ valves to be used only for emergency. Outboard valves should be used for normal killing operations. Hydraulic operators are generally Vent installed on the primary (lines 1 and 2) choke and kill flowline outboard valves. This allows remote control during  To test manifold  killing operations.
5. No choke or kill flowlines are connected to the casing-head outlets, but valves and unions are installed for emergency use only. It is not good practise to flow into or out of a casing head outlet. If this connection is ruptured or cutout, there is no control. Primary and secondary flowlines should all be connected to heavy duty BOP outlets or spools.

kill line

 

There are a variety of tools used to prevent formation fluids rising up inside the drillpipe. Among these are float valves, safety valves, check valves and the kelly cock. A float valve installed in the drillstring will prevent upward flow, but allow normal circulation to continue. It is more often used to reduce backflow during connections. One disadvantage of using a float valve is that drill pipe pressure cannot be read at surface. A manual safety valve should be kept on the rig floor at all times. It should be a full opening ball-type valve so there is no restriction to flow. This valve is installed onto the top of the drillstring if a kick occurs during a trip.

The opening and closing of the BOP’s is controlled from the rig floor. The control panel is connected to an accumulator system which supplies the energy required to operate all the elements of the BOP stack. The accumulator consists of cylinders which store hydraulic oil at high pressure under a compressed inert gas (nitrogen). When the BOPs have to be closed the hydraulic oil is released (the system is designed to operate in less than 5 seconds). Hydraulic pumps replenish the accumulator with the same amount of fluid used to operate the preventers (Figure 26).

BOP accumulator

The accumulator must be equipped with pressure regulators since different BOP elements require different closing pressures (e.g. annulus preventers require 1500 psi while some pipe rams may require 3000 psi). Another function of the accumulator system is to maintain constant pressure while the pipe is being stripped through the BOPs.

A choke is simply a device which applies some resistance to flow. The resistance creates a back pressure which is used to control bottomhole pressure during a well killing operation. Both fixed chokes and adjustable chokes are available (Figure 25).   The choke can be operated hydraulically or manually if necessary.

choke device

The choke manifold is an arrangement of valves, pipelines and chokes designed to control the flow from the annulus of the well during a well killing operation. It must be capable of:

•     Controlling pressures by using manually operated chokes or chokes operated from a remote location.
•     Diverting flow to a burning pit, flare or mud pits.
•     Having enough back up lines should any part of the manifold fail.
•     A working pressure equal to the BOP stack.

Since, during a gas kick, excessive vibration may occur it must be well secured.

 

When circulating out a kick the heavy fluid is pumped down the drillstring, up the annulus and out to surface. Since the well is closed in at the annular preventer the wellbore fluids leave the annulus through the side outlet below the BOP rams or the drilling spool outlets and pass into a high pressure line known as the choke line. The choke line carries the mud and influx from the BOP stack to the choke manifold. The kill line is a high pressure pipeline between the side outlet, opposite the choke line outlet, on the BOP stack and the mud pumps and provides a means of pumping fluids downhole when the normal method of circulating down the drillstring is not possible.

 

A drilling spool is a connector which allows choke and kill lines to be attached to the BOP stack. The spool must have a bore at least equal to the maximum bore of the uppermost casing spool. The spool must also be capable of withstanding the same pressures as the rest of the BOP stack (Figure 23). These days outlets for connection of choke and kill lines have been added to the BOP ram body and drilling spools are less frequently used. These outlets save space and reduce the number of connections and therefore potential leak paths.

flanged drilling spool

 

Ram type preventers (Figure 22) derive their name from the twin ram elements which make up their closing mechanism. Three types of ram preventers are available:

1. Blind rams – which completely close off the wellbore when there is no pipe in the hole.
2. Pipe rams – which seal off around a specific size of pipe thus sealing of the annulus. In 1980 variable rams were made available by manufacturers. These rams will close and seal on a range of drillpipe sizes.
3. Shear rams which are the same as blind rams except that they can cut through drillpipe for emergency shut-in but should only be used as a last resort. A set of pipe rams may be installed below the shear rams to support the severed drillstring.

ram element

The sealing elements are again constructed in a high tensile strength rubber and are designed to withstand very high pressures. The elements shown in Figure 21 are easily replaced and the overall construction is shown in Figure 22. Pipe ram elements must be changed to fit around the particular size of pipe in the hole. To reduce the size of a BOP stack two rams can be fitted inside a single body. The weight of the drillstring can be suspended from the closed pipe rams if necessary.

ram preventer

The main component of the annular BOP (Figure 19) is a high tensile strength, circular rubber packing unit. The rubber is moulded around a series of metal ribs. The packing unit can be compressed inwards against drillpipe by a piston, operated by hydraulic power.

annular type bops

The advantage of such a well control device is that the packing element will close off around any size or shape of pipe. An annular preventer will also allow pipe to be stripped in (run into the well whilst containing annulus pressure) and out and rotated, although its service life is much reduced by these operations. The rubber packing element should be frequently inspected for wear and is easily replaced.

The annular preventer provides an effective pressure seal (2000 or 5000 psi) and is usually the first BOP to be used when closing in a well (Figure 19). The closing mechanism is described in Figure 20.

annular type bops closing mechanism

The Drillers Method for killing a well is an alternative to the One Circulation Method. In this method the influx is first circulated out of the well with the original mud. The heavyweight kill mud is then circulated into the well in a second stage of the operation. As with the one circulation method, the well will be closed in and the circulation pressures in the system are controlled by manipulation of the choke on the annulus. This procedure can also be divided conveniently into 4 stages:

Phase I (circulation of influx to surface)

During this stage the well is circulated at a constant rate, with the original mud. Since the original mudweight is being circulated the standpipe pressure will equal Pdp + Pc1 throughout this phase of the operation. If the influx is gas then Pann will increase significantly (Figure 18). If the influx is not gas the annulus pressure will remain fairly static.

driller method

Phase II (discharging the influx)

As the influx is discharged the choke will be progressively opened. When all the influx has been circulated out Pann should reduce until it is equal to the original shut in drillpipe pressure Pdp so that Pann + ρmd = Pf

Phase III (filling the drillstring with heavy mud)

At the beginning of the second circulation, the stand pipe pressure will still be Pdp + Pc1, but will be steadily reduced by adjusting the choke so that by the end of phase III the standpipe pressure = Pc2 (as before).

Phase IV (filling the annulus with heavy mud)

In this phase Pann will still be equal to the original Pdp, but as the heavy mud enters the annulus Pann will reduce. By the time the heavy mud reaches surface Pann = 0 and the choke will be fully opened. The pressure profiles for the drillers method are shown in Figure 17.

one circulation