The underlying principle of the one circulation method is that bottom hole pressure, Pbh is maintained at a level greater than the formation pressure throughout the operation, so that no further influx occurs. This is achieved by adjusting the choke, to keep the standpipe pressure on a planned profile, whilst circulating the required mudweight into the well. A worksheet may be used to carry out the calculations in an orderly fashion and provide the required standpipe pressure profile. While the choke is being adjusted the operator must be able to see the standpipe pressure gauge and the annulus pressure gauge. Good communication between the choke operator and the pump operator is important.

Figure 17 shows the complete standpipe and annulus pressure profiles during the procedure. Notice that the maximum pressure occurs at the end of phase II, just before the influx is expelled through the choke, in the case of a gas kick.

Safety factors are sometimes built into the procedure by:

1. Using extra back pressure (200 psi) on the choke to ensure no further influx occurs. The effect of this is to raise the pressure profiles in Figure 16 by 200 psi.

2. Using a slightly higher mud weight. Due to the uncertainties in reading and      calculating mud densities it is sometimes recommended to increase mud      weight by 0.5 ppg more than the calculated kill weight. This will slightly      increase the value of Pc2, and mean that the shut in drill pipe pressure at the      end of phase I will be negative. Whenever mud weight is increased care should      be taken not to exceed the fracture pressure of the formations in the openhole. (An increase of 0.5 ppg mud weight means an increased hydrostatic pressure of 260 psi at 10000ft). Some so-called safety margins may lead to problems of overkill.

one circulation

Institute of Petroleum Engineering, Heriot-Watt University

The procedure used in this method is to circulate out the influx and circulate in the heavier mud simultaneously. The influx is circulated out by pumping kill mud down the drillstring displacing the influx up the annulus. The kill mud is pumped into the drillstring at a constant pump rate and the pressure on the annulus is controlled on the choke so that the bottomhole pressure does not fall, allowing a further influx to occur.

The advantages of this method are:
1. Since heavy mud will usually enter the annulus before the influx reaches surface the annulus pressure will be kept low. Thus there is less risk of fracturing the formation at the casing shoe.
2. The maximum annulus pressure will only be exerted on the wellhead for a short time
3. It is easier to maintain a constant Pbh by adjusting the choke.

When the kick occurs during drilling, the well can be killed directly since:

1.  The formation fluids can be circulated out
2. The existing mud canbereplaced witha mud withsufficient density to overbalance the formation pressure

If a kick is detected during a trip the drillstring must be stripped to bottom, otherwise the influx cannot be circulated out. Stripping is the process by which pipe is allowed to move through the closed BOPs under its own weight. Snubbing is where the pipe is forced through the BOP mechanically. There are basically two methods of killing the well when the drillstring is at the
bottom of the borehole. These are:
•     The One Circulation Method
•     The Drillers Method

One method of killing a well when there is no drillstring in the hole is the Volumetric Method. The volumetric method uses the expansion of the gas to maintain bottom hole pressure greater than formation pressure. Pressures are adjusted by bleeding off at the choke in small amounts. This is a slow process which maintains constant bottom hole pressure while allowing the gas bubble to migrate to surface under the effects of buoyancy. When the gas reaches surface it is gradually bled off whilst mud is pumped slowly into the well through the kill line. Once the gas is out of the well, heavier mud must be circulated. This can be done with a snubbing unit. This equipment allows a small diameter pipe to be into the hole through the closed BOPs.

Another important parameter which must be calculated is the maximum allowable annular surface pressure (MAASP). The MAASP is the maximum pressure that can be allowed to develop at surface before the fracture pressure of the formation just below the casing shoe is exceeded. Remember that an increase in the annulus pressure at surface will mean that the pressures along the entire wellbore are increasing also. Normally the weakest point in a drilled well is the highest point in the open hole section (i.e. at the previous casing shoe). During the well control operation it is important that the pressure is not allowed to exceed the fracture gradient at this weakest point. The fracture pressure of the formation just below the casing shoe will be available from leak off tests carried out after the casing was set. If no leak-off test was carried out an estimate can be made by taking a percentage of the minimum geostatic gradient for that depth.

If an influx occurs and the well is killed with a kill mud this calculation should be repeated to determine the new MAASP. The MAASP should not exceed 70% of the burst resistance of the casing.

An influx of gas into the wellbore can have a significant effect on the annulus pressure.

Since there is such a large difference in density between the gas and the mud a gas bubble entering the well will be subjected to a large buoyancy effect. The gas bubble will therefore rise up the annulus. As the gas rises it will expand and, if the well is open, displace mud from the annulus. If, however, the well is shut in mud cannot be displaced and so the gas cannot expand. The gas influx will rise, due to buoyancy, but will maintain its high pressure since it cannot expand. As a result of this Pann will increase and higher pressures will be exerted all down the wellbore (note the increase in bottom hole pressure). The situation is as shown in Figure 14. This increase in annulus, and therefore bottom hole, pressure will be reflected in the drillpipe pressure (Pph = bhp – ρmd). This situation can, therefore, be identified by a simultaneous rise in drillpipe and annulus pressure.

It is evident that this situation cannot be allowed to develop as it may lead to the problems mentioned earlier (casing bursting or underground blow-out). From the point at which the well is shut in the drillpipe and annulus pressures should be continuously monitored. If Pann and Pdp continue to rise simultaneously it must be assumed that a high pressure gas bubble is rising in the annulus. In this case, the pressure must be bled off from the annulus by opening the choke. Only small volumes (1/4 – 1/2 bbl) should be bled off at a time. By opening and closing the choke the gas is allowed to expand, and the pressure should gradually fall. The process should be continued until Pdp returns to its original shut in value (again Pdp is being used as a bottom hole pressure gauge). This procedure can be carried out until preparations to kill the well are complete. During this procedure no further influx of fluids will occur, provided Pdp remains above its original value.

gas bubble

Institute of Petroleum Engineering, Heriot-Watt University

When an influx has occurred and has subsequently been shut-in, the pressures on the
drillpipe and the annulus at surface can be used to determine:
•    The formation pore pressure
•     The mudweight required to kill the well
•     The type of influx

In order to determine the formation pressure, the kill mudweight and the type of
influx the distribution of pressures in the system must be clearly understood. When
the well is shut-in the pressure at the top of the drillstring (the drillpipe pressure)
and in the annulus (the annulus pressure) will rise until:

(i)     The drillpipe pressure plus the hydrostatic pressure due to the fluids in the drillpipe is equal to the pressure in the formation and,
(ii)     The annulus pressure plus the hydrostatic pressure due to the fluids in the annulus is equal to the pressure in the formation.

It should be clearly understood however that the drillpipe and annulus pressure
will be different since, when the influx occurs and the well is shut-in, the drillpipe
will contain drilling fluid but the annulus will now contain both drilling fluid and
the fluid (oil, gas or water) which has flowed into the well. Hence the hydrostatic
pressure of the fluids in the drillstring and the annulus will be different. A critical
assumption that is made in these calculations is that the influx travels up the annulus
between the drillstring and the borehole rather than up the inside of the drillstring.
This is considered to be a reasonable assumption since the influx would be expected
to follow the flow of fluids through the system when they enter the wellbore.

It is convenient to analyse the shut-in pressures by comparing the situation with
that in a U-tube (Figure 9). One arm of the U-tube represents the inner bore of the
drillstring, while the other represents the annulus. A change of pressure in one arm
will affect the pressure in the other arm so as to restore equilibrium.

well bore pressure

The following procedures should be undertaken when a kick is detected. This procedure refers to fixed drilling rigs (land rigs, jack ups, rigs on fixed platforms). Special procedures for floating rigs will be given later.

For a kick detected while drilling:
1. Raise kelly above the rotary table until a tool joint appears
2. Stop the mud pumps
3. Close the annular preventer
4. Read shut in drill pipe pressure, annulus pressure and pit gain.

Before closing in the annular preventer the choke line must be opened to prevent surging effects on the openhole formations (water hammer). The choke is then slowly closed when the annular preventer is closed. Once the well is closed in it may take some time for the drill pipe pressure to stabilise, depending on formation permeability.

When a kick is detected while tripping:
(i)     Set the top tool joint on slips
(ii)     Install a safety valve (open) on top of the string
(iii)    Close the safety valve and the annular preventer
(iv)     Make up the kelly
(v)    Open the safety valve
(vi)    Read the shut in pressures and the pit gain (increase in volume of mud in the mud pits).

The time taken from detecting the kick to shutting in the well should be about 2 minutes. Regular kick drills should be carried out to improve the rig crew’s reaction time.

BOP Stack

Institute of Petroleum Engineering, Heriot-Watt University
 

Since most blow-outs actually occur during trips, extra care must be taken during tripping. Before tripping out of the hole the following precautions are recommended:

(i)     Circulate bottoms up to ensure that no influx has entered the wellbore
(ii)     Make a flowcheck
(iii)    Displace a heavy slug of mud down the drillstring. This is to prevent the string being pulled wet (i.e. mud still in the pipe when the connections are broken). The loss of this mud complicates the calculation of drillstring displacement.

It is important to check that an influx is not taking place and that the well is dead before pulling out of the hole since the well control operations become more complicated if a kick occurs during a trip. When the bit is off bottom it is not possible to circulate mud all the way to the bottom of the well. If this happens the pipe must be run back to bottom with the BOP’s closed. This procedure is known as stripping-in and will be discussed later.

As the pipe is tripped out of the hole the volume of mud added to the well, from the trip tank, should be monitored closely. To check for swabbing it is recommended that the drillbit is only pulled back to the previous casing shoe and then run back to bottom before pulling out of hole completely. This is known as a short trip. Early detection of swabbing or incomplete filling of the hole is very important.

 

Whilst drilling, the drilling crew will be watching for the indicators described above. If one of the indicators are seen then an operation known as a flow check is carried out to confirm whether an influx is taking place or not. The procedure for conducting a flowcheck is as follows:

(i)      Pick up the Kelly until a tool joint appears above the rotary table
(ii)     Shut down the mud pumps
(iii) Set the slips to support the drillstring
(iv)     Observe flowline and check for flow from the annulus
(v)      If the well is flowing, close the BOP. If the well is not flowing resume drilling, checking for further indications of a kick.