In this method the well is killed in one circulation. The kick is circulated out whilst mud of sufficient density to (over) balance the pore pressure is circulated in.

Mud with a density sufficient to balance the pore pressure is circulated at a constant rate. At the same time, to prevent any further influx, the choke is adjusted to maintain a constant bottom hole pressure slightly in excess of the pore pressure. The balanced mud method enables the well to be killed in one circulation. Adequate stocks of dry barytes and spare weighted or base mud should always be available to allow implementation of this method.

1 Advantages

The balanced mud method has the following advantages:

·the pressure in the annulus will usually be lower than with other methods thus, in most cases the best condition for avoiding formation breakdown is also achieved;
·the hole and wellhead equipment are subjected to high pressures for the shortest possible length of time;
·the well can be opened sooner and the drillstring reciprocated, thus reducing the possibility of getting stuck.

2 Procedures

The following procedures concerning the balanced mud method are discussed below:

• Closing in the well.
• Pressure and pit volume readings.
• Calculating the gradient of the kill mud.
• Determining the amount of overbalance.
• Determining the amount of weighting material required.
• Determining the pumping speed (killing pump rate).
• Determining the circulating pressures.
• Determining the surface to bit travel time (or volume).
• Determining the time (or volume) for the influx top to reach the casing shoe.
• Determining the shoe to choke time.
• Determining the total pumping time.
• Determining the height and gradient of the influx.
• Construction and use of the standpipe kill graph.
• Maintaining a constant bottom hole pressure.
• Choke adjustment.
• Determining the pressure at the top of a gas influx at any point in the annulus.
• Kick control with a subsea BOP stack.
• Procedure after the well has been brought under control.

3 Closing in the well

The well should be closed in immediately after detecting a kick condition.

There are two possible ways to close in the well:

·soft shut-in procedure;
·hard shut-in procedure.

The soft shut-in method is applied with a view to avoid shockloads on weak formations (resulting from the inertia of a moving fluid column) which could result in induced losses in a well control situation. The procedure is to open the choke line first and then close the annular or pipe rams after which the choke is closed slowly.

The hard shut-in method is applied with a view to reduce the influx volume as much as possible in order to reduce well bore pressures to a minimum during well killing operations. The procedure is to close the ram or annular preventer without opening the choke line, or the hydraulic choke valve is closed immediately after the BOP is closed.

In general, it is recommended practice to close-in the well with the annular preventer instead of the ram type preventer, because the annular preventer can be closed around the string regardless of the position of DC's, tool joints, subs, or kelly. It will also minimise shockloading to the wellbore due to the slow closing action of the annular preventer. Pipe rams may be closed first instead of the annular preventer when the detrimental effects of having a larger influx volume entering the borehole is considered worse than the risk of taking higher shockloads. The pipe rams should only be closed if it is certain that the rams will close around the proper pipe OD.

Whether to use the soft or the hard shut-in procedure when closing in a well depends very much on the circumstances under which the kick is experienced. No rigid rules for one way or the other apply.

The following criteria should be considered when determining the well closing-in procedure to be followed, bearing in mind the objectives of both methods:

·severity of the kick (flowrate/influx volume);
·casing shoe depth/strength;
·margin of MAASP;
·strength/depth of weakest formation;
·rig type.

Although the soft shut-in procedure is in general the preferred method, the hard shut-in method may in a number of cases be a better choice, depending on above criteria.

The equipment and chokeline configuration must always allow the soft shut-in procedure to be used, should this be the indicated option for closing-in the well.

Detailed closing-in well procedures differ for each of the following installations:

·land rigs and offshore bottom-supported units;
·offshore floating units (with drillstring motion compensator operational);
·offshore floating units (with drillstring motion compensator non-operational).

The procedure (soft shut-in policy) in each case is as follows:

3.1 Land rigs and offshore bottom-supported units

·With the pump ON, raise the kelly or top drive so that:

-(a) the lower kelly cock is above the rotary table;
-(b) no tool joint or other upset is opposite any of the BOP stack rams or inside the BOP stack.

·Stop the pump.

·Open the hydraulically operated choke valve. (The rest of the choke line is always open under normal conditions).

·Close the annular preventer.

·Close in the well using the adjustable choke at the BPM.

A choke valve is for regulating pressure, not for isolating pressure. Therefore, immediately after the choke is CLOSED the gate valve upstream of the choke must be CLOSED to ensure that the well pressure is effectively closed in.

·Close the upper pipe rams (optional).

·Observe and record the closed-in drillpipe pressure (Pdp) and the closed-in annulus pressure (Pa).

·Kill the well by the balanced mud method.

If pressures are very high, then use a circulating head and possibly the cement unit, or both.

3.2 Offshore floating units (with drillstring motion compensator operational)

·With the pump ON, unlock rotary bushing and raise the kelly or top drive to the pre-determined position for landing the string on the rams (with the lower kelly cock above the rotary table, allowing for tidal condition).

·Stop the pump.

·Open the outer fail-safe valve of the choke line (the rest of the choke line is always open under normal conditions).

·Close the upper annular preventer.

·Close in the well on the adjustable choke at the choke manifold.

·Close the valve upstream of the adjustable choke.

·Close the uppermost pipe rams (not the variable bore rams).

·Land the string on the rams, set compensator to mid-stroke position and close locks on the rams (wedge locks).

·Observe closed-in drillpipe pressure (Pdp) and closed-in annulus pressure (Pa).

·Kill the well by the balanced mud method.

The use of a circulating head is mandatory for killing a high pressure well or when using circulating pressures of over 27,600 kPa (4000 psi). Follow the same closing in procedure as is described for offshore floating units with drillstring motion compensator non-operational. The circulating head assembly may be supported by the motion compensator, constant tension winches, or tensioners.

3.3 Offshore floating units (with drillstring motion compensator non-operational)

·With the pump ON, raise the kelly or top drive to the pre-determined position for landing the string on the rams (the lower kelly cock above the rotary table, allowing for tidal condition).

·Stop the pump.

·Open the outer fail-safe valve of the choke line (the rest of the choke line is always open under normal conditions).

·Close the upper annular preventer.

·Close in the well on the adjustable choke at the choke manifold.

·Close the valve upstream of the adjustable choke.

·Set the string in the slips.

·Close the lower kelly cock, bleed off pressure in the kelly or top drive.

·Disconnect the kelly or top drive above the lower kelly cock.

·Install the circulating head on one drillpipe single.

·Attach the supporting system to the circulating head assembly (using constant tension winches, or tensioners).

·Close the uppermost pipe rams (not the variable bore rams).

·Pick up the string, remove the slips and land the string on the pipe rams with the circulating head assembly supported from the elevators and close the wedge locks.

·Pressure test the lines/hoses and connections to the circulating head and standpipe manifold to the pressure rating of the manifold.

·Remove the elevators (depending on heave).

·Pressure up the lines to the lower kelly cock to Pdp and open the lower kelly cock.

·Observe closed-in drillpipe pressure (Pdp) and closed in annulus pressure (Pa).

·Kill the well by the balanced mud method.

3.4 Moving the string whilst killing the well

In some cases it may be considered appropriate to keep the string moving through the annular preventer during well control operations in order to prevent stuck pipe. This practice is optional and depends entirely on the circumstances under which the kick is experienced. Moving the string through the annular preventer may only be done if well control is not jeopardised.

Other criteria are:

·the BOP stack should have more than one properly functioning/sealing ram type preventer;

·blind/shear rams are installed;

·there is no danger of stripping the tool joint through the annular preventer (offshore floating units).

When killing a well, first priority is to safely execute the well control operation. Possible hole problems have a lower priority and may be dealt with after the well is killed.

3.5 Importance of landing the string on the underwater BOP stack in floating drilling operations

Shop and field tests have established that plain pipe can be reciprocated through a closed annular preventer for a reasonable time before significant wear of the packing element occurs. However, a reciprocating tool joint may quickly cause failure of the packing element.

Therefore, during the close-in procedure following a well kick, relative movement between the drillstring and the seabed should be eliminated as soon as possible by landing the string on the uppermost solid pipe rams to minimise BOP wear.

3.6 Well control with a Top Drive System (TDS)

When a TDS is used in combination with stands, it should be possible to disconnect the string at rotary level to be able to carry out jobs which require string entry near the rotary table (e.g. installation of a lubricator, circulating head, etc.). For that purpose an NRV or drop in sub (DIS) should be used in the string to allow disconnection of the string below the kelly cock of the top drive. NRV's are usually employed in top hole drilling operations only. A reliable NRV, suitable for deep drilling operations, is not available on the market yet, hence a DIS is preferred for this type of operation.

When a TDS is being used on a floater, it should always be possible to pull back the string sufficiently high to be able to hang-off the string in the subsea BOP stack.

4 Pressure and pit volume readings

After the well is closed-in, and whilst making calculations on how to proceed in controlling the well, the following should be carried out:

·Start taking readings of the closed-in annulus pressure (Pa) and closed-in drillpipe pressure (Pdp) immediately until they are stabilised. Record pressures on graph paper. If a drillpipe float valve is installed in the string, pump very slowly occasionally and read the pressure required to open the float (employing a float valve with a small wear resistant hole to equalise the pressure will avoid this inconvenient procedure).

·Measure the increase in pit level.

·Record all values on the Kick Control Worksheet Section 6.8

·Watch the behaviour of the well carefully. The closed-in drillpipe pressure is always a reliable measure for the bottom hole pressure. If both drillpipe pressure and annulus pressure rise steadily before starting circulating, gas migration is indicated and the annulus pressure will have to be continuously bled off to maintain the original drillpipe pressure.

The following procedure can be used to check for trapped pressures:

·Determine the hydrostatic pressure loss per unit volume bled off in the worst case situation (e.g. influx opposite the smallest annular space: OH/DC capacity).

·Bleed off a small volume of mud on the annulus/choke side and allow a small pressure decrease only (e.g. 350 kPa and/or 50 ltr max.). Use the trip tank to monitor return volumes.

·Check that the hydrostatic pressure loss per unit volume bled off corresponds with the hydrostatic pressure loss shown on the drillpipe pressure gauge.

·When the pressure ceases to drop on the drillpipe side and the pressure on the annulus rises to a higher pressure after the choke is once more closed, the bottom hole pressure equals the formation pore pressure.

5 Calculating the gradient of the kill mud

The mud gradient required for controlling a kicking well can be determined as soon as the closed-in drillpipe pressure has stabilised. The information required will be on the Kick Control Worksheet.

6 Determining the amount of overbalance

A small overbalance factor can usually be included in the new mud gradient. If, in addition, bottom hole pressure during well control is maintained by applying additional choke pressure, complete flexibility is retained.

The amount of required overbalance (safety margin) should take into account the fluctuations in mud gradient and choke control operation.

Normally the overbalance on bottom during well control (neglecting friction losses in the annulus), should not exceed 100 psi. 50 psi in the mud weight and 50 psi additional choke pressure is recommended.

If it is decided to apply more than the recommended overbalance during the well control operation, applying additional choke pressure is preferred to increasing the mud gradient, as it allows immediate adjustment if undesirable hole conditions or mud losses develop.

Once the well is under control, the mud gradient should be further increased until it includes a normal trip margin to enable resumption of normal operations. Offshore floating units should add the trip/riser margin to the mud only when circulating through the riser with the rams open.

7 Determining the amount of weighting material required

Amount of weighting material per unit volume of original mud required.

Volume increase after adding weighting material to the mud.

The gradient of the mud pumped into the drillstring should be maintained constant and recorded. The properties of the mud returns should be measured until the well is brought under control. Any contaminated mud returns should be de-gassed, treated, or discarded.

8 Determining the pumping speed (kill pumping rate)

The maximum pumping speed is amongst others limited by the weighting material mixing capacity of the rig.

To obtain a safety margin and reasonable surface pressures, a pump rate lower than the one corresponding to the maximum flowrate is selected.

Killing pump rates are normally restricted to approximately one half the speed used for the drilling operation. Killing speed should be maintained at a level which allows sufficient time for the choke operator to react to changes in choke pressure.

The pump rate should preferably be kept constant throughout the well control period.

9 Determining the circulating pressures

9.1 Initial circulating pressure

The standpipe pressure at the start of the well control operation is expected to be the sum of the closed-in drillpipe pressure (Pdp) and the pump pressure at the selected pump rate (Pc1) found during a previous pump test:

Pst=Pdp+Pc1

If the observed Pst is different than expected when circulation is started at the selected pump rate, with the choke pressure adjusted to the closed-in annulus pressure, then the circulating pressure to be used for all subsequent calculations should be taken as the observed standpipe pressure minus the closed-in drillpipe pressure.

If it is not clear why pressures do not match, the well should be closed in to allow analysis of the situation.

9.2 Circulating pressure with new mud

The circulating pressure when the new mud reaches the bit is derived by adjusting Pc1 for the mud density increase. Pdp is now zero and the relation between Pc1 and Pc2 is as follows:

Pc2=Pc1 * (MW2 / MW1)

10 Determining the surface to bit travel time (or volume)

The time, or volume, needed to pump the new mud to the bit at the selected pump flowrate must be determined. This value can also be expressed as a number of pump strokes.

The surface to bit time is given by:

Surface to bit time = Internal volume of complete\ drillstring / Pump output

The number of pump strokes required can be calculated:

Pump strokes = Selected pump speed x Surface to bit time

11 Determining the shoe to choke time

The time required to displace the drillpipe/casing annulus can be determined as above.

12 Determining the time (or volume) for the influx top to reach the casing shoe

The time, or volume, required for the top of the influx to reach the casing shoe is important (in the case of a gas influx), since the choke pressures can thereafter be allowed to exceed the MAASP without risk or fracturing the formation at the shoe.

The time, or number of pump strokes, needed to displace the top influx from bottom to casing shoe at the selected flowrate is approximated as follows:

Bit to shoe time  = (Bit to shoe volume – Original Influx volume) / Pump output

This can also be expressed as a volume or as a number of pump strokes.

13 Determining the total pumping time

The total pumping time will be the sum of the three values found above, i.e.

Total pumping time = (Surface to bit time) + (Bit to shoe time) + (Shoe to choke time).

14 Determining the height and gradient of the influx

Knowledge of the gradient of an influx is not a necessity for the well control operation. However, the pattern of the expected annular pressures is determined by the type of influx, i.e. liquid or gas.

14.1 Determining the height of the influx

The height of the influx in the annulus when the influx is at bottom (hb) can be calculated from the volume gained before the well was closed-in, and the annular capacity, assuming hole size equals bit size.

The influx height is worked out as follows:

When the initial pit volume gain is less than the annular volume around the DC's:

When the pit volume gain is larger than the annular volume around the DC's, the calculation above is repeated for the remaining volume. The height thus calculated is added to the height of the previous section. If required, the process is repeated for each change in section, until all the influx volume is accounted for.

14.2 Determining the gradient of the influx

Since the difference between the closed-in surface pressures is due to the presence of the influx in the annulus, the gradient of the influx may be calculated by dividing the pressure difference between the closed-in annular and drillpipe pressures by the true vertical height of the influx as determined in the previous section.

The gradient of the influx is given by:

This information is not essential to the well control operation, but will give an indication of the pattern of choke pressures and pit level change that may be expected during the controlling of the kick.

14.3 Using the calculated gradient to find the type of influx

The gradient of gas under bottom hole conditions is usually less than 3.4 kPa/m (0.15 psi/ft), whereas that of formation water is likely to exceed 10.5 kPa/m (0.465 psi/ft). A calculated value within this range could represent a mixture of gas and water or oil.

In practice, a significant difference between Pdp and Pa for a reasonable inflow volume implies gas.

15 Construction and use of the standpipe kill graph

The kill graph of standpipe pressure versus volume pumped or time should be plotted. Standpipe pressures should include the safety margin to be applied when controlling the well at the selected pump speed.

The procedure is as follows:

·Plot the initial standpipe pressure from the Kick Control Worksheet at time (or volume) zero.

·Plot the standpipe pressure when the new mud has reached the bit.

·Connect the points obtained in (1) and (2) with a straight line. This line represents the standpipe pressure to be followed whilst pumping the new mud from the surface to the bit (given the condition that the bottom hole pressure is equal to the pore pressure).

·By adjusting the choke opening every 2-4 minutes, the correct standpipe pressure is obtained whilst the selected pump rate is held.

·Once the drillstring is filled with mud of gradient r2, the standpipe pressure must be held constant at the circulation pressure Pc2 until heavy mud returns to the surface, provided the pump speed is also maintained constant.

Note that if it is decided to apply extra back pressure to increase the bottom hole pressure whilst circulating, e.g. by 350 kPa (50 psi), the standpipe kill graph must be adjusted by the same amount. This extra pressure also acts against all formations in the open hole below the casing shoe.

If gas migrates after the initial build-up period, annulus and drillpipe pressures will rise at the same time. Formation breakdown will eventually occur unless action is taken. Therefore the closed-in drillpipe pressure must not be allowed to rise above the initial value by more than the amount necessary to observe the change.

The gas must then be expanded by bleeding off mud via the choke until the drillpipe pressure returns to a value slightly in excess (700 kPa) of its initial reading. The original drillpipe pressure should be used again at the start of the circulation.

16 Maintaining a constant bottom hole pressure

From the moment that pumping of the weighted mud begins, until the end of the well control process, a constant bottom hole pressure should be maintained. This is achieved by pumping at a constant rate and adjusting the choke opening as required to obtain pre-determined standpipe pressures. These are obtained from the standpipe pressure killing graph on the Kick Control Worksheet. If standpipe pressures drop below the pre-determined values, including safety margins, the bottom hole pressure will be less than the pore pressure and another influx will enter the well. If the standpipe pressure rises above the pre-determined value, pressures throughout the well become higher than necessary. The risk of damage to the formation and consequent mud loss is therefore increased.

To maintain a constant bottom hole pressure until the heavy mud reaches the bit, the initial standpipe pressure must be compensated for the effects of pumping heavier mud into the string. These effects include:

·the reduction of the closed-in drillpipe pressure to zero;

·the greater pressure required because of the increased friction generated by pumping heavier mud at the same rate as the lighter mud was being pumped.

With heavy mud at the bit, there is no further significant change in conditions between bottom hole and the pump. The standpipe pressure must therefore be held constant (indicating constant bottom hole pressure) by choke adjustment as necessary until the heavy mud reaches the surface.

Pumping can then be stopped and the well observed for flow.

The effect of annular friction losses is very small and is therefore not considered. However, in practice, the annular friction loss adds to the bottom hole pressure throughout circulation. Similarly, by "stepping" the pressure in increments during Phase I, bottom hole pressures are also higher than normal. The gradual change from Pc1 to Pc2 also adds pressure to the open hole, because a significant percentage of the pressure rise occurs only when the heavy mud actually passes through the bit nozzles (e.g. at the very end of Phase I).

17 Choke adjustment

The choke opening is adjusted so that, while pumping, the standpipe pressures correspond to the calculated pressures for the volume pumped or time elapsed.

The procedure for choke adjustment is as follows:

·Open the valve upstream of the choke, then open the choke as soon as possible and start pumping mud of the required density at the selected pump speed.

·Adjust the choke opening until the choke pressure equals the value of the closed-in annulus pressure plus the "overbalance back pressure" (Section 4.6)

·Read the standpipe pressure. This should agree with the calculated value plus the "overbalance back pressure" applied. If it does not, consider the former pressure to be correct and modify the standpipe kill graph accordingly.

·Record choke pressures.

The value of the choke pressure depends on the characteristics of the influx gradient, pressure and volume. If the influx is salt water in a uniform annulus, the choke pressure remains constant until the heavy mud reaches the bit. Thereafter the choke pressure gradually decreases as the original lighter mud and the salt water in the annulus are replaced by heavier mud. The pit level remains constant during the well control process except for a small rise due to the volume of weighting material which has been added. With heavy mud at the surface, the final pit level will show a gain representing the volume of weighting material added during weighting up. It is important that there are no restrictions (e.g. partially closed valves) downstream the annular measuring point, because that will result in higher pressures along the hole. A similar effect is seen with the choke line of a subsea BOP stack (Section 4.19)

18 Determining the pressure at the top of a gas influx at any point in the annulus

When a gas kick is being circulated out of the hole, the influx volume will increase due to expansion and consequently results in increased pit levels and higher annulus pressures.

By calculating the expected annular pressures at the top of the influx at specific points along the hole together with the associated influx volumes at these points, comparisons can be made with actual values observed during circulating out the finlux. This information can play an important role in the decision making process during well control operations.

19 Kick control with a subsea BOP stack

Friction losses in subsea BOP stack kill-and choke lines represent a significant proportion of the back pressure developed in the annulus and, if not taken into account, could lead to a fracture of the formation around the casing shoe.

The friction losses occurring at various pump rates must be known Section 2.3.3.2 and the appropriate pressure drop across the choke line for the pump speed used to kill the well should be taken into account during the well control operation.

The well should be killed on the basis:

P_choke_ dynamic = P_choke_static - DeltaP

Where:

P_choke_ dynamic = choke pressure during pumping

P_choke_static = choke pressure when the well is closed-in

DeltaP = pressure drop across the choke line

The well killing procedure is as follows:

·Close in the well, record Pa and Pdp. (Note the difference between kill-and choke line pressures, as the choke line contents has changed during the process of closing-in the well).

·Displace kill-and choke lines to mud (r1).

·Prepare mud (r2).

·Calculate and construct the standpipe graph.

·Check Pchoke and Pdp and if second build-up has taken place bleed-off Pchoke until Pdp has reached the original pressure again.

·Read Pchoke static.

·Start pumping at pre-determined kill speed while opening the choke.

·Adjust the choke until Pchoke dynamic = Pchoke - DP.

·Read corresponding Pstandpipe (Pst).

·Modify the standpipe kill graph using the real Pst and kill the well accordingly.

It is possible to avoid the necessity to take the choke line pressure drop into account during well killing operations by using the kill line as a pressure conduit to monitor Pa at the subsea BOP stack (kill line fail safe valves open and the kill line valve upstream of the choke closed).

Normal well killing practices can then be applied without the need to take the choke line pressure drop into account, as long as the kill line pressure is used as the annulus pressure indicator during the well killing operation.

Towards the end of the well killing operation, Pchoke will gradually reduce to zero, after which Pst will increase with DP until r2 mud has reached surface. The pump speed should be reduced, if the subsequent increase in BHP with DP is unacceptable.

19.1 Maximum allowable annular surface pressure (MAASP)

MAASP calculated for rigs using a subsea BOP stack equals the formation leak-off pressure at the shoe minus the hydrostatic head of the mud and/or influx in the annulus above the casing shoe.

The hydrostatic head in the annulus and corresponding MAASP should be calculated for the kill- or choke line which is used to monitor the annulus pressure and also acts as the MAASP indicator. Changes in the fluid content of the pressure monitoring line will result in a different MAASP. It is therefore important to know the fluid content of both lines. The best option is to circulate the lines to mud (r1) prior to commencing killing operations.

The pressure loss across the choke line (DP) should also be taken into account during pumping operations, if Pchoke is used as the MAASP indicator.

The "static" MAASP will then change to "dynamic" MAASP:

"dynamic" MAASP = "static" MAASP - DP.

As soon as pumping is stopped, "static" MAASP should be used again.

The pressure drop across the choke line should be ignored if the kill line is used to monitor Pa, and Pa is used as the MAASP indicator.

19.2 Determining the gradient of the influx

When the choke line is filled with seawater or liquids other than the original mud at the time of well closure, the gradient of the influx is given by:

$\rho _{inf}\,=\,\rho _1\,{{\left( {P_a-P_{dp}} \right)-\left\{ {\left( {L_{ch}-h_m} \right)\times \left( {\rho _1-\rho _s} \right)} \right\}} \over {h_b}}\,\,\,kPa/m\ (psi/ft)$

where:${L_{ch}}$= length of chokeline m (ft)${h_m}$= height of mud in the choke line at the time the choke was closed m (ft)${\rho _s}$= gradient of the fluid originally in the choke line kPa/m (psi/ft)${\rho _1}$= original mud gradient${h_b}$= influx height at bottom kPa (psi)${P_a}$= annulus pressure kPa (psi)${P_{dp}}$= drillpipe pressure kPa (psi)

It is assumed that the gradient of the mud in the annulus above the influx is equal to that of the clean mud in the drillstring. If the mud in the annulus includes cuttings and is actually heavier, the calculated influx gradient will be higher than its true value.

19.3 Determining the pressure at the top of a gas influx at any point in the annulus

When the top of the influx has not reached the choke line yet, the pressure at the top of a gas influx can be calculated using the formulae presented in Section 4.18

The peak pressure Ppeak at the choke at the end of Phase II (gas at surface) when circulating out a kick is calculated as follows:

An iterative calculation should be carried out in order to determine Av. cap.x and Ppeak.

Calculations are made as follows:

·assume Av. cap.x = csg/dp capacity;

·calculate Ppeak and Vinflux;

·calculate the corresponding Av. cap.x (including the choke line);

·continue iterative process in order to approximate Ppeak.

19.4 Construction and use of the standpipe kill graph

In principle procedures to construct the standpipe kill graph and any graph adjustments required during well killing operations (e.g. due to plugged nozzles, change in pumping rate, etc.) are the same for all rigs.

The effect of changes in choke line friction losses due to variations of fluid gradients or gas should be dealt with by adjusting the choke, maintaining constant BHP and Pst.

Slugs of mud and gas will cause wide variations in choke pressures and it will be difficult to keep Pst constant by adjusting the choke accordingly.

Circulating out gas through a long choke line may even cause an increase in BHP and Pst (in spite of further opening the choke) due to the speed of the expanding gas.

Methods to reduce this effect are:

·open all chokes completely;

·use both kill-and choke lines to circulate out the gas;

·reduce the pumping rate. (It may even be required to stop/start circulation intermittently to allow the gas to vent).

Note Hydrates could form and chokes and choke line could freeze up. It is recommended to reduce the pumping speed to an absolute minimum just before the gas reaches the choke line. Any change in pumprate will of course affect the standpipe kill graph which should be changed accordingly in order to maintain correct bottom hole pressure.

20 Procedure after the well has been brought under control

After the well has been brought under control, the well should be flow-checked via the open choke line. The preventers should only be opened and normal circulation resumed after flow has ceased from the choke line for a reasonable flow-check time. However, in floating drilling operations, the well may only be opened up after carrying out the following steps:

·Circulate the riser to r2 mud, taking care of any possible riser gas.

·Reduce the volume of trapped gas below the closed preventers.

Well control operations always take precedence over treatment of riser gas problems once the well is shut-in at the BOPs. Riser returns due to expanding riser gas are diverted via the diverter system. The riser is treated passively; the riser content is not circulated via the booster lines until well control operations are completed.

Once the well is safely under control, the riser gas problem is treated prior to taking care of the gas trapped below the closed preventers. The riser content is slowly circulated to the new mud gradient via the booster lines or kill-or choke line above the closed preventer, if available. If this is not possible, the riser is circulated after taking care of the trapped gas below the closed preventers.

The procedure to handle trapped gas accumulated in the BOP stack after a well killing operation depends on the BOP stack configuration and the position of the kill-and choke line connections at the stack.

In principle the procedure should be based on minimising the trapped gas volume before the preventers are opened and the residual gas is released into the riser.

A general approach to cope with trapped gas below closed preventers is summarised as follows:

·If the string is hung off on the uppermost rams, pick up the string, close annular preventer and bottom pipe rams.

·Open top pipe rams, land the string on the bottom rams and displace the upper kill-and choke line contents with seawater whilst applying backpressure at the choke. Do not allow the trapped gas to expand.

·When the lines are circulated to water, close the kill line valves at the stack and bleed-off pressure from the choke line to allow the gas to expand.

·After the flow has stopped completely, open the kill line valves and circulate both lines to seawater again.

·With the diverter closed, open the annular preventer and allow the riser to U-tube into the uppermost kill-or choke line. Keep the riser full with mud via the booster line or riser fill-up line.

·Close the annular preventer again after a few minutes and circulate kill- and choke lines to r2 mud.

·Let the gas, which has possibly been released into the riser, migrate and mix with the mud for approximately 10 minutes per 300 m (1000 ft) of riser length.

·Circulate the riser slowly to r2 mud or, if no booster line is installed, open the annular preventer and circulate via the kill-or choke line.

·Open the diverter and circulate to r2 mud plus margin.

Some subsea BOP stacks have a kill line connection installed directly below the upper annular preventer which makes it possible to reduce the trapped gas volume to an absolute minimum prior to releasing it into the riser.

20.1 Riser margin

When a subsea BOP stack and marine riser are employed, it is normal practice to carry additional mud gradient which will still control the formation pressures with the marine riser removed, parted, or riser blown empty. This is known as the riser margin:

$Riser\ Margin\ =\ {{L\ \times \ W\ -\ W_D\times \rho _{sw}} \over {D\ -\ L}}\,\,\,kPa/m\ (psi/ft)$

Where:${L}$= riser length m (ft)${\rho _{sw}}$= seawater gradient kPa/m (psi/ft)${W}$= mud gradient needed to control formation pressure with riser installed kPa/m (psi/ft)${D}$= depth of highest formation pressure gradient m (ft)${W_D}$= water depth m (ft)

The calculated riser margin should be added to the mud gradient which controls the formation pressure. If this mud gradient does not provide sufficient trip margin, it should be increased to obtain a satisfactory margin.

In deep water and when using high density mud, it may not be practicable to include a riser margin due to the fact that in deep water the maximum allowable mud weight is limited.

After killing a kick, add the trip or riser margin to the mud only after the well is completely under control.