Positive Kick Sign

Positive kick indicators are different from kick warning signs. They indicate that the kick has already entered the well bore. Any of them indicate regular flow checks.

i) Increase in Return Flow (Pumps On)

After the early warning signs the first positive kick sign is increase in flow rate at the flow line withpumps on. The entrance of any fluid into the well bore causes the flow rate to increase.

ii) Flow from Well (Pumps Off)

Stopping the pump causes a reduction in bottom hole pressure equivalent to the annular pressure drop, so flow check is a reliable method of checking for a well kick. If the well does not flow when the pump is shut off and remains static for two or three minutes, then no well kick is entering.

iii) Pit Volume Increase

An increase in pit volume is obvious & positive indication of flow into the well bore & can be easily verified. If an increase in pit volume is seen, shut off the pump and make a flow check. If the well does not flow, no kick is entering.

iv) Decrease in Pump Pressure and Increase in Pump Stroke

In case of kick there is under balanced condition between the fluid in the drill pipe and the mixed column of mud and influx in the annulus. Therefore circulating pressure gradually decreases and unless the pump throttle is changed, pump speed slowly increases.

12.3 KICK WHILE TRIPPING

When the pump is switched off, a reduction in BHP equal to annular pressure losses occurs. To prevent kick while tripping, basic requirement is that hole must be kept full of mud and the volume of mud required to fill the hole must be equal to the steel displacement of drill string pulled out. The sequence of events to a kick while making a trip-out of hole is :

• Hole remains full or does not take proper amount of mud. Whenever such ‰ situation is noticed the pipe should be run back to bottom and mud is ‰ circulated to clear the hole.

• Flow from the flow line • Increase in pit volume

The sequence of events leading to a kick while tripping-in the hole is:

• The hole does not stop flowing during making connection between the stands • Increase in pit volume

In order to avoid well kicks while tripping, trip schedule must be made and trip tank must be used to monitor the hole fill up (in case of tripping-out) and mud displacement (in case of tripping-in).

12.4 TRIP MARGIN

During pulling out, upward motion of the drill string in the borehole (which is assumed to be full of mud) creates a swab pressure. This decreases BHP when pipe is in motion. One way of minimising this is to use safe tripping speeds and having close monitoring of pipe volume pulled out & mud volume pumped in to keep the hole full. Another practice to tackle the problem is to keep mud weight gradient greater than the formation pressure gradient. The resulting overbalance permits safe tripping and connection operations. This extra mud weight is called trip margin. For normal drilling operation trip margin is kept 0.2 to 0.3 ppg.

However, the swab pressure being a function of yield point (yp) of mud, trip margin can be calculated as follows:-

Trip margin (ppg)= 8.33Yp ÷ 98 (dh-dp) Where

Yp = Yield point of mud in lbs/100 sq.ft Dh = Hole diameter in inches

Dp = Pipe outside diameter in inches

Effect of riser margin on maintaining bottom hole pressure

In the event of riser getting accidentally disconnected due to vessel drive-off or riser failure etc. the bottom hole pressure shall be reduced due to loss of hydrostatic pressure as the riser mud column is replaced by sea water. To compensate this reduction in bottom hole pressure, some margin has to be added to the drilling mud density which is known as riser margin.

Example: Water depth - 700 ft RKB to sea level - 50 ft Mud density - 11 ppg Seawater density - 8.5 ppg Well TVD - 10000 ft Solution : RISER MARGIN (ppg) =

[ Air Gap + Water depth] x Mud density – [ Water Depth x Sea Water Density] ————————————————————————————————————

TVD – Air Gap – Water Depth

[ 50 + 700] x 11 – [ 700 x 8.5]

—————————————— = 0.25 ppg 10000 – 50 – 700

Mud Density including Riser margin = 11+0.25 = 11.25 ppg

12.5 SLOW CIRCULATION RATE

During well control operations, to avoid further entry of formation fluid it is essential to keep BHP minimum equal to formation pressure. This is done by imposing certain calculated back pressure in addition to system pressure losses on the well bore as long as old mud is in the well. Kicks have to be circulated out at slow circulation rates to ensure that the sum of this back pressure and system losses does not exceed the rating of high pressure lines and other rig equipment. Various reasons for circulating out the kicks at slow circulation rates are :-

a) To ensure that the slow circulation pressure plus the shut in drill pipe pressure is a convenient total pressure for the pump and does not exceed the surface line ratings.

b) To allow mud returns to be weighted up and re-circulated within the capabilities of available mud mixing system.

c) To allow longer reaction time for choke adjustments.

d) To allow sufficient time for disposal of kick fluid /de-gassing at the surface. e) To reduce the annular pressure losses.

The common practice so far had been to select a rate which is about half the pump speed at the time of drilling. This practice was fairly good with duplex mud pump earlier in use on drilling rigs. Now with the use of triplex pumps this convention gives much higher speeds than the actual requirements. Theoretically speaking the kill rate or slow circulation rate should be the minimum possible pump speed at which pump can run smoothly without any knocking etc. But since at minimum pump speeds more time will be required to kill the well, a compromise has to be made which can meet all the requirements. Therefore slow circulation rate should be 1/2 to 1/3 of pump SPM at the time of drilling.

Recording of slow circulation rate

It should be recorded near to the bottom for each pump at regular intervals and / or when drilling conditions change such as:-

i) At the beginning of each shift. ii) After change in drilling fluid density. iii) After change in bit nozzle size or BHA.

iv) After drilling a long section of hole (500 ft.) in a shift. v) After pump fluid end repair.

On the rig there are a no. of places where drill pipe pressure gauges are installed such as stand pipe, mud pumps, driller’s console, choke & kill manifold and remote choke panel. Slow circulation pressure should be recorded from the gauge that is to be used for well killing operation . So, it should be recorded at remote choke panel, if available on the rig.

Choke line friction losses

In subsea operations when circulating through choke, flow resistance in the extending choke line running up from the sub sea BOP to surface is considerable. If pressure losses in choke line are not taken into account during well killing, an excess pressure unnecessarily may be applied in the hole. Since fracture gradient generally decreases with increased water depth, so beyond 500ft water depth choke line friction losses should always be considered while planning well control operations.

Measurement of chokes line friction losses

There are three ways to find out choke line friction losses.These are :

a) Pump down the choke line at slow circulation rate taking the returns into the riser through open blow out preventer. The pressure thus shown on the choke manifold gauge is the choke line friction losses. The value so obtained does include circulating pressure losses in the riser but that is negligible.

b) Record circulating pressure at slow rate through riser with BOP open. Close BOP, open choke line fail safe valve and record pressure with full choke open. The difference of the two values is the choke line friction loss.

c) Pump down the choke line at slow circulation rate taking the returns through kill line with BOP closed. The pressure thus shown on the choke manifold gauge is twice the choke line friction losses.

Corrected choke line friction losses for new mud density can be calculated as follows:- New mud density

Choke line friction losses with old mud × -———————— Old mud density

Drill pipe pressure should be recorded at two or more slow circulation rates. Choke line pressure should also be measured over the same range of rates. Both drill pipe pressure & choke line pressure losses can be plotted separately on Log-Log paper and extrapolated to provide respective estimated pressure losses at various pump rates because due to high friction losses in the choke line it may be necessary to circulate out a kick at a very slow rate if formation breakdown is to be avoided.

12.6 LINE UP FOR SHUT IN

When one or more positive kick signs are observed, flow check is made. In case of self flow well can be shut-in in two ways:

a) Soft shut-in b) Hard shut-in

12.7 SHUT IN PROCEDURES As per API RP 59

As per following are the shut-in procedures for land/jack-up rigs & floating rigs.