gas kicks n special problems

PULJET KONSULT GAS KICKS AND SPECIAL PROBLEMS Drilling & Well Services Training

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CONTENTS 1. GAS KICKS AND SPECIAL PROBLEMS

1.1 INFLUX BEHAVIOUR 1

1.2 GAS MIGRATION 2

1.3 GAS EXPANSION 4

1.4 EXCEEDING MAXIMUM ALLOWABLE SURFACE PRESSURE 6

1.5 LOST CIRCULATION DURING A KILL 7

1.6 KICKS WITH A BIT OFF BOTTOM OR OUT THE HOLE 8

1.7 PROCEDURES FOR DEALING WITH KICKS 9

1.8 SOLUBLE GAS KICKS 11

1.9 HYDROCARBON GAS KICKS IN OIL BASE VS WATER BASE

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1 GAS KICKS AND SPECIAL PROBLEMS 1.1 INFLUX BEHAVIOUR

1.1.1 General The formation fluids influx into a well will consist of water, oil or gas, or various combinations of these. Effects of influx are explained in the following paragraphs.

1.1.2 Water

Water is virtually incompressible, and so does not expand significantly as the pressure on it reduces; hence while circulating a water kick, there should be no change in pit level provided no further influx is allowed. Small variations in casing pressure occur as an influx moves through different annular geometrics but these will be minor effects compared to the changes seen in a gas kick. Often water kicks are gas charged, with gas in solution, and these will show pressure variations similar to a gas kick, on a smaller scale.

1.1.3 Oil

Oil has gas in solution, so the effect will be similar to that produced by a gas kick, although again somewhat reduced in scale.

1.1.4 Gas

Gas is compressible. The volume occupied by a quantity of gas is related to both pressure and temperature. The property means that during the circulation of a gas kick, the volume of the gas must be allowed to expand in order to drop the pressure as it comes to the surface. Considerable changes in casing pressure are seen, along with variation in pit levels. For this reason, gas kicks are the hardest to deal with, and the majority of kicks discussed in well control literature are gas kicks. A further problem is that gases, being lighter than the muds in normal use, tend to percolate through the mud up the hole toward the surface.


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1.2 GAS MIGRATION

If a gas kick enters a well, the pressure of gas at that point is formation pressure (PF), (ignoring any skin damage effects). Gases are compressible and thus store energy for later release. Considerable energy can be stored in this way. Liquids, in contrast, are virtually incompressible, and because little or no change in volume occurs little energy can be stored. This characteristic of gas means that when a well is shut in with a gas kick, the gas in the well retains the prevailing pressure at the moment of shut in, if no expansion of that gas is allowed. Gases are generally lighter than the drilling muds in use, and tend to ‘float’ or percolate up the hole toward the surface. So long as the well stays shut in, and nothing breaks down, the gas bubbles will stay the same total volume and hence at the same pressure while moving up the hole. This is usually called ‘Gas Migration’. It is a basic principle that in an unbroken, sealed in well the pressures at any point must balance each other. If a gas bubble of constant volume and constant pressure is slowly moving toward the surface, there must be progressively less and less mud hydrostatic head above it, to balance its pressure. Thus in order to maintain a balance as the bubble rises, the annulus, or casing, pressure must rise. In this case, an increase in casing pressure must result in an increase of bottom-hole pressure, since the total hydrostatic pressure of fluid in the annulus has not changed. This increased bottom hole pressure must itself in turn result in an increased drillpipe pressure, since the hydrostatic head of fluid in the drillpipe has not altered. A slow continuous increase of shut-in drillpipe and shut-in casing pressures together, after their initial stabilisation, is a positive indication of gas in a kick.


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1.3 GAS EXPANSION

During a kill the gas is not allowed to expand freely, since this would result in the well ‘unloading’. Therefore a CONSTANT BOTTOM HOLE PRESSURE slightly above FORMATION PRESSURE is maintained throughout the kill. The diagrams Figure 2 and Figure 3 show theoretically how casing pressure and pit volume vary during the circulating out of a gas kick, using the Wait and Weight method, while holding BHP constant. Figure 2 assumes a single bubble has entered the well. As previously mentioned the dispersion of many small bubbles, spread along a considerable length of the annulus, results in a ‘smearing out’ of the graph. The peak pressures are reduced and pressure variations slower than indicated. A-B Gas bubble moves from around Drill Collars to around Drill Pipe in the open hole. B-C

Small expansion occurs as gas circulates up the annulus. C-D Gas is still slowly expanding, but the effect of kill mud entering the annulus is greater,

hence a small pressure reduction occurs. D-E The increasingly rapid gas expansion effect now exceeds the effect of kill mud in the

annulus and an increasingly rapid rise in casing pressure occurs. E-F As gas is bled off from the annulus, and replaced by heavy mud, the casing pressure

falls. F-G Light mud from the drillpipe is steadily replaced by heavy mud.

Figure 2 - Casing Pressure v Barrels Pumped (Wait & weight Kill)


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Figure 3 – Pit Volume Increase to Barrels Pumped


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1.4 EXCEEDING MAXIMUM ALLOWABLE SURFACE

PRESSURE 1.4.1 Factors Influencing Maximum Casing Pressure

The maximum casing pressure resulting from circulating out a kick while maintaining constant BHP is influenced by the following factors: a) Size of kick b) Formation pore pressure c) Difference between mud and formation pore pressure gradients (Original Mud Weight

versus Kill Mud Weight) d) Density and type of kick. (Gas kicks are worse) e) Annular volume capacity. Pressures increase as annular capacity decreases because the

gas bubble is ‘longer’ f) Formation influx height g) The type of kick killing method used (e.g. the Wait and Weight Method causes the

lowest casing pressure.) Of all the variables involved, the influx volume or kick size is the most significant factor in determining how high the maximum surface pressure will be. The other variables cause maximum surface pressure increases, but their effect is not nearly as great as the effect of kick size. Under identical well conditions, gas kicks cause higher surface pressures than salt water or oil kicks of equal size. This emphasises the importance of detecting a kick early, before the influx has become too large to handle with reasonable surface pressure. For this reason, it is essential that every available means be used to detect all kicks as quickly as possible. The most important step in controlling potential blowouts is rapid detection, followed by positive action to bring the well under control. If after the well is closed in, or during circulation, the maximum allowable surface pressure on the annulus is likely to be exceeded, problems may arise. Generally this maximum pressure relates to the pressure required to cause formation leak-off and breakdown at the casing shoe. Many formations, especially non-consolidated or plastic formations, are strengthened during the drilling process by the bridging actions of mud and drilled solids. This means that leak-off and breakdown may occur at higher values than the specified maximum allowable. In most cases, the best practice is to proceed normally and closely monitor pit volume. If pit levels start to fall, the ‘low-choke’ method may be used. This should only be required where the influx is known to still be below the casing shoe.


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1.4.2 Low Choke Method

After observing the maximum allowable surface pressure, choke adjustment may be made to hold the casing pressure constant. This will steadily reduce BHP. This procedure is to be limited at most to a 150 psi drop in BHP. The effect of annular friction loss acts as a small safety margin before influx occurs. In many cases this procedure allows time for the influx to be circulated past the casing shoe before a further significant influx occurs. This depends, amongst other things, on formation permeability. Once the 150 psi drop in BHP has been allowed, the drillpipe pressure must thereafter be held constant. Casing pressure is allowed to rise again, and depending on circumstances, partial lost returns may then occur. After a gas kick is well inside the shoe, although surface casing pressures may exceed the MAASP determined by casing shoe leak-off, this will not result in a breakdown at the shoe, accordingly the low choke method is not required.

1.5 LOST CIRCULATION DURING A KILL 1.5.1 General

Lost circulation may occur as partial or total loss of returns. In the relatively soft shales of the marine basins, partial losses are relatively common during well kills. In this case, the well is killed using the standard method. With total losses, as may occur in older hard rock country, well control is much more difficult. There are a number of signs which, taken together, indicate that losses are occurring. The most reliable of these is the pit level, which may either drop or, more probably, fall below an expected trend of increase as gas expands. Another indication of loss is choke movement. Most choke adjustments in a usual kill are towards the open position. If a gradual closing down is needed to hold pressure, lost circulation is a possibility, since this results in casing and drillpipe pressure dropping, with the casing pressure reduction being more pronounced.

1.5.2 Partial Losses

With partial loss of returns, two possible courses of action are: a) Maintain kill rate pump speed and drillpipe pressures to keep a constant bottom hole

pressure, while attempting to keep up with the losses until the gas is within the shoe. Once the gas is within the casing shoe, the lost return problem should stabilise.

b) If the losses become increasingly heavy, the ‘low-choke’ method should be adopted. If

this does not allow sufficient returns, then close the well in and treat as for severe or complete losses.

1.5.3 Severe or Total Losses

Where losses are too severe to maintain or are total, several options remain: a) Pump lost circulation material down the annulus. In most instances, losses occur at the

casing shoe, in which case Lost Circulation Material (LCM) pumped down the annulus


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will often reach the shoe more rapidly. Pumping down the annulus further helps to reduce influx and to avoid bit plugging, since the total fluid head is greater.

b) Placing a heavy slug of mud on bottom. A heavy slug of mud can be spotted to fill the

annulus between hole bottom and the lost circulation zone. This slug should be of sufficient weight to balance formation pressure with the assistance of the column of original weight mud. It should be reasonable to expect the well still holds the previous drilling mud weight, if no losses have occurred during drilling; however it may be safer to assume the well will only support a full column of sea-water above the loss zone. This is the most pessimistic practical assumption. Having placed the heavy slug in position, strip above the slug, circulate the influx out; and then take measures to cure the lost circulation. Once this is achieved, it is possible to stage in and circulate the heavy slug out.

c) Set barite, cement or gunk plugs.

There may be difficulty in getting any of these plugs to set properly in a flowing well, especially the cement plug. One method is to set a barite or gunk plug, followed by a cement plug on top. The heavier a barite plug, the more reluctant it is to settle, as the barite becomes self-suspending. However, a heavy plug has advantages. A high concentration of thinners may be needed with high density plugs which can be weighted up to a maximum of 20 ppg. This may not work in a water flow, but is potentially effective in a gas flow. Gunk plug squeezes, which are mixtures of diesel oil and bentonite, work well in water flows — which help the squeeze to set up. However, they are likely to be hard to set in gas flows. A cement plug should be set above a gunk squeeze, which will slowly lose strength and, although a correctly set barite plug is fairly permanent, setting a cement plug above would still be a reasonable precaution.

1.6 KICKS WITH BIT OFF BOTTOM OR OUT OF THE HOLE 1.6.1 Precautions

Generally, kicks which occur while puffing out are due either to swabbing in or failing to keep the hole full. A short check trip prior to puffing Out of the hole may be a useful precaution where a drilling break has been encountered immediately before the trip, or where swabbing is anticipated as a problem. If the hole does not take the correct fill volumes, then return to bottom and circulate to condition the hole.

1.6.2 Problems

If the well has to be killed off bottom, several problems arise. First, killing off bottom takes higher kill mud weights than on bottom, creating increased pressure on the formation. For a swabbed in kick, the original mud weight will balance formation pressure on bottom. Secondly, the bit must be returned to bottom to circulate the kick and the well is not dead until this is completed. The operation may require staging in using two or more kill operations. Thirdly, and an example of the complications which occur, gas migration below the bit makes accurate determination of bottom hole pressure difficult or impossible. Kill rate pressures cannot be determined accurately.


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1.7 PROCEDURES FOR DEALING WITH KICKS 1.7.1 One Stage Kill

The well is closed in as quickly as possible to keep kick size to a minimum. If at all possible, pipe is to be run back to bottom, by stripping in, before starting the kill. Appropriate procedures for this are discussed under ‘Stripping’. While stripping in, variations in bottom hole pressure due to gas migration may be dealt with using the Volumetric method discussed in Section ‘Kill Methods’. DO NOT RUN BACK IN WITH THE WELL OPEN. If the well is underbalanced, a further influx will occur and higher casing pressures will inevitably result during the kill circulation.

1.7.2 Two or Multi-Stage Kill

If return to bottom is not practicable, the well must be brought back to balance to allow staging back to bottom and a final kill. The diagram Figure 4 illustrates a situation with a well closed in, bit off bottom. Note that the shut in drillpipe and shut in casing pressure are reading the same. If all of the influx is below the bit, this is likely to be so. The effect of a slug of heavy mud in the drilipipe, for tripping, would be to lower the drillpipe figure somewhat (perhaps 30 or 40 psi). Therefore, to establish pressures as accurately as possible, it is necessary to ‘clear’ the slug out of the drillpipe. This is done by circulating original weight mud down the drillpipe at (say) the kill rate, while holding casing pressure steady at its last shut in value, using the choke. Note that this will maintain constant pressure at the bit, not at the bottom of the hole. If the influx is moving up the hole, but still stays below the bit, then this procedure allows bottom hole pressure to reduce somewhat. This effect will be small, and may be off set by the heavy slug entering the annulus. One disadvantage of killing off bottom can be seen here; there are more unknowns and an accurate picture of bottom hole conditions is impossible. In a normal kill with the bit on bottom, drilipipe pressure readings give us an accurate indications of what is happening at the bottom of the hole. Once the drill pipe has been displaced to original weight mud, the shut in drillpipe pressure can be used to calculate a kill mud weight. In this case, the same procedure can be used but the required depth figure is the bit vertical depth and not the total vertical depth. Note that is the bit is considerably off bottom, any slow circulating rate pressure obtained before the trip will be in error and it may then be necessary to determine a new Initial Circulating Pressure using the normal start-up procedures described in Section ‘Kill Methods’. It is re-emphasised that the effect of gas migration during the kill procedure could result in an increase in bottom hole pressure, which puts more stress on the well. Once the well is ‘dead’ to the bit, it may be possible to stage in by progressively circulating contaminated mud and gas, while circulating kill mud in to replace it.


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1.8 SOLUBLE GAS KICKS

A gas kick where some or all of the gas goes into solution in the drilling fluid can be very dangerous and difficult to handle. If the gas is in solution, it does not normally expand until it comes out of solution. As the fluid nears the surface, the drop in pressure and temperature may allow gas to break out from the fluid. The normal near-surface rapid expansion then occurs when not expected, in what otherwise appeared as an easily managed liquid kick. This effect is very likely to occur in petroleum vapour gas kicks in oil base muds, where a significant solubility exists. It may also occur, very dangerously, with hydrogen sulphide gas, in water based drilling muds, especially at relatively low alkaline pH levels. It is considered that carbon dioxide gas may also show this effect in water base muds, though somewhat less dramatically due to its lower solubility. In any of these cases, the result is that casing pressures stay low, and may well drop slowly during the Wait and Weight circulation of kill mud, until the dissolved kick is near the surface. A rapid rise in casing pressure, with a corresponding rise in pit level then occurs. This effect may also make it effectively impossible to spot a kick occurring using the ‘conventional’ primary signs. The first visible sign may be gas belching and mud unloading at the bell nipple. It may therefore be worth considering the use of a rotating head when drilling with oilbase muds in suspected gas zones. The well should be fully circulated, ‘bottoms up’ before tripping or after a drilling break. In certain instances it has been necessary to perform this circulation through the choke manifold, in order to provide the necessary immediate protection.


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1.9 HYDROCARBON GAS KICKS IN OIL BASE vs WATER BASE

MUDS

NOTE: This is a general guide and under certain well conditions the values may change.

gas kicks n special problems

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