3 causes jfhjhgjwarnings

CAUSES AND WARNINGSWell Control School

Define key terms in well controlDiscuss the conditions that must exist for a kick to be takenDescribe drilling actions that can lead to an influxDescribe the common warning signs that indicate a kick has occurred

A surface blowout is:an uncontrolled flow of wellbore fluids at the surfacefluids can be gas, oil, mud, water or allfire may or may not breakoutresults may be seriousloss of lifedamage to the environmentloss of equipmentloss of the wellA kick is: -an unwanted influx of formation fluids into the wellbore

Maintain Sufficient Wellbore Pressurewellbore pressure > formation pressureuse hydrostatic pressure of the mudprovide a margin for swabbingUse Trip Tank Continuouslykeep the hole standing fullmeasure volumes of mud during trips

Necessary Conditions for a KickCommon Causes of KicksWarning Signs

Two Conditions Can Lead to a Kick...1. The formation must have permeability or contain fractures or channels, and2. The formation pressure must be greater than the wellbore pressure at the point of influxThe Two Conditions Together are Necessary and Sufficient for a Kick

Hole Not Full of MudSurging or Swabbing During a TripInsufficient Mud Weight (Density)Abnormal PressureLoss of CirculationRapidly Drilling a Gas SandDrilling Into an Adjacent Well

If the hole is not full of mud, then the hydrostatic pressure at the bottom is reduced. If the mud level drops sufficiently, then the hydrostatic pressure can be reduced enough to allow an influx to occur.

Causes for a loss in mud level include:1.Pulling pipe from the hole without using trip tank2.Lost circulation (lost returns)3.Poor mud filtration characteristics4. High permeability formations

Drilling Actions / Conditions that Can Cause a KickHole Not Full of MudSurging or Swabbing During a TripInsufficient Mud Weight (Density)Abnormal PressureLoss of CirculationRapidly Drilling a Gas SandDrilling Into an Adjacent Well

Running pipe into hole too fast creates large bottom-hole pressures that can fracture the formation.When drilling mud is lost to the formation, the height of the mud column in the annulus drops - reduced hydrostatic pressureWhen hydrostatic pressure decreases, formation fluids can enter the wellbore.

Hole Not Full of MudSurging or Swabbing During a TripInsufficient Mud Weight (Density)Abnormal PressureLoss of CirculationRapidly Drilling a Gas SandDrilling Into an Adjacent Well

Insufficient Mud Weight9.7 ppg9.2 ppgHydrostatic pressure from mud column is lower than pore pressure - InfluxWith well shut-in, gas migrates up the annulus leading to increased casing pressure.GasInflux

Normal pressure is equivalent to the hydrostatic pressure generated by a column of salt waterAbnormal pressure is anything elseRule of Thumb - Abnormal pressure is a equivalent mud weight > 9.0 ppgAbnormal pressure has many causes

Abnormal Pressure IndicatorsD-exponentIncreased ROPChange in shale densityIncreased drill gasesIncreased downhole temperatureCuttings analysisIncreased chlorides

Thick zone of oil or gas above a normally pressured aquifer appears abnormally pressured

Question-2 (Losses)Whilst drilling ahead, partial losses are measure at 10 bbls/hr. A total power loss occurs.Annular capacity 0.1512 bbls/ft (with pipe).Mud weight 10.2 ppg.If the hole cannot be filled, what will be the reduction in bottom hole pressure after 4 hours?

a. 250 psi.b. 560 psi.c. 175 psi.d. 140 psi.

10 ppgEquivalent Mud Weight in Annulus (ppg)Depth below flow line (ft)

Sheet1

MW ppgftMW kg/m3m

505990

910001078.2304.8780487805

9.5525001144.09762.1951219512

9.750001162.061524.3902439024

9.8100001174.043048.7804878049

Chart2

0

1000

2500

5000

10000

Sheet2

Sheet3

Yes, it can & does happen!Platform wells most susceptible

Warning signs include:

Erratic torqueDrop in ROPCement in returnsMetal shavings in returnsWell kicks

Hole Not Taking Correct Amount of Mud on a TripGain in Pit VolumeIncreased Flow Rate from AnnulusDrilling BreakChange in Pump Speed or PressureGas Cut MudChloride Increase

Loss of hydrostatic pressure if trip without filling pipe (no trip tank)

ExampleIf hole doesnt take correct mud volume, conduct flow check:If positive - shut-in, strip to bottomIf negative - trip to bottom, circulate

Required on all tanks in active mud system

Audible and visual alarms installed in drillers console

A recorder and dial indicator of pit gain shall be installed on drillers console102030405060708090100VolumeDeviationsTotalVolumeSchematic of Pit Volume TotalizerFloatTransmitterMud PitGages on Console

Pump Rate ConstantReturn Rate IncreasesInput < OutputWellbore InfluxMost Sensitive IndicatorFor critical wells, more accurate meters availableA simple paddle type flowmeter in the return flow line

Sudden Increase In ROPCauseschange in formation strength or typechange in bit operating parametersincrease in pore pressuredrilling underbalanced

Influx of lighter fluids reduces hydrostatic pressure in the annulusMud in drill pipe tends to U-tube - heavier mud in drill pipePump will speed up due to less resistancePump pressure (surface standpipe) will decrease as mud tends to U-tube

10 ppgEquivalent Mud Weight in Annulus (ppg)Depth below flow line (ft)

Sheet1

MW ppgftMW kg/m3m

505990

910001078.2304.8780487805

9.5525001144.09762.1951219512

9.750001162.061524.3902439024

9.8100001174.043048.7804878049

Chart2

0

1000

2500

5000

10000

Sheet2

Sheet3

Kicks occur when formation pressure exceeds wellbore pressure and the formation is permeable or fracturedCommon causes of kicks include hole not full, swabbing, surging, insufficient mud weight, abnormal pressure, charged zones, loss of circulation, and rapidly drilling a gas sandWarning signs for kicks include hole not taking the correct amount of mud on a trip, gain in pit volume, increased flow from the annulus, drilling break, change in pump speed or pressure, gas cut mud, and chloride increase

This is an example of what we are here to learn how to avoid - a surface blowout.

This blowout occurred on an Armco platform operating in the Berri field in the Arabian Gulf during the late 1970s

To ensure that we all have a common understanding of the important concepts in well control, lets define the most important terms

A surface blowout is defined as an uncontrolled flow of wellbore fluids at the surface during a well drilling, completions or workover operation.The fluids can be hydrocarbons, mud, water or a combination of all.During a blowout, fire may or may not result. The breakout of a fire depends on the type of fluid being blow from the wellbore, its concentration relative to the available oxygen, and whether a source of ignition is present.The results are generally serious and include the possibility of loss of life, injury, damage to the environment, loss of the rig and/or the well itself.Surface blowouts occur very seldom, particularly in Exxon operations. Exxon has an excellent safety record.

A kick is an unwanted influx of formation fluids into the wellbore. A kick can be oil, gas, water, or a mixture of these fluids. There are a number of causes for kicks and warning signs that a kick has occured. The objective of this lecture is to discuss these causes and warnings. Our primary method to control the well and prevent kicks is to ensure that the pressure inside the wellbore is always larger than the pressure in the formation.

The primary method for controlling formation fluids exposed in a wellbore is to keep the local wellbore pressure greater than the formation pressure.Normally, this is achieved by using a mud of sufficient density to create a hydrostatic pressure that keeps the wellbore pressure greater than the formation pressure.The hydrostatic is calculated by: p = 0.052 x MW (ppg) x TVD (ft)The mud weight chosen should contain a small margin (0.1 or 0.2 ppg) to overcome the effects of swabbing that occur when the drill string is moved upward during connections and trips.When not drilling or circulating, such as when tripping a drill string into or out of a well, the trip tank is put on the hole to keep the hole standing full of mud and to measure mud volumes vs. pipe displacement, thereby keeping the wellbore pressure greater than the formation pressure at all times.

Now that we have covered some background, lets focus on kick detection.During well operations, only two conditions have to be met for an influx to occur. Both conditions must exist.

1. The formation exposed must have permeability or contain fractures or channels filled with formation fluids, and2. The formation pressure must be greater than the wellbore pressure at the point of influx.

The two conditions are both necessary and sufficient conditions for a kick to occur.

First lets consider the consequences of not keeping the hole full of mud.

For earlier we know that the the hydrostatic pressure in the wellbore depends on the fluid column height and the mud weight. p = 0.052 x MW (ppg) x TVD (ft)So, it follows that if the TVD is reduced (mud level drops in the well) then the hydrostatic pressure will drop correspondingly. What could cause the mud level to drop in the wellbore?1. Pulling pipe without using the trip tank - if metal is removed from well and not enough mud is pumped in to replace the steel, then the mud level and pressure will drop2. Lost Circulation - If the formation is fractured and the fluid is lost to the formation, the mud level and hydrostatic pressure in the wellbore will drop.3. Poor Mud Characteristics - poor mud characteristics can lead to a poor filter cake on the wellbore. Fluid can seep to the formation leading the reduced mud level and pressure4. High permeability formations - if being drilled with water or brine, loss to formation must be expected and accounted for to keep hole full

ALWAYS USE TRIP TANK TO KEEP HOLE FULL!!For earlier we know that the the hydrostatic pressure in the wellbore depends on the fluid column height and the mud weight. p = 0.052 x MW (ppg) x TVD (ft)So, it follows that if the TVD is reduced (mud level drops in the well) then the hydrostatic pressure will drop correspondingly. What could cause the mud level to drop in the wellbore?1. Pulling pipe without using the trip tank - if metal is removed from well and not enough mud is pumped in to replace the steel, then the mud level and pressure will drop2. Lost Circulation - If the formation is fractured and the fluid is lost to the formation, the mud level and hydrostatic pressure in the wellbore will drop.3. Poor Mud Characteristics - poor mud characteristics can lead to a poor filter cake on the wellbore. Fluid can seep to the formation leading the reduced mud level and pressure4. High permeability formations - if being drilled with water or brine, loss to formation must be expected and accounted for to keep hole full

ALWAYS USE TRIP TANK TO KEEP HOLE FULL!!When pipe (or casing) is run into the hole, it must displace fluid. Moving the fluid out of the way leads to increased pressure under the bit. This is called surge pressure. It is similar to a syringe - push in the plunger and the pressure under it increases.

A number of parameters determine surge pressure:Mud densityMud rheology (viscosity, yield)Annular clearance.Running speedBalled-up BHAEPR has a computer model SURGE, used to simulate both surging and swabbing. Swabbing is the opposite of surging. When pipe is pulled from the hole, the pressure below the bit is reduced. Again using the syringe analogy, swabbing is like pulling the plunger out - reduced pressure can lead to an influx.

Use trip tank measurements to detect swabbing and return to bottom.

Factors that impact swabbing:Close hole tolerances (small annular clearances)Pipe SpeedPoor Mud Properties (mud rheology)Balled-up BHA

EPR has a computer model SURGE, used to simulate both surging and swabbing.

We know from our hydrostatic pressure equation that proper fluid density or mud weight is critical to maintaining the wellbore pressure above formation pressure.

Consider the above schematic: If drilling with a 9.2 ppg mud, the hydrostatic pressure in the wellbore is not large enough to balance the 9.7 ppg equivalent formation pressure, so an influx is taken.

When the well is shut in, the casing and drillpipe pressure increase to balance the formation pressure. As time passes, the influx will migrate up the wellbore further increasing bottomhole pressure. Abnormal pressure is a term used to describe pressures that might exist in wellbores that are greater than an expected, naturally occurring hydrostatic pressure.Normal pressure is equivalent the hydrostatic pressure generated by a column of seawater. Normal pressure is also often expressed in terms of a normal pressure gradient. A normal pressure gradient is 0.465 psi per foot.Abnormal pressure is a pressure greater than the hydrostatic pressure of a column of seawater. An abnormal pressure gradient is a pressure gradient greater than a seawater gradient of 0.465 psi/foot.In terms of equivalent mud weight, an abnormal pressure gradient or simply abnormal pressure is a formation pressure gradient greater than 9.0 pounds per gallon (ppg).Lets discuss the main indicators and causes of abnormal pressure.

D-exponent - the d-exponent is a dimensionless ROP that takes into account changes in rotary speed, bit weight, and bit size. It is a real change in ROP that would be caused by something other than changes in drilling parameters. Increased d-exponent could indicate abnormal pressure. D-exponent not valid for PDC bits. Increased ROP - abnormal pressure would tend to help push cuttings up the wellbore after they are removed from the well. ROP will increase because cuttings are not being held down and re-ground by the bit.Changes in shale density - measurement of retained water in shales. As formation pressure increases, more water will be in the shale pores thereby reducing the overall density. Increased drill gases - The gas in the drilling fluid can increase when drilling into abnormally pressured, shallow gas region. Increased downhole temperature - Increases in pressure are often accompanied by an increase in temperature.Cutting analysis - used to detect changes in rock density that would accompany increased pressure. Cuttings appearance can say whether they were cut off by bit or pushed of by abnormal pressure.Increased chlorides - chloride level will increase when a permeable abnormally pressured formation with salt water is encountered.

One cause of abnormal pressure is aquifer outcrop.

The normal-pressured well encounters a fluid column that starts at sea level; therefore the water column height is the same as the TVD of the well.

The abnormally-pressured well encounters an aquifer at the same TVD, but the water column is higher because the aquifer has an outcrop that is elevated above sea-level. The increased fluid column leads to a higher pressure.

This scenario could be encountered in platform or land drilling near mountainous regions

This scenario for abnormal pressure involves a thick hydrocarbon zone.

The pressure at the oil-water contact is the same as the pressure generated by the water column on the right side of the figure(normal pressure). However, since the fluids above the water (oil and gas) have lower densities than water, they must be under pressure to balance the water column.

So, when we drill into the gas, we encounter pressure that is greater than the pressure in a water column at the same TVD.

In general, formation pressure increases with depth. This is because the overburden and formation compaction increase. When a fault moves a deep interval to a shallower depth, the interval will retain its higher pressure provided that the fault is sealed.

If we drill into this sealed, uplifted fault interval, we will encounter the pressure that occurs normally at a deeper depth. This will appear as abnormal pressure.In areas of rapid deposition, organic material can be deposited and sealed at shallow depths. As bacterial decay of this organic material takes place, the methane gas produced can be sealed and pressurized at shallow depths.

When hydrocarbons exist in a sealed formation, the overburden and compaction from the earth above the formation can lead to increased reservoir pressure. When the sealed interval is compacted, the additional pressure cannot be released (sealed reservoir), so the formation pressure increases.

So far we have discussed how several factors can lead to a kick. Next, lets consider what happens when lost circulation occurs. Lost circulation is the loss of fluid in the wellbore to the formation. Initially, one might think that losing fluid is OK - it is taking formation fluids into the wellbore that we want to prevent. However, as we will show, losing fluid in the wellbore can lead directly to taking an influx.

Consider the schematic in the above figure. While drilling, we encounter a highly permeable or under-pressured zone, and our drilling fluid begins to rapidly flow into the formation. This causes of fluid levels in the wellbore to drop.

A reduction in hydrostatic pressure accompanies the drop in fluid level, and the reduced pressure could allow formation fluids from a different interval to flow into the wellbore.

LMST = limestoneSDST = sandstoneA gas sand is an sand interval that contains some quantity of gas. If a gas sand is drilled rapidly, a large amount of gas can be introduced into the well. As the gas expands while traveling up the wellbore, it reduces the density of the fluid column in the annulus.

At bottomhole conditions, the gas is under high pressure and does not alter the local fluid density significantly. However, as the gas is circulated up the annulus, the hydrostatic pressure decreases. This allows the bubble to expand. When the gas gets near the surface, it can occupy a significant volume of the wellbore. The two-phase mixture has a lower bulk density than the liquid phase alone. The reduced pressure can lead to an influx from a shallow downhole interval.

This is not usually significant, but it can cause the appearance of positive flow as the gas approaches the surface.

Another cause of well kicks is drilling into an adjacent well. While this may sound highly unlikely, it can and does occur. It is most common in platform development drilling where a large number of directional wells are drilled from a central platform. If the wellbore of a producing well is penetrated, the produced fluids could enter the wellbore of the drill well as a kick.Lost returns could also result from penetrating another wellbore.

Warning signs include:Erratic torque - would be expected if suddenly drilling steel casingDrop in ROP - expected when drilling cement and/or steel tubularsCement in returns - cement form the adjacent casing appearing in the returnsMetal shavings in returns - cuttings show pieces of adjacent casing string Best way to prevent this is to plan carefully and take surveys to ensure that the bit is not near an existing wellbore. So far we have discussed what actions could lead to kick. Now lets consider what warning signs can be observed from the rig to indicate that a kick has been taken.

It is very important to rapidly detect and shut-in a kick. Rapid response reduces the kick volume and leading to lower casing pressures and a better chance of successfully and safely removing the influx. This example illustrates why we use trip tanks. When tripping out of the hole, the trip tank is used to properly fill the hole to maintain hydrostatic pressure.

The above example shows that if 15 joints of 8 collars are pulled from the well without filling the hole, the fluid level in the well will drop and reduce the hydrostatic pressure at 1300-ft by 0.5 ppg equivalent. This reduced hydrostatic pressure could allow formation fluids to enter the wellbore. The metal volume of the pipe being pulled can be calculated, but mud additions necessary to replace hole seepage losses due to filtration effects can only be predicted by comparison to the mud volumes required to keep the hole full on previous trips. For this reason, it is imperative that a record of mud volume required versus number of stands pulled be maintained on the rig in a trip book for every trip

If the hole isnt taking the correct amount of mud while using a trip tank, the additional volume could be coming from the well. Conduct a flow check. Flow positive: Strip to bottom Flow negative: Trip to bottom, circulateAnother piece of required rig equipment that is helpful in kick detection is a pit volume totalizer (PVT). The PVT is a device that measures changes in the pit volume. If a kick is coming into the annulus, the mud in the annulus will be driven into the mud pits. This will cause an increase in pit volume which will be detected by the PVT.

The PVT has pre-set alarms that will activate if a given pit gain (not to exceed 5 bbls) is observed.

Details on this device can be found on pg. 8-13 of Surface BOPE manual, but the main points are summarized below:Required in all steel tanks Floats must be checked to ensure full range of motionRecorder and dial indicators required in driller's consoleAudible and visual alarms set to pre-set limit(not to exceed 5 bbls)on drillers console.The most sensitive indicator of an influx is the return flow rate from the annulus. If the flow rate out of the well is greater than the flow rate into the well, then the additional flow must be coming from the well - KICK

This is the most sensitive indicator; first alert. Flow meters are required to be placed in the flow line to measure return flow rate.

Details of flow meters can be found on WCS Chapter 1 3 Blowout Prevention manual. Below is a summary of the requirements for flow meters:Required on every well - dial and recorder on drillers consoleAudible and visual alarms with pre-set limits required at Drillers console and second consoleInstalled upstream of the trip tank return line to permit use during trips.If drilling ROP suddenly increases, this can be an indicator of being underbalanced. When underbalanced conditions are encountered the net force on the cuttings is up the wellbore. This improves the cuttings transport in the bottom of the well and eliminates cuttings hold-down. Since the cuttings are not forced to the bottom of the hole, they are not re-ground by the bit. Consequently, the ROP is increased.

It is important to note that all drilling breaks are not kicks. Other factors such as changes in lithology, rotary speed, bit weight can affect ROP. However, if all things are constant, increased ROP is an indication of a possible kick or a change in formation pressure (closer to balance conditions).

If an unexpected drilling break is encountered, a flow check should be conducted.Changes in the pump speed or pressure is another indicator of a kick. When a lighter weight fluid (oil or gas) enters the annulus, the pump will suddenly be pushing against less resistance (lower hydrostatic pressure in the annulus).

This reduced pump resistance could lead to an increase in pump speed and decrease in pump pressure.

The pump pressure will decrease because the mud in the drillpipe will U-tube around to the annulus. If the gas units measured at the surface increase, this could be an indication that a gas kick may have been taken. As with rapid drilling of a gas sand, increased gas in the annulus can expand and reduce the hydrostatic pressure in the annulus leading to another influx.

If an unexpected increase in gas units is observed, a flow check should be conducted.

The causes and warning signs for kicks have been summarized and explained.

It is very important to be constantly aware of the warning signs while on the rig. Early detection, recognition, and shut-in is critical to the safe and effective handling of an influx.

By looking for the warning signs, a kick can be detected early and circulated from the wellbore with lower casing shoe and surface pressures.

3 causes jfhjhgjwarnings

Documents