wellcontrol_v2-1

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BLOW OUT PREVENTION

&

WELL CONTROL

Version 2.1

March 2001

Dave Hawker

Corporate Mission

To be a worldwide leader in providing drilling and geological monitoring solutions to the oil and gas industry, by utilizing innovative technologies and delivering exceptional customer service.

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1 INTRODUCTION

Many problems can be encountered when drilling wells, especially in areas previously unexplored. Most problems can be considered an inconvenience that cost operating time, and therefore money, to resolve. Kicks and blowouts are also costly in terms of time, but unlike most other problems, they are unique in that they provide a direct threat to the safety of the drilling rig and it’s personnel.

It is therefore very important that anyone involved in the monitoring of the well is fully able to recognize any and all of the signs that could indicate that a kick is taking place downhole. Early identification of such an event, allowing the driller to close in the well at the earliest opportunity, will make for a safer well control procedure and reduce the danger to rig and personnel.

In addition, for the mud logging engineer, it is very important to understand the theories and procedures involved in a well control situation, in order to assist and support the operation.

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2 PRESSURE GRADIENTS

Whatever the particular method of it’s occurrence, a kick occurs when the formation pore fluid pressure exceeds the balancing pressure in the annulus. This can lead to an influx of the formation fluids into the annulus, and thus, a kick that has to be controlled. Well control then consists, essentially, of removing the influx and restoring well balance so that annular pressure exceeds formation pressure.

During this process, while the well is closed, it is vital to ensure that the pressures in the annulus do not fracture the weakest formation in the open hole. If this was to happen while a kick is taken place, then a blowout has occurred and this is the most difficult and dangerous of all drilling problems, and one that can lead to the loss of rig and personnel.

For effective well control, it is therefore important to have a good understanding of the formation pressures involved and the annular pressures acting against them.

2.1 Formation Related Pressures

Overburden Pressure The pressure exerted, at a given depth, by the accumulated weight of overlying sediments. It is therefore a function of both rock matrix and pore fluid.

Formation Pressure The pressure exerted by the fluid contained in the pore spaces of rocks. It is therefore equivalent to hydrostatic pressure of the regional formation fluid; the pressure exerted by the vertical column of formation fluid(s). Fracture Pressure The maximum pressure a formation can sustain without failure

occurring. The weakest plane of formations is typically horizontal.

OVERBURDEN STRESS

Mud Hydrostatic

Pressure

Formation Pore

Fluid

Pressure

Fracture

Pressure

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2.2 Wellbore Balancing Pressures

Mud Hydrostatic Pressure The pressure exerted by the weight of a vertical column of static drilling fluid or mud.

Equivalent Circulating Density Although expressed in terms of equivalent mud weight, this is actually an increase in annular pressure caused by the frictional pressure losses resulting from mud circulation.

Swab Pressure This is a reduction in annular pressure caused by the frictional pressure losses resulting from the mud movement caused when the drillstring is lifted. It will lead to an influx if the annular pressure is reduced below the formation pressure.

Surge Pressure Increase in annular pressure resulting from the frictional pressure surges when the drillstring is run in hole. It can lead to formation breakdown if the surge pressure exceeds the fracture pressure.

If the formation pressure exceeds the balancing annular pressure >>>

KICK

If the annular pressure exceeds the fracture pressure >>>

FRACTURE

Mud weight must therefore be selected so that it is high enough to balance the formation pressure and prevent a kick, but it cannot be so high that it would cause a shallower, weaker, formation to fracture. This could lead to losing circulation of fluids at the shallower depth, while kicking from a deeper formation. This is an underground blowout.

Vertical

Depth

Pressure

Overburden (OBG)

Fracture (Pfrac)

Mud Hydrostatic

Formation (FP)

ECD

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The “annular pressure” is therefore key to well balance and control. It is dependent on the mud weight although this “static” pressure can be increased or decreased in certain situations: -

• Lifting pipe causes swabbing which reduces annular pressure.

• Running pipe causes a pressure surge, which increases annular pressure.

• Circulating increases annular pressure.

Formation related pressures are typically quoted in terms of “equivalent mud weight” (emw), since this provides a convenient way of “visualizing” pressures exerted downhole.

2.2.1 Mud Hydrostatic

Hydrostatic Pressure is defined as the pressure exerted at a given depth by the weight of a static column of fluid.

It therefore follows, that when a given drilling fluid, or mud, fills the annulus, the pressure at any depth is equal to the Mud Hydrostatic Pressure.

At any depth: -

HYDmud = mudweight x TVD x g

PSI = PPG x ft x 0.052 KPa = kg/m3 x m x 0.00981 PSI = SG x feet x 0.433

PSI = pounds per square inch

ppg = pounds per gallon

KPa = kilo Pascals

SG = specific gravity (gm/cc)

This will tell us the balancing pressure, in the wellbore, when no drilling activity is taking place and the mud column is static.

As soon as any movement of the mud is initiated, then frictional pressure losses will result in either an increase, or decrease, in the balancing pressure, depending on the particular activity, which is taking place.

At all times, it is important to know what the annular balancing pressure is, and the relationship with the “lithological” pressures acting against them: -

• If formation pressure is allowed to exceed the wellbore pressure, then formation fluids can influx

into the wellbore and a kick may result.

• If the wellbore pressure is allowed to exceed the fracture pressure, then fracture can result,

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2.2.2 Equivalent Circulating Density

During circulation, the pressure exerted by the “dynamic” fluid column at the bottom of the hole increases (and also the equivalent pressure at any point in the annulus). This increase results from the frictional forces and annular pressure losses caused by the fluid movement.

Knowing this pressure is extremely important during drilling, since the balancing pressure in the wellbore is now higher than the pressure due to the static mud column.

Higher circulating pressure will result in: -

• Greater overbalance in comparison to the formation pressure

• Increased risk of formation flushing

• More severe formation invasion

• Increased risk of differential sticking

• Greater load exerted on the surface equipment

The increased pressure is termed the Dynamic Pressure or Bottom Hole Circulating Pressure (BHCP).

BHCP = HYDmud +

∆∆∆∆

Pa

where ∆ Pa is the sum of the annular pressure losses

When this pressure is converted to an equivalent mudweight, the term Equivalent Circulating Density is used.

ECD = MW + ∆∆∆∆ Pa

(g x TVD)

PPG = PPG + (PSI / (ft x 0.052))

KPa = kg/m3 + (Kpa / (m x 0.00981))

The weight of drilled cuttings also needs to be considered when drilling. The weight of the cuttings loading the annulus, at any time, will act, in addition to the weight of the mud, to increase the pressure at the bottom of the hole.

Similar to the increase in bottom hole pressure when circulating (ECD), pressure changes are seen as a result of induced mud movement, and resulting frictional pressures, when pipe is run in, or pulled out, of the hole.

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2.2.3 Surge Pressures

Surge Pressures result when pipe is run into the hole. This causes an upward movement of the mud in the annulus as it is being displaced by the drillstring (as seen by the mud displaced at surface into the pit system), resulting in frictional pressure.

This frictional pressure causes an increase, or surge, in pressure when the pipe is being run into the hole. The size of the pressure increase is dependent on a number of factors, including the length of pipe, the pipe running speed, the annular clearance and whether the pipe is open or closed.

In addition to the frictional pressure, which can be calculated, it is also reasonable to assume that fast downward movement of the pipe will cause a shock wave that will travel through the mud and be damaging to the wellbore.

Surge pressures will certainly cause damage to formations, causing mud invasion of permeable formations, unstable hole conditions etc.

The real danger of surge pressure, however, is that if it is too excessive, it could exceed the fracture pressure of weaker or unconsolidated formations and cause breakdown.

It is a common misconception, that if the string is inside casing, then the open wellbore is safe from surge pressures. This is most definitely not the case! Whatever the depth of the bit during running in, the surge pressure caused by the mud movement to that depth, will also be acting at the bottom of the hole.

Therefore, even if the string is inside casing, the resulting surge pressure, if large enough, could be causing breakdown of a formation in the open wellbore. This is extremely pertinent when the hole depth is not too far beyond the last casing point!

Running casing is a particularly vulnerable time, for surge pressures, due to the small annular clearance and the fact that the casing is closed ended. For this reason, casing is always run at a slow speed, and mud displacements are very closely monitored.

2.2.4 Swab Pressures

Swab Pressures, again, result from the friction caused by the mud movement, this time resulting from lifting the pipe out of the hole. The frictional pressure losses, with upward pipe movement, now result in an overall reduction in the mud hydrostatic pressure.

The mud movement results principally from two processes: -

1. With slower pipe movement, an initial upward movement of the mud surrounding the pipe may result. Due to the mud’s viscosity, it can tend to “cling” to the pipe and be dragged upward with the pipe lift.

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2. More importantly, as the pipe lift continues, and especially with rapid pipe movement, a void space is left immediately beneath the bit and, naturally, mud from the annulus will fall to fill this void.

This frictional pressure loss causes a reduction in the mud hydrostatic pressure. If the pressure is reduced below the formation pore fluid pressure, then two things can result: -

1. With impermeable shale type formations, the underbalanced situation causes the formation to fracture and cave at the borehole wall. This generates the familiar pressure cavings that can load the annulus and lead to pack off of the drill string.

2. With permeable formations, the situation is far more critical and, simply, the underbalanced situation leads to the invasion of formation fluids, which may result in a kick.

In addition to these frictional pressure losses, a piston type process can lead to further fluid influx from permeable formations. When full gauge tools such as stabilizers are pulled passed permeable formations, the lack of annular clearance can cause a syringe type effect, drawing fluids into the borehole.

• More than 25% of blowouts result from reduced hydrostatic pressure caused by swabbing.

• Beside the well safety aspect, invasion of fluids due to swabbing can lead to mud contamination and

necessitate the costly task of replacing the mud.

• Pressure changes due to changing pipe direction, eg during connections, can be particularly damaging

to the well by causing sloughing shale, by forming bridges or ledges, and by causing hole fill requiring reaming.

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3 KICKS AND BLOWOUTS

3.1 Definitions

What is a kick? An influx of formation fluid into the wellbore that can be controlled at surface.

What criteria are necessary for a kick to occur?

1. The formation pressure must exceed the wellbore or annular pressure. Fluids will always flow in the direction of decreasing or least pressure. 2. The formation must be permeable in order for the formation fluids to

flow.

What is a blowout? A flow of formation fluids that cannot be controlled at surface.

What is an underground blowout?

An underground blowout occurs when there is an uncontrollable flow of fluids between two formations. In other words, one formation is kicking while, at the same time, another formation is loosing circulation.

What is a surface blowout? A surface blowout occurs when the well cannot be shut in to prevent the flow of fluids at surface.

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3.2 Causes Of Kicks

Not keeping the hole full when tripping out of hole

When pipe is pulled from the hole, mud must be pumped into the hole to replace the steel volume removed. If not, the mud level in the hole will drop, leading to a reduction in the overall mud hydrostatic pressure. Keeping the hole full is extremely critical when pulling drill collars owing to the large steel volume.

Reducing annular pressure through swabbing

Frictional forces resulting from the mud movement caused by lifting pipe, reduce the annular pressure. This is most critical at the beginning of a trip when the well is balanced by mud hydrostatic and when swab pressures are greatest.

Lost circulation

If drilling fluid is being lost to a formation, it can lead to drop in mud level in the wellbore and reduced hydrostatic pressure.

Excessive ROP when drilling through gaseous sands

If too much gas is allowed into the annulus, especially as it rises and starts expanding, it will cause a reduction in the annular pressure.

Underpressured formations

May be subject to fracture and lost circulation which could result in a loss of hydrostatic head in the annulus.

Overpressured formations

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3.3 Kick Warning Signs

Before an influx or kick actually occurs, there are a number of signs and indications that can give possible warnings that conditions exist for such an event to occur or, indeed, that such an event is about to take place.

Lost circulation zones Large surge pressures should result in closer attention to possible signs of fracture and lost circulation.

Weaker, fractured formations may be identified by higher ROP’s and higher, erratic torque

Reduced mud returns, identified from a reduction in mud flow and decreasing pit volume, indicate a loss of fluids to the formation.

Transitional zones Increasing ROP and decreasing drilling exponent trend. Increasing gas levels.

Appearance of connection gas.

Hole instability indications, tight hole, drilling torque, overpull and drag. Increasing mud temperature.

Increased cuttings volume, cavings, reduced shale density.

Sealed overpressured bodies Immediate drill break resulting from the pressure differential and the higher porosity.

A Drill Break should always be Flow Checked, in order to determine whether it is

associated with an overpressured zone and possible influx.

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3.4 Indications Of Kicks While Drilling

The following influx indicators are listed in the typical order that they would become apparent by surface measurements.

• Gradually decreasing Pump Pressure

There may also be an associated increase in the Pump Rate.

The drop in pump pressures as a direct result of lower density formation fluids entering the wellbore, reducing the overall mud hydrostatic.

The pressure drop will be most significant with gas and worsened as gas expansion takes place. Initial pressure drop may be slow and gradual, but the longer the kick goes undetected, the more “exponential” the drop in pressure.

• Increased mud flow from annulus, followed by…..

• An associated increase in mud pit levels

As formation fluids enter the borehole, an equivalent volume of mud will, necessarily, be displaced from the annulus at the surface. This is in addition to the mud volume being circulated so that the mud flow rate will show an increase.

In the case of a gas influx, mud displacement will increase dramatically as gas expansion takes place

As the influx continues…….

• Variations in Hookload/WOB

Although certainly not a primary indicator, these indications may be seen as the buoyancy effect on the string is modified.

If the influx reaches surface….

• Contaminated mud, especially gas cut Reduced mud density.

Change in chloride content (typically increase). Associated gas response.

Pressure indicators such as cavings, increased mud temperature.

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3.4.1 Connection Gas

Connection gases are an extremely accurate indication of increasing formation (and therefore a warning of a possible kick) resulting from a temporary underbalance in the wellbore.

The connection gas will appear as a short duration, sharp gas response, one “bottoms-up” time after the pumps are restarted following the connection.

This temporary underbalance can result as follows:

• A pressure reduction (to the ECD) due to

swabbing when the pipe is lifted.

• A reduction to mud hydrostatic when pumping

is stopped and the string is set in slips.

• A piston type suction from full gauge tools such

as stabilizers and bit, as they are pulled passed permeable formations.

Swabbing results when, initially, mud is lifted with the string, due to it’s viscosity. The mud movement results in frictional pressure loss that reduces the annular pressure. This occurs for the entire length of drillstring. In addition, mud movement also results from it “dropping” to fill the void left by the pipe as it is lifted.

If Annular Pressure < Formation Pressure, then an influx can result

The pressure reduction caused through swabbing increases with:

• Pipe pulling speed

• Length of drillstring

• Mud viscosity

• Smaller annular clearance

An influx can occur from anywhere in the open hole if a formation is permeable and is brought into a condition of underbalance.

However, connection gases are most likely to be generated from the bottom of the hole:

• This is where the pressure drop is greatest

• Here, there is the smallest annular clearance with the BHA and drillcollars, as opposed to drill pipe.

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Connection gas can also be produced from impermeable shales through fracture and caving (left), rather than through influx as with permeable formations. As cavings are generated from the borehole wall, porosity is exposed and, in the process, gas is released.

Connection gases then, clearly indicate an influx of formation fluids when annular pressure is reduced temporarily. Once connection gas is recorded, subsequent connections should be very closely monitored for signs of increasing pressure and/or increased swabbing. An increasing trend could indicate that the well is getting closer and closer to balance and that a kick may eventually result, rather than a temporary influx.

This reduction in differential pressure may result from:

• Increasing formation pressure

through a transition zone, OR

• A reduction in annular pressure as

more gas, through increased swabbing, is allowed into the annulus.

If background gases and connection gases are increasing, the mud weight should certainly be increased to bring the well back on to balance.

Impermeable

Permeable

FP > Phyd

Increase in Liberated Gas

Produced Gas

CG

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3.5 Indicators While Tripping

• Insufficient Hole Fill

When tripping out of hole, the hole is not taking enough mud fill to compensate for the pipe volume that has been pulled from the hole. This may indicate that:

A kick has been swabbed into the hole, or that… Mud is being lost to the formation

• A “wet trip”

Where the influx and pressure, beneath the string, prevents mud from draining from the string as it is lifted.

• Swabbing

Excessive swabbing can be identified through the change in trip tank volume as individual stands of pipe are being lifted. The trip tank may be seen to initially gain mud before the mud level drops in the hole to allow fill to take place.

• Pit Gain

A continual increase in trip tank level clearly shows that a kick is taking place.

• Mud Flow

Similar, mud flowing at surface indicates an influx.

Flow may also result from swabbed fluids that are migrating and expanding in the annulus. This in itself, may be sufficient to reduce hydrostatic further to allow an influx to take place.

• Hole Fill

Excessive hole fill (at the bottom of the hole) after a trip may show caving from an overpressured or unstable hole.

• Pinched Bit

A warning rather than an indicator, a pinched bit may be an indication of tight, under-gauged hole resulting from overpressure.

Every precaution (i.e. monitoring the well before pulling out, minimizing swabbing, flow

checks) is taken to avoid taking a kick during a trip:

• Well control is more difficult if the bit is out of the hole or above the depth of influx.

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3.5.1 Trip Margin

The pressure reduction through swabbing is critical when tripping pipe (in comparison to that seen over a connection), since:

• The balancing pressure is the static mud hydrostatic rather than the higher ECD.

• There is repeated swabbing as each stand is pulled.

• The “piston” effect affects every permeable formation in open hole.

The pressure reduction can be minimized by:

• Pulling the drillstring at a slower speed.

• Keeping mud viscosity as low as possible (bearing in mind that hole cleaning and cuttings lift

properties have to be maintained while drilling).

A safety, or trip, margin can be calculated to ensure that the pressure reduction does not create an underbalance:

A graph can be produced that shows, for a given well profile, mud system, etc, the pressure losses (Y) that would result for a given length of drillstring being pulled at various running speeds (X).

From this graph:

• For a given running speed, the additional mudweight to provide a specific trip margin over the

formation pressure can be determined.

• For a given overbalanced situation, the maximum running speed can be determined in order to

avoid creating an underbalance.

Running Speed

Pressure

Reduction

Y KPa

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Example:

A change in formation is anticipated at 3400m. What mudweight will be required in order to provide a 500Kpa trip margin. The estimated formation pressure is 1045 kg/m3 emw.

Formation Pressure = 1045 x 3400 x 0.00981 = 34855 KPa BHP required = 34855 + 500 = 35355 KPa

MW = 35355 / (3400*0.00981) = 1060 kg/m3

If the mud weight is now set at 1060 kg/m3, the swab/surge software can be used to determine the maximum pipe running speed, so as to avoid exceeding a 500KPa pressure drop.

In this way, even with swabbing occurring, the annular pressure is never reduced below the formation pressure.

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3.6 Gas Expansion

Boyle’s Law states that the relationship between pressure, volume, and temperature (PV/T) is a constant. Gas bubbles expand as they are circulated up the annulus and the mud hydrostatic pressure (which is acting against the bubbles) decreases.

As the vertical depth is halved, so too is the mud hydrostatic pressure. Correspondingly, as given by Boyle’s Law, the gas bubbles double in size.

When using water base mud systems, methane gas will typically be present as free gas, rather than dissolved gas (At STP, maximum C1 in solution is 3%).

There will therefore be increased expansion as a gas influx moves up the annulus:

To illustrate how significant this gas expansion can be, assume that ½ m3 (500 litres) of gas enters the borehole at 4000m. At…. 2000m V = 1 m3 1000m V = 2 m3 500m V = 4 m3 250m V = 8 m3 125m V = 16 m3 60m V = 32 m3

D

D/2

D/4

D/8

V

4V 8V

depth

gas volume

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However, oil base muds (approx 10% soluble C1 at STP), and worse still, mineral oils (~15%), have much higher bubble points, so that gas bubbles may not appear until the influx is very close to surface.

Therefore, SPP, MFO and pit level indicators may not be significant until the influx is close to, or at surface where expansion may be almost immediate as gas breaks out of solution.

It becomes very important to try to identify the influx itself from a small volume change

3.7 Flowchecks

A flow check, to determine whether the well is static or is flowing, is normally conducted in one of two ways:

• By actually looking down through the rotary table, into the wellhead, and visually determining if

the well is flowing.

• By lining the wellhead up to the trip tank and monitoring the level for any change.

They are typically conducted at the following occasions:

• Significant drill breaks

• Any kick indication while drilling, especially changes in mud flow

• Prior to slugging the pipe before pulling out of hole

• After the first few stands have been pulled, to check that swabbing has not induced flow.

• When the bit is at the shoe

• Prior to pulling drill collars through the BOP’s

• Constant monitoring (trip tank) while out of the hole

If the well is flowing, the well will be shut in

Gas in solution,

no expansion

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4 KICK CONTROL EQUIPMENT

4.1 The BOP Stack

To prevent the occurrence of a blowout, there needs to be a way of closing, or sealing off the wellbore, so that the flow of formation fluids remains under control. This is achieved by the Blow Out Prevention system (BOP), an arrangement of preventers, valves and spools that is positioned on top of the wellhead. Commonly referred to as the stack, it’s purpose is to: -

• Seal off the well so that the flow of formation fluids is under control.

• Prevent fluid from escaping to surface.

• Allow the release of fluids, from the well, under controlled conditions.

• Allow drilling fluid to be pumped into the well under controlled conditions to balance formation

pressure and prevent further influx.

• Allow movement of the drillstring in or out of the well

The size and arrangement of the BOP stack will be determined by the hazards expected and the protection required, together with the size and type of pipe being used. BOP’s have various pressure ratings established by the American Petroleum Institute (API). This will be based on the lowest pressure rating of a particular item in the stack, such as a preventer, casing head or other fitting. A suitably rated BOP can therefore be installed depending on the rating of the casing and the expected formation pressures below the casing seat. BOP’s commonly have ratings of 5, 10, or 20,000 psi.

The requirements for a BOP stack are as follows: -

• There must be sufficient casing to provide a firm anchor for the stack.

• It must be able to close off and seal the well completely, with or without string in the hole.

• It must have a simple and rapid shut in procedure.

• It must have controllable lines through which to bleed off pressure.

• It must provide the ability to circulate fluids through both the string and the annulus.

• There must be the ability to hang or shear pipe, shut in a subsea stack, detach the riser and

abandon the location.

• Subsea stacks cannot be affected by the lateral movement of the riser caused by current

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4.2 Preventers and Rams

These are the names applied to the various “packers” that can be closed to seal the wellhead. A small BOP arrangement for a shallow land well is shown below.

4.2.1 Annular Preventer

This, simply, is a reinforced packer (rubber seal) that surrounds the wellbore.

It can close around pipe, of any size, when pressure is applied, thus closing off the annulus. With increasing pressure, it will close around pipe of any diameter, including drillpipe, smooth collars and kelly.

However, it cannot be used on irregularly shaped pipe, or tools such as spiral drillcollars or stabilizers.

It allows slow rotation and vertical movement of the pipe while the well remains sealed off.

Tripping into the hole with closed annular preventer is known as snubbing.

Pulling out of the hole while the annular preventer is closed is known as stripping.

An annular preventer can also close across an open wellbore when there is no pipe in the hole.

Annular

preventer

Ram preventers

Manual closure

possible on land

rigs and jack ups

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4.2.2 Ram Preventers

Ram Preventers have a more rigid rubber seal that fits around specific, pre-designated shapes.

Pipe/Casing Rams Here, the rubber seals match, exactly, tubing of specific diameter, so that the annulus is completely sealed off with pipe in the hole.

The BOP stack must therefore include pipe rams for each size of pipe in the hole.

Blind/Shear Rams Blind or shear rams are used to close off an open annulus, i.e. when there is no pipe in the hole.

If there is pipe in the hole, the blind rams will crush it when closed. When equipped with shear blades, the pipe will be cut. These are more typical in subsea stacks so that pipe can be held by pipe rams, and cut through by shear rams allowing the rig to abandon location.

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4.3 Stack Configuration

The annular preventer is always positioned on top of the BOP stack.

The positioning of the various rams, and lines, is dependent on the expected operations. The following summarizes the benefits/disadvantages of positioning the blind, or shear, rams beneath, or above, the pipe rams.

• Lower blind rams

The well can be shut in to allow other rams to be repaired or changed i.e. used as a master valve. The string cannot be hung off on pipe rams.

• Upper blind rams

The string can be hung from pipe rams, backed off and then the well shut in by the blind ram.

Pipe rams can be closed with pipe in hole and blind rams replaced with pipe rams. This will minimize wear and also allow ram to ram stripping of the pipe.

Simple BOP stack schematic

Casing Head

Pipe Ram

Blind/Shear

Annular

preventer

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4.4 Subsea Equipment

BOP

Stack

Lower Marine

Riser Package

Temporary and Permanent Guidebases

Marine Riser, Choke and Kill Lines

Pipe and

Shear Rams

Annular Preventer,

often two

Ball/Flex Joint

Flex lines or loops

(Choke + Kill)

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4.4.1 Lower Marine Riser Package

Flexible lines

connecting

to choke/kill

Flex/Ball

Joint

Riser Connection

Annular

Preventor

Control Pod

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4.5 Choke Manifold

Following a kick and shut in, back pressure is applied, in order to balance the well, by routing returns through adjustable chokes. Release of fluids and pressure can therefore be controlled safely.

A soft shut-in is where the choke is open before the rams are closed, in order to minimize the shock exerted on the formation.

A hard shut-in is where the choke is closed prior to shut in.

The chokes are connected to the BOP stack through a series of lines and valves that provide a number of different flow routes and the ability to stop fluid flow completely. This arrangement is known as the choke manifold.

Again, there are specific requirements for the choke manifold:

• The manifold should have a pressure capability equal to the rated operation pressure of the BOP

stack (equal to the weakest component).

• The choke line connecting the manifold to the stack should be as straight as possible and firmly

anchored.

• Alternative flow and flare routes should be available downstream of the choke line in order to

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4.5.1 Choke and Kill Lines

Choke lines are typically used to release fluids from the annulus.

Kill lines are typically used to pump mud into the wellbore if it is not possible through the drillstring.

The placement or configuration of the rams determines the positioning of the kill lines. They will be placed directly beneath one or more of the rams, so that when the rams are closed, fluid and pressure can

be bled off under control (choke line).The choke line is routed to the choke manifold where pressures can

be monitored. An adjustable choke allows for the ‘back pressure’ being applied to the well to be adjusted in order to maintain control.

They also allow for an alternative way of pumping drilling mud or cement into the wellbore, should it not be possible to circulate through the kelly and drillstring (kill line). The kill line will normally be lined up to the rig pumps, but a ‘remote’ kill line may often be employed in order to use an auxiliary, high-pressure, pump.

Although preventers may have side outlets for the attachment of choke and kill lines, separate drilling spools are often used. This is a drill-through fitting that fits between the preventers creating extra space (which may be required in order to hang off pipe and have enough room for tool joints between the rams) and allowing for the attachment of the kill lines.

On floating rigs, when the BOP stack is on the seabed, the choke and kill lines are attached to opposite sides of the marine riser. The lines have to flexible at the top and the bottom of the riser to allow for movement and heave.

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4.6 Closing the Preventers

Preventers are closed hydraulically with fluid supplied under pressure. Manual closure is possible if the stack is accessible.

There are three main system components to close the preventers: - 1. Pressure source

2. Accumulators 3. Control manifold.

4.6.1 Pressure source

• The hydraulic fluid must be supplied under sufficient pressure to close the rams.

• Electric or pneumatic pumps are usually used to deliver the hydraulic fluid under said pressure.

• In addition, there should always be backup pumps and an alternative source of electricity or air to

power them.

4.6.2 Accumulators

Accumulator bottles are a series of pre-charged nitrogen bottles that store and supply the hydraulic fluid, under pressure, necessary to close the preventers

• Different preventers have different operating pressures and require different volumes of hydraulic

fluid in order to function.

• The total volume of hydraulic fluid required to operate the entire stack must be known.

• Accumulator bottles are linked together in order to store the necessary volume.

• The bottles are pre-charged with nitrogen (typically 750 - 1000 psi).

• Hydraulic fluid is pumped into the bottles, compressing the nitrogen and increasing the pressure

in the bottle.

• This operating pressure (minimum typically 1200psi, maximum typically 3000psi) determines the

amount of hydraulic fluid available from each bottle and therefore the total number of bottles required.

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A Pre-charge P = 1000psi V = 40litres

B Maximum Fluid Charge P = 3000psi N2 volume = (1000*40)/3000 = 13.33litres C Minimum Operating Pressure P = 1200psi N2 volume = (1000*40)/1200 = 33.33litres

Therefore, usable hydraulic fluid, per bottle, is 20litres

4.6.3 Control manifold

This is basically the well control operations center.

The control manifold directs the flow of hydraulic fluid to the correct ram or preventer. Regulators reduce the pressure from the accumulator operating pressure to the preventer operating pressure, typically 500-1500psi. The master control panel is typically situated in the doghouse, with a second panel in another safe area.

Typically, pneumatic operation is used to open and close preventers, choke and kill lines and to monitor and regulate pressures.

(32)

Subsea stacks require slightly different operation from the control panel, in that: -

• They also require signal or pilot lines in addition to hydraulic fluid lines.

• Subsea regulators and valves control the flow and pressure of hydraulic fluid upon receiving the

(33)

4.7 Diverters

The diverter is a low pressure system installed beneath the bell nipple and flow line assembly to direct well flow away from the rig and personnel.

They are typically employed prior to installing a BOP stack in order to provide safety in the event of shallow gas being encountered.

They are essential in offshore drilling, but the diverter system is only designed to handle low pressures. It is designed to pack off, or close around, the Kelly or drillpipe and direct fluid flow away. If it were attempted to be control high pressures, or completely shut in the well, the likely result would be failure and uncontrolled flow, with the breakdown of formations around the shallow casing or conductor pipe. Typically, two diverter lines are installed and, in the event of a kick: -

• One or both diverter lines will be opened

• A packer is closed around the drillpipe, or Kelly, in order to close off the annulus

• Gas will then be directed away from the rig until it loses pressure

Response must be quick since, with shallow gas, there is little hydrostatic head and gas will quickly blowout at surface. One vent line must be open before closing the packer, in order to prevent gas from blowing out around conductor pipe.

This schematic shows a typical installation for drillships and semi-submersibles.

It is mounted to the drill floor sub-structure at the top of the marine riser assembly.

Relative motion between the BOP stack and the rig is accounted for by a flex/ball joint positioned above the stack.

A second flex/ball joint may be installed between the diverter and the riser’s telescopic joint.

Seabed

Ram preventers

LMRP

Annular preventer

Marine Riser

Diverter assembly

Rig Structure

(34)

4.8 Inside Blowout Preventors

This refers to equipment that can be used to close off the drillstring in order to provide additional control. They may be manual shut off valves that can be inserted into the string at the surface, or they may be automatic check valves actually located inside the drillstring downhole.

There are slight differences in the equipment depending on the rotary system of the rig: -

4.8.1 Kelly Rigs

Upper kelly valve or cock This valve is positioned between the kelly and the swivel, in order to

isolate drilling fluid in the drillstring.

Lower kelly valve or cock This is installed at the base of the kelly and will most likely be used if the

upper kelly valve is damaged or inaccessible.

Safety valve This is actually identical to the lower kelly valve. Rather than being

installed as part of the string, it is kept on the rig floor in order to be quickly “stabbed” into the top of the drillpipe should a kick occur during a trip when the kelly is racked.

4.8.2 Top Drive Rigs

Top drives utilize an Upper Remote Safety Valve and a Lower Safety Valve, the two valves connected together.

• The upper valve is operated remotely, since the top drive location is likely to be inaccessible

(height) should a kick take place.

The advantage of this arrangement is that kick protection is immediately available should a kick occur during a trip.

(35)

4.8.3 Additional Preventers

Inside BOP This is a check valve that is used to close off the top of the drillpipe. It allows the string to be stripped into the hole, under pressure, in the event that a kick occurs when the string is off bottom.

It is physically difficult to stab the valve against mud flow from the drillpipe, so a safety valve is usually installed first.

Drop In Check Valve This valve is actually pumped or dropped into the drillpipe, setting itself in a landing sub situated in or close to the BHA.

Some models can be retrieved on wireline, otherwise, the drillstring has to pulled out to retrieve the valve.

They are typically used in stripping operations.

If abandoning location offshore, they must be deployed prior to shearing the pipe.

Float Valve This check valve is installed in the bit sub to prevent backflow of mud through the drillstring.

Simple models are one-way valves, which prevent pressures being transmitted as well as fluid flow. Unfortunately, this results in the disadvantage that the shut in drillpipe pressure would not be known. A “slotted” or “vented flapper” type minimizes backflow but allows for stabilized shut in pressure to be recorded.

(36)

4.9 Rotating Preventers

These may be known as rotating heads, or rotating BOP’s.

• They are mounted on top of the standard

BOP stack and act as a rotating flow diverter.

• This allows rotation and vertical movement

of the drillstring at the same time that a rubber stripper seals around, and rotates with, the pipe or kelly.

• Mud flow is therefore contained and can be

diverted away through a bowl and bearing assembly.

• Annular pressures up to 3500psi can be

controlled with such equipment.

• Applications include underbalanced

drilling applications and even facilitating the drilling with high pressures while well is flowing.

While well pressures are contained by the rubber seal around the drillstring or kelly, flow is diverted by way of a steel bowl and bearing assembly. The bearing assembly enables the inner part to rotate with the drillstring while the outer part is stationary with the bowl.

Seals are typically of two types: -

1.

A cone shaped rubber that seals around the drillstring. The inside diameter of the seal is slightly

smaller than the outside diameter of the pipe, so that the seal stretches to provide an exact seal around the pipe. No hydraulic pressure is required to complete the seal, since the pressure is provided by the actual wellbore pressures acting on the cone rubber. The rubber is therefore self-sealing, the higher the wellbore pressure the greater the seal.

2.

A packer type seal requiring an external hydraulic pressure source to inflate the rubber and

provide a seal. A seal will be given as long as the hydraulic pressure is greater than the wellbore pressure.

Kelly driver

Bearing

assembly

Bottom rubber

Bowl

Top rubber

(37)

5 FRACTURE CALCULATIONS

5.1 Leak Off Test

This is a pressure test that is typically carried out after drilling out casing/cement, prior to drilling the next hole section. There are two principle reasons for this test.

Cement Integrity Before drilling the next hole section, it is critical to determine that the cement

bond is strong enough to prevent high pressure fluids from flowing through to shallower formations or to surface.

Fracture Pressure If, as intended, the cement retains the pressure exerted during the test, then

formation fracture will occur, under controlled conditions. The formation at this depth, since it will be the shallowest in the next hole section, is assumed to be the weakest point.

The fracture pressure determined from the test will therefore be the maximum pressure that can be applied in the wellbore, without causing fracture.

Two types of test may be performed: -

A Formation Integrity Test is often performed when there is a good knowledge of the formation and fracture pressures in a given region. Rather than inducing fracture, this pressure test is taken to a pre-determined maximum pressure, one considered high enough to safely drill the next hole section.

A complete Leak Off Test leads to the actual fracture of the formation.

Procedure: -

• After drilling out the casing shoe, a small section of new formation, perhaps 10m, is drilled.

• Shut in the well

• Pump mud, at a constant rate, into the wellbore in order to increase the pressure in the annulus.

• Monitor pressure for indication that mud is injected into the formation. A linear increase will be

seen initially, with a drop in pressure occurring when leak off is reached. At this point, stop pumping.

The pressure plot against time, or mud volume pumped, shows that there are 3 principle stages to a complete Leak Off Test. It must be the operator who makes the decision as to which particular value is taken as the ‘leak off” pressure, but obviously, it should be the lowest value. This way well be the initial Leak Off Pressure, if the test hasn’t been taken further to cause complete rupture. If it has, then the Propagation Pressure is likely to be the lowest, indicating that the formation has actually been weakened as a result of the test.

(38)

With a LOT, mud is actually injected into the formation until fracture occurs. The formation is therefore weakened allowing less tolerance for the next hole section. Full Leak Off’s should be conducted on wildcat wells where no pressure/fracture information is known.

If regional pressure and fracture gradients are known, then an FIT can be conducted to a pressure that is known to be above the maximum anticipated pressure requirement during the next hole section. By not increasing the pressure to actual leak off, an FIT provides a built in safety margin against shoe fracture.

Surface

Shut In

Pressure

Mud Volume Pumped

Leak Off Pressure

Slower pressure increase - reduce pump rate as mud begins to inject into the formation

Rupture Pressure

Complete and irreversible failure has occurred when pressure drops - stop pumping

Propagation Pressure

If pumping is stopped at the point of failure, the formation may recover, but weakened

(39)

5.2 Fracture Pressure

All materials have a finite strength. Fracture Pressure can be defined as the maximum pressure that a formation can sustain before it’s tensile strength is exceeded and it fails.

Factors affecting the fracture pressure include:

Rock type

In-situ stresses

Weaknesses such as fractures, faults Condition of the borehole

Relationship between wellbore geometry and formation orientation

Mud characteristics

If a rock fractures, a potentially dangerous situation exists in the wellbore.

Firstly, mud loss will result in the fractured zone. Depending on the mud type and the volume lost, this can be extremely costly. Mud loss may be reduced or prevented by reducing annular pressure through reduced pump rates, or, more expensive remedial action may be required, using a variety of materials to try and “plug” the fractured zone and prevent further loss. Obviously, all of this type of treatment is extremely damaging to the formation and is to be avoided if at all possible.

However, if mud loss is so severe, then the mud level in the wellbore may actually drop, reducing the hydrostatic pressure exerted in the wellbore. This may result in a zone, elsewhere in the wellbore, becoming underbalanced and flowing – we now have an underground blowout!

Knowledge of the fracture gradient is therefore essential while planning and drilling a well.

The fracture pressure is determined from the leak off test performed at the casing shoe. During this test, a combination of two pressures provide the pressure, at the shoe, to cause fracture:

• The hydrostatic pressure exerted by the drilling fluid, at the shoe.

• The shut-in pressure applied

by pumping mud into a closed well…i.e. the leak off pressure.

HYD

LOP

(40)

Pfrac = HYDshoe + LOP

where Pfrac = fracture pressure

HYDshoe = mud hydrostatic at the shoe = MW x TVDshoe x constant LOP = shut-in pressure applied at surface,

whether determined from LOT or FIT

Pfrac (emw) = MW + LOP/(TVDshoe x g)

Example - imperial

A LOT is performed at a shoe depth of 4000ft TVD, and with a mudweight of 10.5 ppg. Leak off occurs when the surface shut in pressure is 1500psi.

LOP = 1500psi

HYDshoe = 10.5 x 4000 x 0.052 = 2184psi Pfrac = 2184 + 1500 = 3684psi

Pfrac emw = 3684 / (4000 x 0.052) = 17.71ppg emw

Example - metric

An FIT is performed at a shoe depth of 2500m TVD, and with a mudweight of 1035 kg/m3. The FIT is held at a surface shut in pressure of 10500 KPa.

LOP = 10500KPa

HYDshoe = 1035 x 2500 x 0.00981 = 25383 KPa Pfrac = 25383 + 10500 = 35883 KPa

Pfrac emw = 35883 / (2500 x 0.00981) = 1463 kg/m3 emw

It is very important to understand, however, that although the pressure test is the only way of determine the fracture pressure (other than actually losing circulation), there are certain circumstances that can lead to inaccuracy or unreliability: -

• A Formation Integrity Test gives no determination of actual fracture pressure, only an accepted

maximum value for the drilling operation. Although not providing accurate data, this test does provide a safety margin.

(41)

• Well consolidated formations are typically selected to set the shoe – this formation may not be the weakest if subsequent unconsolidated, or overpressured, formations are encountered within a short interval from the shoe.

• Apparent leak off may be seen in high permeability, or highly vugular formations, without

fracture actually occurring.

• Poor cement bonds may result in leak off through the cement, rather than the formation.

• Localized porosity or micro-fractures can result in lower recorded fracture pressures.

• Well geometry, in relation to horizontal or vertical stresses, can also lead to deceptive fracture

pressures, with different results being produced, in the same formations, between vertical and deviated wells.

(42)

5.3 Maximum Allowable Annular Surface Pressure

When a well has to be shut in, in order to control a kick, surface shut-in pressure is required to balance the bottom hole pressure.

At the time of shut-in, there are two pressures acting at the shoe:

• mud hydrostatic

• shut-in pressure applied from surface.

These two pressures, combined, cannot exceed the fracture pressure of the formation at the shoe (Pfrac determined from the leak off test).

i.e.

Pfrac > HYDshoe + Shut-in Pressure

MAASP is the maximum shut in pressure that can be applied without fracturing the weakest zone, assuming this is the shoe:

Pfrac = HYDshoe + MAASP MAASP = Pfrac - HYDshoe

At the time of a LOT, the MAASP is clearly equal to the Leak Off Pressure, since this is the shut-in pressure that actually causes fracture.

Example – imperial

A LOT is performed at a shoe depth of 4000ft TVD, with a mudweight of 10.5 ppg. Leak off pressure is 1500psi.

Pfrac = hyd + LOP = (10.5 x 4000 x 0.052) + 1500 Pfrac = 2184 + 1500 = 3684psi

MAASP therefore, with 10.5ppg mud, also equals 1500psi; any shut-in pressure higher than this will fracture the shoe.

MAASP will only change if mud weight changes: -

Drilled depth is unimportant, since we are dealing with weakest zone at the shoe. Of the two pressures acting at the shoe:

Mud hydrostatic only changes if the mud weight changes. Pfrac obviously does not vary.

(43)

What is the MAASP, if at 6000ft MD, mudweight has to be increased to 11.2ppg? MAASP = Pfrac - HYDshoe

= 3684 - (11.2 x 4000 x 0.052) = 1354psi

The form of this calculation will only change if a weaker zone, at a greater depth, is encountered.

Example – metric

Since Pfrac remains constant, if mudweight is increased, the MAASP has to decrease correspondingly. At the time of the leak off test, a table of mudweight versus MAASP should be constructed.

A leak off is performed at a shoe TVD of 3000m; the mudweight is 1020kg/m3 and the recorded leak off pressure is 8000 Kpa.

Pfrac = (1020 x 3000 x 0.00981) + 8000 = 38019 Kpa MAASP = Pfrac – HYDshoe

MAASP @ 1020kg/m3 = 8000 Kpa

MAASP @ 1030kg/m3 = 38019 - (1030 x 3000 x 0.00981) = 7706KPa MAASP @ 1040kg/m3 = 38019 - (1040 x 3000 x 0.00981) = 7412KPa MAASP @ 1050kg/m3 = 38019 - (1050 x 3000 x 0.00981) = 7117Kpa

(44)

5.4 Kick Tolerance

Mud weight must, clearly, be sufficient to exert a pressure that will balance the formation pressure and prevent a kick, but it cannot be so high that the resulting pressure would cause a formation to fracture. This would lead to lost circulation (mud being lost to the formation) in the fractured zone. This, in turn, would lead to a drop in the mud level in the annulus, reducing the hydrostatic pressure throughout the wellbore. Ultimately then, with reduced pressure in the annulus, a permeable formation at another point in the wellbore may begin to flow. With lost circulation at one point and influx at another, we now have the beginnings of an underground blowout!

A critical condition exists should the wellbore has to be shut in.

While drilling, high formation pressures can be safely balanced by the mudweight. However, if a kick is taken (either through a further increase in formation pressure, or through a pressure reduction cause by swabbing, for example), then the well would have to be shut in. If the pressure caused by the mudweight is too high, then weaker formations at the shoe may fracture when the well is shut in. This situation would be worsened if higher shut-in pressures are required to balance low density influxes, especially expanding gas!

KICK TOLERANCE is the maximum balance gradient (i.e. mudweight) that can be handled by a well, at the current TVD, without fracturing the shoe should the well have to be shut in.

KICK TOLERANCE = TVDshoe x (Pfrac – MW)

TVDhole

Where Pfrac = fracture gradient (emw) at the shoe

MW = current mudweight

If the mudweight, that is required to balance the formation pressures while drilling, would result in shoe fracture during well shut in, then a deeper casing shoe (with greater fracture pressure) must be set.

In order to account for a gas influx, the formula is modified as follows: -

KT =

[TVDshoe x (Pfrac – MW)] - [influx height x (MW – gas density)]

TVDhole

(45)

The method illustrated is based on three criteria:

• A maximum influx height and volume (zero kick tolerance) – Point X

• A typical or known gas density (from previous well tests for example)

• The maximum kick tolerance (liquid influx with no gas) – Point Y

This defines limits on a graphical plot, which provides easy reference to this important parameter.

The values are determined as follows:

Maximum Height = TVDshoe x (Pfrac – MW) MW – gas density

If gas density is unknown, assume 250 kg/m3 (0.25 SG or 2.08ppg)

Maximum Influx Volume is determined from the maximum height and the annular capacities – this defines Point Y on the graph.

Maximum KT, as shown before, =

TVDshoe x (Pfrac – MW)

TVDhole

This defines Point X on the graph, a liquid influx without any gas.

The graph is completed by dividing it into the different annular sections covered by the influx, i.e. in the event that there are different drill collar sections, or if the influx passes above the drill collar section, or even if the influx passes from open hole to casing. This is necessary since the same volume of influx will have different column heights in each annular section.

(46)

Kick Tolerance, worked example Using the following well configuration:

Casing Shoe = 2000m

Hole Depth = 3000m

Pfrac at shoe = 1500 kg/m3 emw

Current MW = 1150 kg/m3

Drill Collar length = 200m

Annular Cap = 0.01526m3/m (216mm open hole, 165mm drill collars)

Annular Cap = 0.02396m3/m (216mm open hole, 127mm drillpipe)

Gas Density = 250 kg/m3

Maximum Height = TVDshoe x (Pfrac – MW) = 2000 (1500 – 1150) = 777.8m MW – gas density 1150 – 250

Maximum Volume, determined from 200m around the drill collars, and 577.8m around drillpipe:

DC = 200 x 0.01526 = 3.05m3

DP = 577.8 x 0.02396 = 13.84m3

Max Vol = 3.05 + 13.84 = 16.89m3

Maximum KT =

TVDshoe x (Pfrac – MW)

=

2000 (1500 – 1150) = 233.3 kg/m3

TVDhole

3000

Therefore, Point X = 16.7m3, Point Y = 233 kg/m3

Now, determine the ‘break point” of the graph, for the drill collar / drill pipe annular sections:

To do this, calculate the KT related to a 3.05m3 gas influx, which would reach the top of the 200m length of drill collars:

KT =

[TVDshoe x (Pfrac – MW)] - [influx height x (MW – gas density)]

TVDhole

= 2000 (1500 – 1150) - 200 (1150 – 250)

3000 3000 = 173.3 kg/m3

Therefore, 3.05m3 and 173.3 kg/m3 define the “break point” on the graph. The graph can now be plotted, as follows:

(47)

From this graph, the following information can be determined:

For a liquid influx, with no gas:

• The kick tolerance is 233 kg/m3 above the present mudweight.

• This would mean that the maximum formation pressure that can be controlled, by well shut-in,

without resulting in fracture, is 1383 kg/m3 (1150 + 233).

• If formation pressures greater than this are anticipated, then a new casing shoe would have to be

set.

Lighter and expanding gas changes this scenario dramatically:

• If more than 16.7 m3 of gas was allowed into the annulus, there is no kick tolerance on well

shut-in, the shoe would fracture!

• Operators will often work on an acceptable maximum kick influx to determine kick tolerance:

• For example, a 10m3 gas influx would give a kick tolerance of 86 kg/m3 above the present

mudweight. 0 2 3.05 4 6 8 10 12 14 16 18 240 200 173 160 120 80 40 0 KT kg/m3 Influx Volume m3

X

Y

(48)

This can be verified with the formula:

Of the 10m3, 6.95m3 would be around the drillpipe annular section, since 3.05m3 fill the drill collar section: Height around DP = 6.95 / 0.02396 = 290m Height around DC = 200m Total Height = 490m KT = 2000 (1500 – 1150) - 490 (1150 – 250) 3000 = 86.3 kg/m3

(49)

6 WELL CONTROL PRINCIPLES & CALCULATIONS

6.1 BALANCING BOTTOM HOLE PRESSURES

Assuming a kick at the bottom of the hole, during well control the bottom hole pressure (BHP) must be balanced on both the drillstring side and annulus side. The well can be considered to behave along the lines of a U-tube.

Take a normal well situation:

Assume a normally balanced well, where the mud hydrostatic pressure exceeds the formation pressure.

In a normal drilling situation, the u-tube is open at the surface with the pressure at the bottom of the hole equal to the mud hydrostatic.

This pressure would be the same on both sides of the u-tube, so that the well is balanced.

If the well is shut in, the pressures are the same and no additional surface pressure is required to achieve balance.

Now, consider actual depths and pressures:

MW = 1020 kg/m3 TVD = 1000m

HYDmud = 1020 x 1000 x 0.00981 = 10006 KPa If this is greater than Pform, then the BHP = 10006 KPa. Shut in pressures would be zero since the well is balanced.

SICP = 0

SIDP = 0

BHP = HYDmud

SICP = 0

SIDP = 0

BHP = HYD = 10006KPa

(50)

Now, let the annulus be partially (half in this case) filled with a lighter mud:

The string is still filled with 1020 kg/m3 mud, so exerts a BHP pressure of 10006 KPa.

However, the hydrostatic in the annulus has been reduced:

HYD1020 = 1020 x 500 x 0.00981 = 5003KPa

HYD1000 = 1000 x 500 x 0.00981 = 4905KPa

Annular Pressure = 5003 + 4905 = 9908KPa

This does not balance the BHP, so if the well was shut in, an additional 98KPa would have to be imposed at surface.

(98 + 5003 + 4905 = 10006)

Returning to our well with 1020 kg/m3 mud:

At 1000m, a formation is penetrated with a pressure of 10400KPa. A kick results in the well being shut in. BHP now equals 10400KPa

On the drillstring side, it is assumed that the influx does not enter the pipe:

HYDmud = 10006KPa

SIDP of 394KPa will therefore balance the well: 10400 = 10006 + 394

In the annulus, the overall hydrostatic has been reduced by the influx, so that a higher SICP will be required to balance the well

SICP = 98

SIDP = 0

BHP = 10006KPa

1020

1000

500m

1000m

10006KPa 9908KPa

influx

BHP = Pform = 10400Kpa

SIDP=394KPa

(51)

Example:

Drilled depth = 3500m TVD, MW = 1030kg/m3.

A formation kicks….FP = 38000KPa; oil of density 850 kg/m3 influxes to a height of 500m.

BHP = the higher FP = 38000 KPa

HYD = 1030 X 3500 X 0.00981 = 35365KPa

To balance the drillstring side, SIDP = 38000 – 35365 = 2635KPa To balance the annulus, SICP = 38000 – (HYDmud + HYDinflux)

= 38000 – [(1030 x 3000 x 0.00981) + (850 x 500 x 0.00981)] = 38000 – [30313 + 4169]

= 3518KPa

From these U-tube principles, the following shut-in formulas can be determined: -

Pform = 38000KPa

HYDmud = 35365KPa

1030

850 HYDinflux = 4169KPa

SIDP = 2635KPa

SICP=3518KPa

(52)

6.2 Shut In Formulas

Annular or Drillpipe Pressure + Shut In Pressure = Formation Pressure

The SIDP provides the additional pressure to the mud hydrostatic in the drillstring, in order to balance the increased BHP resulting from the formation pressure.

Mud Hydrostatic + SIDP = Formation Pressure

The same principle applies to the annulus side of the u-tube, but here, the mud column is contaminated by the influx. This reduces the overall hydrostatic in the annulus, so that a greater CSIP is required in order to provide balance.

If it is assumed that the influx is concentrated at the bottom of the hole and the height of the influx can be determined:

NewMud HYD + InfluxHYD + SICP = Formation Pressure

Where influx hydrostatic = influx gradient x influx height

6.3 Influx Height and Type

Despite the formula shown above, because of too many uncertainties, the SICP is not used to determine formation pressure, but it can be used as an early estimation as to what type of influx needs to be controlled.

The influx volume is normally assumed to be equal to the pit volume increase, i.e. the volume of mud displaced at surface, as a result of the influx downhole.

Height of influx = pit gain * annular capacity

Pit volume increase, once the well has been shut in and lined up to the trip tank, will be due to an influx volume situated at the bottom of the hole.

Prior to shut in, however, while circulating, the influx would have been dispersed further up the annulus, contaminating the mud and with reduced height due to larger annular capacity.

These possible errors are ignored and the influx assumed to occupy the bottom of the hole, with a reduced mud column above.

influx

contaminated

mud

clean

(53)

The height reached by an influx is dependent on:

• The pressure differential and permeability, i.e. effectiveness of influx flow

• The fluid type

• The time taken to shut in the well, allowing for influx

• Annular capacities

Naturally, the greater the height of the influx, then the greater the reduction in hydrostatic pressure, and the greater the CSIP that will be required to balance the well.

Gas expansion will reduce the hydrostatic even further!

With reliable data, the influx gradient can be determined as follows:

Fluid Gradient (psi/ft) = (MWppg x 0.052) - (SICP - SIDP (psi))

influx height (ft)

Fluid Grad (KPa/m) = (kg/m3 x 0.00981) - (SICP - SIDP (KPa))

influx height (m)

Fluid Gradient (psi/ft)

Fluid Type Fluid Gradient (KPa/m) 0.05 – 0.15 Gas 1.131 – 3.393 0.15 – 0.40 Condensate – Oil 3.393 – 9.048 0.433 Fresh water 9.795 0.433 – 0.48 Salt water 9.795 – 10.858

wellcontrol_v2-1

BLOW OUT PREVENTION

&

WELL CONTROL

Version 2.1

March 2001

Dave Hawker

Corporate Mission

CONTENTS

1 INTRODUCTION

2 PRESSURE GRADIENTS

2.1 Formation Related Pressures

Mud Hydrostatic

Pressure

Formation Pore

Fluid

Pressure

Fracture

Pressure

2.2 Wellbore Balancing Pressures

KICK

FRACTURE

Vertical

Depth

Pressure

Overburden (OBG)

Fracture (Pfrac)

Mud Hydrostatic

Formation (FP)

ECD

HYDmud = mudweight x TVD x g

BHCP = HYDmud +

∆∆∆∆

Pa

(g x TVD)

3 KICKS AND BLOWOUTS

3.1 Definitions

3.2 Causes Of Kicks

3.3 Kick Warning Signs

A Drill Break should always be Flow Checked, in order to determine whether it is

associated with an overpressured zone and possible influx.

3.4 Indications Of Kicks While Drilling

If Annular Pressure < Formation Pressure, then an influx can result

Impermeable

Permeable

FP > Phyd

Increase in Liberated Gas

Produced Gas

CG

CG

3.5 Indicators While Tripping

Every precaution (i.e. monitoring the well before pulling out, minimizing swabbing, flow

checks) is taken to avoid taking a kick during a trip:

Running Speed

Pressure

Reduction

Y KPa

3.6 Gas Expansion

D

D/2

D/4

D/8

V

4V 8V

depth

gas volume

3.7 Flowchecks

If the well is flowing, the well will be shut in

Gas in solution,

no expansion

4 KICK CONTROL EQUIPMENT

4.1 The BOP Stack

4.2 Preventers and Rams

Annular

preventer

Ram preventers

Manual closure

possible on land

rigs and jack ups

4.3 Stack Configuration