Well Control

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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. 
DATALOG: BOP & WELL CONTROL MANUAL, Version 2.1, issued March, 2001 
DATALOG: BOP & WELL CONTROL MANUAL, Version 2.1, issued March, 2001 
 
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CONTENTS 
 
 
1 INTRODUCTION................................................................................................................................................... 3 
2 PRESSURE GRADIENTS ..................................................................................................................................... 4 
2.1 FORMATION RELATED PRESSURES...................................................................................................................... 4 
2.2 WELLBORE BALANCING PRESSURES................................................................................................................... 5 
2.2.1 Mud Hydrostatic ......................................................................................................................................... 6 
2.2.2 Equivalent Circulating Density ................................................................................................................... 7 
2.2.3 Surge Pressures........................................................................................................................................... 8 
2.2.4 Swab Pressures ........................................................................................................................................... 8 
3 KICKS AND BLOWOUTS.................................................................................................................................. 10 
3.1 DEFINITIONS ..................................................................................................................................................... 10 
3.2 CAUSES OF KICKS ............................................................................................................................................ 11 
3.3 KICK WARNING SIGNS...................................................................................................................................... 12 
3.4 INDICATIONS OF KICKS WHILE DRILLING ........................................................................................................ 13 
3.4.1 Connection Gas......................................................................................................................................... 14 
3.5 INDICATORS WHILE TRIPPING........................................................................................................................... 16 
3.5.1 Trip Margin............................................................................................................................................... 17 
3.6 GAS EXPANSION ............................................................................................................................................... 19 
3.7 FLOWCHECKS ................................................................................................................................................... 20 
4 KICK CONTROL EQUIPMENT ....................................................................................................................... 21 
4.1 THE BOP STACK .............................................................................................................................................. 21 
4.2 PREVENTERS AND RAMS................................................................................................................................... 22 
4.2.1 Annular Preventer..................................................................................................................................... 22 
4.2.2 Ram Preventers ......................................................................................................................................... 23 
4.3 STACK CONFIGURATION ................................................................................................................................... 24 
4.4 SUBSEA EQUIPMENT ......................................................................................................................................... 25 
4.4.1 Lower Marine Riser Package.................................................................................................................... 26 
4.5 CHOKE MANIFOLD............................................................................................................................................ 27 
4.5.1 Choke and Kill Lines................................................................................................................................. 28 
4.6 CLOSING THE PREVENTERS............................................................................................................................... 29 
4.6.1 Pressure source......................................................................................................................................... 29 
4.6.2 Accumulators ............................................................................................................................................ 29 
4.6.3 Control manifold ....................................................................................................................................... 30 
4.7 DIVERTERS ....................................................................................................................................................... 32 
4.8 INSIDE BLOWOUT PREVENTORS........................................................................................................................ 33 
4.8.1 Kelly Rigs .................................................................................................................................................. 33 
4.8.2 Top Drive Rigs .......................................................................................................................................... 33 
4.8.3 Additional Preventers................................................................................................................................ 34 
4.9 ROTATING PREVENTERS ................................................................................................................................... 35 
5 FRACTURE CALCULATIONS ......................................................................................................................... 36 
5.1 LEAK OFF TEST ................................................................................................................................................ 36 
5.2 FRACTURE PRESSURE ....................................................................................................................................... 38 
5.3 MAXIMUM ALLOWABLE ANNULAR SURFACE PRESSURE.................................................................................. 41 
5.4 KICK TOLERANCE............................................................................................................................................. 43 
6 WELL CONTROL PRINCIPLES & CALCULATIONS ................................................................................. 48 
6.1 BALANCING BOTTOM HOLE PRESSURES.............................................................................................. 48 
6.2 SHUT IN FORMULAS.......................................................................................................................................... 51 
DATALOG: BOP & WELL CONTROL MANUAL, Version 2.1, issued March, 2001DATALOG: BOP & WELL CONTROL MANUAL, Version 2.1, issued March, 2001 
 
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6.3 INFLUX HEIGHT AND TYPE ............................................................................................................................... 51 
6.4 STABILIZING SHUT IN PRESSURES..................................................................................................................... 53 
6.5 INDUCED KICKS ................................................................................................................................................ 54 
6.6 ONE WAY FLOATS ............................................................................................................................................ 54 
6.7 SLOW CIRCULATING RATES.............................................................................................................................. 55 
6.8 KILL MUDWEIGHT ............................................................................................................................................ 55 
6.9 CIRCULATING THE KILL MUD .......................................................................................................................... 56 
6.10 PRESSURE STEP DOWN ................................................................................................................................... 58 
6.11 SUBSEA CONSIDERATIONS .............................................................................................................................. 59 
7 WELL CONTROL METHODS .......................................................................................................................... 60 
7.1 WAIT AND WEIGHT........................................................................................................................................... 60 
7.2 DRILLER’S METHOD ......................................................................................................................................... 62 
7.3 CONCURRENT METHOD .................................................................................................................................... 64 
7.5 VOLUMETRIC METHOD ..................................................................................................................................... 65 
8 QLOG SOFTWARE............................................................................................................................................. 67 
8.1 LEAK OFF PROGRAM ........................................................................................................................................ 67 
8.2 KICK/KILL PROGRAM ....................................................................................................................................... 68 
9 EXERCISES.......................................................................................................................................................... 70 
 
 
 
DATALOG: BOP & WELL CONTROL MANUAL, Version 2.1, issued March, 2001 
DATALOG: BOP & WELL CONTROL MANUAL, Version 2.1, issued March, 2001 
 
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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. 
 
 
W. Wylie ERCB 
DATALOG: BOP & WELL CONTROL MANUAL, Version 2.1, issued March, 2001 
DATALOG: BOP & WELL CONTROL MANUAL, Version 2.1, issued March, 2001 
 
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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 
DATALOG: BOP & WELL CONTROL MANUAL, Version 2.1, issued March, 2001 
DATALOG: BOP & WELL CONTROL MANUAL, Version 2.1, issued March, 2001 
 
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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 
DATALOG: BOP & WELL CONTROL MANUAL, Version 2.1, issued March, 2001 
DATALOG:BOP & WELL CONTROL MANUAL, Version 2.1, issued March, 2001 
 
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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, 
leading to lost circulation and possible blowout. 
DATALOG: BOP & WELL CONTROL MANUAL, Version 2.1, issued March, 2001 
DATALOG: BOP & WELL CONTROL MANUAL, Version 2.1, issued March, 2001 
 
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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. 
 
 
DATALOG: BOP & WELL CONTROL MANUAL, Version 2.1, issued March, 2001 
DATALOG: BOP & WELL CONTROL MANUAL, Version 2.1, issued March, 2001 
 
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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. 
 
DATALOG: BOP & WELL CONTROL MANUAL, Version 2.1, issued March, 2001 
DATALOG: BOP & WELL CONTROL MANUAL, Version 2.1, issued March, 2001 
 
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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 permeableformations, 
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. 
 
 
 
DATALOG: BOP & WELL CONTROL MANUAL, Version 2.1, issued March, 2001 
DATALOG: BOP & WELL CONTROL MANUAL, Version 2.1, issued March, 2001 
 
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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. 
 
 
 
Preventing a kick from becoming a blowout is paramount in well control! 
 
 
DATALOG: BOP & WELL CONTROL MANUAL, Version 2.1, issued March, 2001 
DATALOG: BOP & WELL CONTROL MANUAL, Version 2.1, issued March, 2001 
 
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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 
 
Naturally, if formation pressure exceeds the annular pressure, then a kick may result. 
 
DATALOG: BOP & WELL CONTROL MANUAL, Version 2.1, issued March, 2001 
DATALOG: BOP & WELL CONTROL MANUAL, Version 2.1, issued March, 2001 
 
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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. 
 
 
DATALOG: BOP & WELL CONTROL MANUAL, Version 2.1, issued March, 2001 
DATALOG: BOP & WELL CONTROL MANUAL, Version 2.1, issued March, 2001 
 
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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. 
 
A kick should always be detected before the influx reaches surface!! 
 
EARLY DETECTION…..FLOW CHECK…..SHUT IN IF FLOWING 
DATALOG: BOP & WELL CONTROL MANUAL, Version 2.1, issued March, 2001 
DATALOG: BOP & WELL CONTROL MANUAL, Version 2.1, issued March, 2001 
 
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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 throughswabbing 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. 
• There will be no filter cake for protection against small influxes. 
DATALOG: BOP & WELL CONTROL MANUAL, Version 2.1, issued March, 2001 
DATALOG: BOP & WELL CONTROL MANUAL, Version 2.1, issued March, 2001 
 
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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 
 
 
 
 CG 
 
 
 
Well Flowing 
DATALOG: BOP & WELL CONTROL MANUAL, Version 2.1, issued March, 2001 
DATALOG: BOP & WELL CONTROL MANUAL, Version 2.1, issued March, 2001 
 
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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. 
 
• The well cannot be shut in (pipe or annular rams) if drill collars are passing through the BOP’s. 
DATALOG: BOP & WELL CONTROL MANUAL, Version 2.1, issued March, 2001 
DATALOG: BOP & WELL CONTROL MANUAL, Version 2.1, issued March, 2001 
 
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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 
X m/min 
DATALOG: BOP & WELL CONTROL MANUAL, Version 2.1, issued March, 2001 
DATALOG: BOP & WELL CONTROL MANUAL, Version 2.1, issued March, 2001 
 
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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. 
 
 
 
 
 
 
 
DATALOG: BOP & WELL CONTROL MANUAL, Version 2.1, issued March, 2001 
DATALOG: BOP & WELL CONTROL MANUAL, Version 2.1, issued March, 2001 
 
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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 notbe 
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 
Bubble point 
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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 
movement and tidal variations. This is achieved through a ball joint connection. 
 
 
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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 
Pipe Ram 
Pipe Ram 
Blind/Shear 
Annular 
preventer 
Choke & Kill Lines 
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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
connectingto 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 
isolate equipment that may need repair. 
 
 
 
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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. 
 
 
For example: - 
 
 
 
 
 
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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. 
 
 
A B C 
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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 
signals from surface. 
 
 
 
 
 
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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 andgas 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 
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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. 
 
 
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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. 
 
 
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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 
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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 valueis 
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. 
 
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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 
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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 
Fracture 
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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. 
 
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• 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. 
 
 
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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. 
 
DATALOG: BOP & WELL CONTROL MANUAL, Version 2.1, issued March, 2001 
DATALOG: BOP & WELL CONTROL MANUAL, Version 2.1,issued March, 2001 
 
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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 
 
 
DATALOG: BOP & WELL CONTROL MANUAL, Version 2.1, issued March, 2001 
DATALOG: BOP & WELL CONTROL MANUAL, Version 2.1, issued March, 2001 
 
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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 TVDhole 
 
 
 
DATALOG: BOP & WELL CONTROL MANUAL, Version 2.1, issued March, 2001 
DATALOG: BOP & WELL CONTROL MANUAL, Version 2.1, issued March, 2001 
 
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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. 
 
 
DATALOG: BOP & WELL CONTROL MANUAL, Version 2.1, issued March, 2001 
DATALOG: BOP & WELL CONTROL MANUAL, Version 2.1, issued March, 2001 
 
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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 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: 
DATALOG: BOP & WELL CONTROL MANUAL, Version 2.1, issued March, 2001 
DATALOG: BOP & WELL CONTROL MANUAL, Version 2.1, issued March, 2001 
 
46 
 
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 
Drill Collars Drill Pipe 
DATALOG: BOP & WELL CONTROL MANUAL, Version 2.1, issued March, 2001 
DATALOG: BOP & WELL CONTROL MANUAL, Version 2.1, issued March, 2001 
 
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This can be verified with the formula: 
 
Of the 10m3, 6.95m3 would be around the drillpipe