DRILLING – INTRODUCTION
Drilling is about equipment and methods commonly used for drilling wells, especially down
to oil and gas reservoirs. Also included are equipments and methods for securing the well and
preparing it for later use. Using the well for production, including setting down production
tubing and equipment belong to production technology. Perforation, making holes through
casing and into the reservoir rock around the well is here included in drilling (it is often
considered part of production).
SUBJECTS BEING TREATED
DRILLING PROCESS
SECURING THE WELL
Surface equipment
Derrick
Hoisting equipment
Rotating (of drill string) equipment
Mud treatment and pumping equipment
Drilling mud
Functions - Properties
Drill string
Drill pipe – Drill collars
Measuring equipment in the drill string
Equipment to loosen stuck pipe
Down hole mud motor
Directional drilling equipment
Drill bits
Well classification
Vertical wells – Deviation wells
Horizontal wells
Surveying the well path
Down hole pressures Overburden (pressure)
Horizontal stresses – fracturing
Pore pressure
Upper and lower limits of well pressure
Pipes for securing well Conductor pipe – casing – liner
PRESSURE-CONTROL
Cementing
Function of cement
Placing of cement slurry*
Limits to cementing heights
Kick – Blowout
BOP – Blow Out Preventer – construction
Reasons for kicks
Killing a kick – circulating out
*Cement slurry is cement powder mixed with water, before gelling and curing starts.
2
BOP
STIGERØR
BOP
HAVBUNN
Figure 1
Sketch of a fixed platform (production platform) and a moveable
platform. Note the different placements of the BOP and of the wellhead,
which in both cases is placed directly below the BOP.
DRILLING PROCESS
Types of platforms
In order to drill a well two main types of platforms are in use, fixed platforms and moveable
platforms. A fixed platform is used only when production wells are drilled for the purpose of
producing an oil or gas field. It is accordingly called a production platform, its main purpose
is to receive the oil and gas produced, to separate the oil and gas, remove water, and in
general give the treatment necessary for transport to land. This type of platform is
permanently mounted on the sea bottom and is dissembled when the production of the field is
terminated. As a production platform always uses several wells the drill floor with the derrick
is mounted on skids (rails) for moving around to drill all the planned wells. These production
wells are closely spaced to some short distance below the sea bottom, where they curve away
in different directions, mainly to reach different parts of the reservoir, or different reservoirs,
but also to reduce the risk that a new well is drilled into another well.
Movable platforms are always used when drilling test wells. These wells are drilled and, if oil
or gas is found, produced for a short time to see if there are sufficient oil or gas present to start
producing the field. Afterwards the test well is usually closed off by cement and all the metal
removed to well below the sea bottom. This is the wellhead and the upper parts of the casing.
Movable platforms may also be used to drill the production wells for a fixed production
platform. For production of small fields with a short production time movable platforms may
3
be used both for drilling and for production. When production ends they can be moved to
another small field, and so on.
Satellite wells are also drilled from movable platforms. These wells are production wells with
its wellhead on the sea bottom. From the well head the produced oil and gas flows through a
single pipeline lying on the sea bottom, connecting the satellite well and a nearby fixed
production platform.
Surface equipment – hoisting equipment
For traditional drilling a steel beam tower (derrick) is used, typically with a height around
60m. The derrick is mounted on the drill floor. All equipment for handling, storing and
operating the drill string is in, on or above the drill floor. Below the drill floor is the pump
floor, where equipment for mixing, cleaning, storing and pumping of drilling mud is found.
On fixed platforms the wellhead and safety equipment like the BOP are also on or right below
the pump floor. On shore there is a corresponding arrangement, but mud treating and
pumping equipment, and the wellhead, are usually mounted directly on the ground.
Illustration:
2D
3D
Enkel
x
Kompleks Animasjon Simulering Foto
x
x
x
Formel
Moveable platforms (or drill ships) are basically designed as the fixed platforms, except that
here the wellhead and the BOP are mounted on the sea bottom, below the floating platform.
In this case the BOP and the platform above it are connected by a riser, a pipe running from
the top of the BOP and up to the pump floor. The connection between the riser and the BOP
is flexible, allowing the platform to move somewhat without bending the riser.
If the platform drift off, which can happen due to bad weather or errors in the navigation
system, the riser can be disconnected rapidly from the BOP in such a way that the flexible
connection and the riser are not damaged. Before disconnection the BOP will be activated,
closing the well completely. This possibility is the main reason the wellhead and the BOP are
mounted on the sea bottom when a moveable platform or a drilling ship is used.
The drill string and other equipment are lifted using block and tackle, mounted from the top of
the derrick. From the cable drum, mounted on the drill floor between two of the derrick legs,
the line runs up to the crown block, over the first wheel and down to the running block and up
again, repeating this 4 to 6 times. Finally the line runs down to the drill floor at the bottom of
one of the derrick legs, opposite the cable drum (this is to balance the forces acting on the
derrick). Here the line is attached to a force transducer, showing the amount of line stretch.
This fixed point is called the dead anchor.
The line from the cable drum to the crown block is always the fastest moving part of the
whole line, and is accordingly called the fast line. The part of the line from the crown block
and down to the dead anchor is not moving and is called the dead line. The running block is
carrying the equipment and is, with 5 to 7 wheels, hanging from 10 to 14 lines. With no
friction present the load on the line would then be 1/10 to 1/14 of the total load carried by
4
hoisting. The total load must include the weight of the running block itself and other lifting
equipment in addition to the drill string or any other equipment being lifted.
Even if the friction for each wheel is small (ball bearings), the total friction will be significant
due to the large number of block wheels, 10 to 14 all together. With 7 wheels in the running
block, the load of the fast line will be around 1/10 of the total load when hoisting up, signifycantly larger than the 1/14 expected with no friction. In the dead line the load will be reduced
to about 1/18 of the total load. For hoisting down, or lowering a load, the situation is the
opposite, giving a load of only 1/18 of the total load in the fast line, while increasing the load
to 1/10 in the dead line. Measurements of the dead line load gives, as seen, a value that
depends upon whether one is hoisting up and down. To a lesser degree it also depends upon
the amount of line between the two blocks (more line if the running block is low). The dead
line load therefore does not give a good measure of the total load. A more accurate
measurement of the total load (the hook load) is obtained by a load cell mounted below the
traveling block. When drilling the force moment of rotation at the top of the drill string is
also often measured. If this becomes too large the drill pipe can be twisted off. A typical drill
pipe can withstand about 30 kNm (kiloNewtonmeter: on a lever reaching one meter
perpendicular out from the drill pipe one can put about 3 ton).
KRONBLOKK
BORETÅRN
HURTIGLINE
HEISETROMMEL
LØPEBLOKK
TOPDRIVE
DØDLINE
STREKKMÅLER
BOREDEKK
ROTASJONSBORD
RENSEANLEGG
FOR SLAM OG
SLAMTANK
STAND PIPE
BOP
SLAMPUMPE
BRØNN
PUMPEDEKK
Figure 2
Sketch of equipment on the pump and drill floors. Cleaning equipment for
returned mud is not shown in detail. Motors for mud pump, rotating table, and
hoisting drum (cable drum) are not shown. BOP is placed directly on the
wllhead (this must be a fixed platform).
5
The hoisting equipment is capable of lifting up to about 300 ton. The line in the block and
tackle must therefore be able to take a load of about 1/10 of this when there is 7 wheels in the
traveling block, about 30 ton. A drill string will not weigh this much, but a BOP stack, or
long sections of large casing strings can approach this load.
The cable drum is turned by, in most cases, an electrical motor, via reducing gears or V-belts,
and a clutch. The clutch disconnects the motor and the drum when the load is lowered.
Powerful brakes are then used. During braking of loads moving down the potential energy in
the gravity field is transformed to heat. For a load of 300 ton = 3000 000 N that is lowered at
a constant speed of 1 m/s the production of heat in the brake is given by:
Power = Force x speed = 300000 kg x 9.81 m/s x 1 m/s = 2943000 W = 2943 kW.
This is equivalent to 2000 electric heaters at full effect (1500 W each), and this will boil 100
liter of water in 17 seconds. This large heat load must be carried away from the brake or they
will burn out in a short time. This is done by pumping water through the brakes.
It is at least two types of brakes connected to the cable drum, one electromagnetic, and a
mechanical drum brake. The electromagnetic brake is in principle a dynamo that is producing
a current when it is rotating. Most of the braking energy (ca. 90%) can be carried away as a
current and used in big resistors. Alternatively a massive rotor where the current generated
heats the rotor. The rotor is cooled by water pumped through it. The brake power is
regulated by the magnetic field in the stator, consisting of electromagnets around the rotor.
Regulating the current (from the platforms electric current system) through these
electromagnets regulates the magnetic field in the stator.
MOTOR
Figure 3
CLUTCH
KABELTROMMEL
MEKANISK
BREMS
ELEKTROMAGNETISK
BREMS
Sketch of the cable drum on the drill floor, with its electric motor and brake
system. On the mechanical drum brake the brake ribbons are shown. The
cooling system, where water is pumped through the interior of the brake drum
and the interior of the electromagnetic brake, is not shown. In reality there is a
gear system between the motor and the line drum, also not shown. This gear
system reduces the rotating speed of the motor to a slower speed, more
convenient for the drum. The electric power consumed by the motor is
commonly around 1000 HK = 750 kW.
6
For a given setting of the electromagnetic brake the braking power (force) is proportional with
the rate of rotation of the drum. Even if full braking power is used, the braking force from the
electromagnetic brake will decrease towards zero when the drum is stopping. For slow
lowering rates of equipment the mechanical brake therefore has to be used. For this brake the
braking force is approximately constant for a given force applied to the braking ribbons,
independent of the drum rotating speed. Evidently, for keeping the load from moving down at
all, only the mechanical brake is useful. But the mechanical brake cannot handle the braking
power possible for the electromagnetic brake, therefore both brakes are necessary. The
problem is that the heat generated is only at the interface between the braking drum and the
braking ribbons, and it is not possible to cool this interface sufficiently rapidly from the inside
of the drum. The procedures for braking is accordingly:
- For lowering loads at relatively high speeds, use only electromagnetic brake.
- For lowering loads at relatively low speeds, also the mechanical brake must be used.
- For keeping the load at a fixed position, only the mechanical brake can be used.
Surface equipment – equipment for rotating and handling drill string
During drilling the drill string is rotated either with the top drive, a motor coupled directly to
the top of the drill string, or with the rotating table. The top of the rotating table is flush with
the drilling floor, it is circular and running on rollers to minimize friction. It is turned by an
electric motor. As for hoisting the standard power of this motor is 1000 HK = 750 kW. Use
of the rotating table to turn the drill string is nearly outdated in the North Sea, but it can still
be used to turn the larger casing string if desirwed (see the section about casings).
The top of the drill string is connected to the bottom of the top drive motor that is hanging
from the trunning block. Through this connection drill mud is pumped into the top of the drill
string by using a swivel, a connection that can rotate freely. The mud pump is connected to
the swivel with a vertical pipe (stand pipe) and a flexible hose. The heigth of the stand pipe
above the drill floor is about 15 meter, see Fig. 2.
Each of the drill pipes is about 10 m long (30 fot). The first time they are used they are joined
to the top of the string one by one, but later on only every third joint is uncoupled as the drill
string is pulled out of the well. When not in use these sections of three drill pipes are stored
vertically on the drill floor, see Fig. 4. Such a section of three connected pipes is called a
stand. It has a length of approximately 30 meter. In some of the tallest derricks a stand may
consist of four pipes (40 m). The advantage of this is that the number one has to connect up,
or deconnect joints during drilling and tripping, is reduced.
During drilling the drill string has to be pulled out of the well a number of times, for changing
equipments, possible repairs, changing the drill bit or the nozzle size, or for setting a new
casing string. Pulling the string out of the well and setting it down again is called tripping.
Tripping out when pulling the string out, and tripping in when setting it down again. During
tripping drill mud is not pumped, and the drill string is not usually rotated.
7
TOP DRIVE
RØRHÅNDTERING
OG LAGRINGSSYSTEM
SETT OVENFRA
SYSTEM FOR
SIDEVEIS
BEVEGELSE
AV TOP DRIVE
STYRESKINNE
FOR TOP DRIVE
STANDS
AUTOMATISK
RØRKOBLING
BOREDEKK
Figure 4 Sketch of systems for connecting pipes and handling and storing pipes or stands.
Guiding rail for the top drive keeps the top drive centered above the well and
prevent rotation of the top drive motor. This rail does not carry any weigth, as the
weigth of the top drive motor and the drill string is carried by the running block
(which here is above the drawing). Hoisting equipment and stand pipe with its
flexible hose are not shown. When drilling deep wells more than one hundred
stands may be stored on the drill floor, far more than shown here. Note that also
drill collars are stored as stands, see storage system as seen from above.
8
When drilling the drill string is elongated by the following procedure:
After drilling down until only the top connection of the drill string is above the rotating table
(the drill floor):
-
-
-
-
The drill string is hoisted up a short distance, lifting the drill bit off the hole bottom.
Rotation and pumping of mud is stopped.
Steel wedges are put down in the hole in the rotating table, around the drill string and
below the top connection. The running block is slightly lowered, the wedges are
pushed down and compressed against the drill string, locking it into place and carrying
the whole drill string load.
The connection between the drill string and the top drive no longer carries the axial
load and is disconnected. On more advanced rigs this is done automatically. The top
drive is hoisted up somewhat more than 30 meter (if three pipe stands are used).
Hydraulic arms grab one pipe stand in the stand storage and moves it out below the
top drive.
Top drive is connected to this stand, and the bottom connection of this stand is
connected to the top connection of the pipe locked by steel wedges in the rotating table
hole. The drill string is now elongated by one stand.
The drill string is lifted sufficiently to shift the weight of the whole drill string from
the wedges to the top drive. This lift and loosens the wedges, which are removed.
Pumping of drill mud and rotating of the drill string are started, and the drill string is
lowered until the drill bit settle on the well bottom and drilling is continued.
After drilling the length of the new stand (ca. 30 m) the top of the drill string is again
just above the drill floor and the operations described above is repeated.
The sequence of operations described above gives that for every 30 meters drilled one must
undo one connection and make two connections, also (in order to keep the disconnected drill
string from falling) put down and remove wedges once. If the rotating table is used to turn the
drill string, as was always the case before the introduction of the top drive, this operation was
considerably more time consuming. In this case a special drill pipe called the kelly had
always to be at the top of the drill string. The kelly had either a square or a hexagonal outer
cross section, a corresponding hole in the rotating table forced the drill string around when the
table turned. As the length drilled for each addition of one drill pipe had to be the whole drill
pipe length, the kelly had to be longer between its end connections than the longest drill pipe
in use. To be on the safe side the kelly was usually around 15 meters.
When elongating the drill string the kelly had to be pulled completely out of the hole in order
to disconnect the kelly from the rest of the drill string. Adding one new drill pipe and the
kelly on top of that required a heigth of 25 meters above the drill floor, giving no possibility
of adding more than one drill pipe at a time in the standard derrick. This resulted in a
minimum of three disconnections, six connections, and putting down and removing wedges
three times for each 30 meters drilled. In addition the square or hexagonal hole had to be
opened three times in order to get the drill string connections through.
During tripping some of the same operations are required, but since pumping mud and
rotating the drill string is not usually done, the top of the drill string does not need to be
connected to the top drive. It is sufficient with a simple hinged ring that can be locked around
the drill string, below the connection at the top. In this case one need to undo only one
connection (tripping up) or do only one connection (tripping down) for each stand removed or
9
added to the drill string. This is also the case when the rotating table is used during drilling,
as one does not need to use the kelly during tripping, when the drill string is not rotated.
Surface equipment – mud mixing and treatment equipment
Before and during drilling mud is made by mixing the different components of the mud in
special mixing containers. The resulting drilling mud is pumped to large storage tanks that
might take hundreds of cubic meters. Pumping of mud between tanks and to the high pressure
pumps used to pump mud down the drill string is done by low pressure centrifugal pumps.
See Fig. 5, where a simplified version of the mud treatment system is shown.
The mud usually contains small particles heavier than the liquid component of the mud can
support. But because such particles are very small they sink slowly. To avoid settling of
particles on the bottom of storage tanks, rotors with paddles are kept rotating slowly in the
mud, around one rotation every second (60 RPM). The resulting currents and eddies in the
mud keep the particles in suspension.
During drilling the mud is pumped down innside the drill string, out through the nozzles in
the drill bit, and up through the annulus outside the drill string. At the top of the well the
returning mud flows out and down a channel to the shale shaker where drill cuttings are
removed. This is a slanted screen which is kept vibrating, the mud flows down through the
small holes in the screen, while all solids larger than these holes slides down the screen and is
collected separately. The rock cuttings are cleaned and dumped at the drilling site, or
transported away for disposal. Gas being trapped in the mud as gas bubbles might also
disappear to the air in this process, as the mud is spread out rather thinly in the shakers. Other
possible contaminations of the mud are oil and water from the formation, very fine particles
from the drilling process, and salts and clay dissolved in the mud. These cannot be removed
by the shakers.
A few of these contaminations can be removed by further treatment of the mud in a secondary
mud cleaning system, for instance in centrifuges or hydrosyclones which is a form of
centrifuge without any moving, mechanical parts. These, and other treatments, can remove
particles too small to be removed by the shakers, including also gas and liquids inmiscible
with water (for water based mud). Separate degassing units can also be used to remove gas.
But contaminations like dissolved clay, small oil drops and very small solid particles are
almost impossible to remove, mainly because such substances are part of the original mud
mixture. Removing these will also remove substances meant to be there.
The properties of the returning mud are contiunally monitored by the mud engineer after
cleaning of the mud. The main properties measured are density, viscosity and ph value. If
these properties have moved outside their desired range the mud can still be used by adding
substances that correct this. For instance, if the mud is too heavy due to loss of water (or oil)
to the formation, and/or adding of clay and/or very fine rock particles from the drilling
process, the mud can be made lighter by adding water (or oil). If this reduces the viscosity
below its minimum desired value, Bentonite (clay) must also be added. Other mud properties
might also need to be corrected by adding other substances.
This will increase the volume of drilling mud, which might be no problem as more mud is
needed as the well is drilled deeper. If, however, the volume of corrected mud increases
10
faster than the volume of the well, some of the returned mud eventually has to be removed
from the site. Either by cleaning of the water in the mud to an acceptable purity and dumping
this, or transporting the surplus mud to a place where it can be treated and/or stored. For offshore drilling this would mean shipping the surplus mud to an on-shore site.
If correction of the returned mud goes on, the mud might eventually reach a stage of
contamination of unwanted substances to such a degree that it cannot be corrected any more.
All of the mud then has to be dumped and new drilling mud mixed.
STAND PIPE
TIL BORESTRENG
BLANDINGSTANK
BORESTRENG
TØRRSTOFF
TANK OG RØRER
RIST
P
P
SLAMPUMPE
Figure 5
BRØNN
P
P
HYDROSYKLON
BOREKAKS
SLAM
Sketch of the mud treatment system. Units marked by ”P” are low pressure
pumps. A hydrosyclone is one of several possibilities for further cleaning of the
mud. Tanks marked ”mud components” contain the different substances needed to
mix mud. Some of these might be stored as dry powder.
From the mud storage tank mud is pumped with a low pressure pump to the main, high
pressure mud pump. This is usually a piston pump with three single acting pistons. Because
of these three pistons this is called a tri-axial piston pump. The operating principle is shown
in Fig. 6. The three pistons are driven by a common crankshaft, with a phase displacement of
120 degrees in relation to each other. This gives a maximum smooth mud flow for pistons
driven by a crank shaft (for less than 5 pistons). The variation of the mud flow is here 13.4 %
((max. flow – min. flow)/(max. flow)). In order to reduce the variation in the volume flow
even more the pump outlet is often connected to a pulse damper, see the figure. This is a
container where a piston or a rubber membrane keep the mud at the same pressure as a large
volume of a compressed gas (nitrogen). The elastisity of this gas reduces the variations in
pressure and flow rate.
MOTOR
SLAM
NITROGEN
PUMPE
11
Figure 6
PULSDEMPER
Triaxial mudER
pump with pulse damper.
Note that the pistons have a smaller diameter than the cylinders, the pistons are then
commonly called ”plungers” instead of ”pistons”. The pressure seals around each plunger are
mounted in such a way that it reduces the possibility that solid particles in the mud are trapped
between the plunger and the liner. If this happens the surfaces might be sufficiently scratched
to destroy the integriety of the seal. Both the plunger and the liner can then be replaced. The
cylinder wall will never be scratched with this design, because there is never a close contact
between the plungers and the cylinder walls.
A mud pump is commonly equipped with 4 – 5 sets of plungers with liners, each set with
different diameters of the plungers and the liners. The range of plunger diameters can for
instance be 5.5, 6.0, 6.5, 7.0 and 7.5 inches. For a given maximum force F from the
crankshaft against each plunger, the maximum pressure PP the pump is able to deliver is given
by this force divided by the cross section area A of the plunger: PP = F/A. By changing to a
smaller plunger the pump can deliver a higher pressure, as the pressure is inversely
proportional to A, or to the square of the plunger diameter D. But then the volume rate
delivered by the pump is reduced, as this is proportional to A, or to D2.
The volume rate Q can be calculated when the number n of rotations per time unit of the
crankshaft is known, in addition to the piston area A = (/4)D2, and the stroke L (the distance
each piston moves back and forth). Since each piston displaces a mud volume equal to the
stroke length times the piston cross section once for every completed rotation of the crank
shaft, three pistons give:
Q = 3v(/4)D2Ln
The parameter v is the volume efficiency, its value is around 0.97. It is due to the following:
-
When the plunger moves back and the cylinder is filled by the low pressure pump, the
pressure in the cylinder is low, down to atmospheric pressure.
-
When the plunger moves forward, into the cylinder, the mud must be compressed until
the pressure in the cylinder is at least equal to the pressure in the stand pipe (the pipe
connected to the pump outlet) before the outlet valve in the cylinder can open and the
mud can start flowing out of the cylinder, see Fig. 6. This pump outlet pressure can be
several hundred bars. Even if liquids usually are considered incompressible, this is
only an approximation. The mud compressibility and the relation between the plunger
and cylinder diameter will determine this contribution.
-
The cylinder will expand slightly due to the increased pressure when the piston moves
into the cylinder. This additional volume has to be filled before mud flows out. The
elasticity of the cylinder wall material and the geometry of the cylinder will determine
this contribution (Youngs modulus of elasticity, cylinder diameter and wall thickness).
12
-
In addition to this there are small volumes in the outlet and inlet valves that have to be
filled before mud start to flow out of the cylinder. The specific design of these valves
will determine this contribution.
-
All this requires the piston to move a small distance into the cylinder before any mud
is pushed out, around 3 % of the stroke length. Effective stroke length is then about
0.97 (97 %) of the total stroke. This number is the volume efficiency v of the pump.
Volume efficiency obviously changes with the working pressure of the pump, also with the
plunger diameter chosen (a smaller plunger diameter has a relatively larger volume of mud to
compress). For simplicity a fixed average value is commonly used, for instance the value
0.97.
From the above the volume efficiency of a specific pump situation can be estimated. Mud has
typically a volume compressibility of CV = 10-9 Pa-1 = 10-4 bar-1. For a typical pump cylinder
of inner diameter 8” (inches) and length of 13” from the end of the liner to the end of the
cylinder, the volume of this part is V = (/4)D2L = (/4)8213 = 653.45 cubic inches. An
increase P of pressure from 0 to 200 bar (P = 200 bar) requires a volume decrease of V =
CVVP = 10-4653.45*200 = 13.069 cubic inches. A plunger with stroke length L and
diameter D6 = 6” has to move a distance L = V/((/4)D62) =13.069/((/4)62) = 0.462” in
order to cover this volume. With a stroke length L = 12” his is L/L = 0.462/12 = 0.0385, so
in this case the compressibility of the mud gives a volume efficiency of v = 1 – 0.0385 =
0.9615 all by itself. In addition to this there is the volume increase of the cylinder due to the
elasticity of the steel in the cylinder walls, and other effects.
For a typical mud pump with a plunger diameter of 7 inches, a stroke length of 10 inches, and
for 120 rotations of the crank shaft each minute, the volume flow rate is:
Q = v3(/4)D2Ln = 0.97*3(/4)7210*120 = 134387.9 cubic inches/min = 2202.2 l/min
Volume flow rate of mud is usually measured in liters per minute. Since an inch is equal to
0.0254 m, a cubic inch will be equal to (0.0254)3 cubic meter. Since 1 m3 is equal to 1000
liter, the first result (in cubic inches/min) should be multiplied by (0.0254)31000 = 0.2543 =
0.016387 in order to get the result in liters per minute, as shown above. For power
calculations it is simplest to use true SI-units, which for volume flow is cubic meters per
second. The result above (2202.2 l/min) must then be divided by 60000, 60 for the number of
seconds in one minute, and 1000 for the number of liters in one cubic meter. This gives Q =
0.03670 m3/sec.
For calculating the maximum pump pressure in this case one could from the known torque
delivered to the crank shaft calculate the force on each plunger. Dividing this with the
plunger cross section area would give the pressure. But it is simpler to use power
considerations (power is work (energy) per time unit). The total power transmission
efficiency  from the input electric power E E used by the motor to the hydraulic power E H
delivered to the mud flow from the pump must then be known. Hydraulic power in liquid
flow is given by pressure P multiplied by volume flow rate Q. The total power transmission
efficiency  is typically around 0.6 to 0.7, and for a typical mud pump motor of 1000 kW
electric power this gives, with  = 0.6:
Hydraulic power = PPQ = *Electric power = 0.6*1000 kW = 600 kW
13
For the triaxial mud pump used as an example above this gives:
PP = (*Electric power)/Q = (600*1000 W)/0.0367 m3/sec =16 349 000 N/m2 = 163.49 bar
Note that we now obtain the pressure in the SI-unit Pascal (= N/m2), which we change to bar
at the very end. Note also that in the calculations power, when given in kW, has to be
changed to the true SI-unit W (Watt). As stated before this type of power calculation is often
used to find the system output, here the output is pressure. Remember that the rule here is
that all parameter units must be changed to true SI-units in actual calculations, unnecessary
correcting factors are then avoided.
It is always possible to get a smaller volume flow than the maximum calculated for any given
plunger diameter by reducing the rotating rate of the motor. But in this case the power
delivered by the motor also decreases. This will therefore not increase the maximum pump
pressure. It is important to note that even if one intends to use the mud pump at a lower rate
of rotation than possible, the maximum pressure still must be calculated as shown above,
using the maximum rate of rotation n (maximum volume flow) and the maximum given
power of the motor.
The only possibility of increasing the pressure above the pressure calculated above, is to
change the plungers (and the liners) to ones with a smaller diameter. The only change in the
calculations above is then the plunger diameter D. By using the proportionality between the
volume flow and the square of the plunger diameter, the maximum volume flow and pressure
for the new plunger diameter Dnew can be found by:
Qnew = (Dnew/D)2 Q
Pnew = (D/Dnew)2 P
If one in the example above changes to a plunger with diameter 5.5 ” (inches), one obtains
Qnew = (5.5/7)2Q = 0.61735*2202.2 l/min = 1359.5 l/min, and Pnew = (7/5.5)2P =
1.6198*163.49 bar = 264.82 bar.
A common problem is to choose a plunger diameter that will give at least the desired pump
pressure, at the same time give the largest volume rate possible with this pressure. If one for
instance has decided that a pump pressure of Pnew = 200 bar is sufficient, what is the plunger
diameter Dnew that should be chosen for the example pump used above? Assuming that the
calculations for one specific plunger diameter D have already been done, as above for 7”, the
Eq. () for Pnew is solved with respect to Dnew:
P
163.49
7
 7  0.9041  6.329 ”
Pnew
200
A plunger with this diameter would give exactly 200 bar. But we have to chose between
existing plungers. We cannot chose a plunger diameter larger than 6.329” because this would
give a pressure smaller than 200 bar. The allowable plunger closest to the calculated diameter
is here 6”. By using Eq. () above this finally gives:
Dnew  D
Qnew = (Dnew/D)2 Q = (6/7)22202.2 = 1617.9 l/min
Pnew = (D/Dnew)2 P = (7/6)2163.49 = 222.52 bar
14
This is the best we can do with this specific pump, if it must be able to deliver at least 200 bar
in output pressure, the largest volume flow rate it can deliver is 1617.9 l/min. If we need
more than this, the only solution is to get another mud pump that can work in parallell with
the first pump, increasing the total flow rate. If we get another pump of the same type, the
maximum output pressure is still 222.52 bar, but the maximum flow rate is now 3235.8 l/min.
Note that we can always put pumps in parallell, increasing the total flow rate. For some types
of pumps, for instance centrifugal pumps (compressor), the output pressure can be increased
by connecting pumps in series, the outlet of one pump is connected to the inlet of the next
pump. This is not possible with the piston pumps used as mud pumps. Connecting these in
series will not increase the output pressure, and it will of course not increase the output flow
rate. So this is never done. If several mud pumps are used they are always connected in
parallell, and each of the pumps must then be set up to deliver the required mud pressure.
Drilling mud
Storage, pumping and cleaning of used drilling mud is described in the former sections. The
composition of drilling mud has become increasingly complex as more demands have been
made upon it. In the very beginning of the history of well drilling they just pumped down
fresh water to wash the cuttings out of the well. It was discovered that with clay present,
dissolving in the fresh water, the cuttings were transported to the surface more efficiently due
to the increased viscosity of the water.
As well were drilled deeper it was discovered that they often needed a heavier mud in order to
avoid collapse of the well. This problem was solved by mixing fine ground, heavy minerals
into the water. A heavy mineral is an advantage, because less is needed. However, because
the mineral grains are heavy compared to the liquid they will sink. The sinking speed v is
determined by the weigth of the grain in the mud divided by its cross section, giving
v   (1  m / )r , where m and  is the mud and particle densities and r is the grain radius
(the paranthesis is the buoyancy factor, see section XX). This shows that the smaller the
grains are, the slower they will sink. The diameter of the weight material grains are usually in
the range 10 – 100 m (0.01 – 0.1 mm).
Finally, by also adding some oil the basic drilling mud was created. The oil lubricated the
equipment, and also strongly reduced the loss of mud into any porous formations.
In principle any clay and any stable mineral can be used to increase the viscosity and the
density of water, but the oil industry is mainly using a clay called Bentonite, and a heavy
mineral called Baryte for this. The reasons for this are mainly due to cost and the desire too
use additives that change only one property of the mud:
- Bentonite is the clay type that gives the largest viscosity increase of water for a given
amount of clay. Only up to 7.5% (by weigth) of Bentonite is needed for obtaining any
viscosity desired, up to 50 cP. Adding Bentonite therefore do not increase the mud
density very much.
- Baryte is stable in water and a quite heavy mineral with a density of 4230 kg/m3, and
it is not too hard, which would give unnecessary abrasive wear of equipment.
- By not needing too much of both these substances transport and storage expenses are
reduced.
15
-
Both substances are not too expensive. Other clay types are generally much cheaper,
but then one would need considerably more clay, increasing the mud density to a
much larger degree. Other minerals than Baryte for weight material have been
considered, for instance Illumenite, but these are either more expensive, or being more
abrasive, or having other undesired properties.
Note that using additives that mainly change one property of the mud is rather important. For
instance, making a light, high viscosity mud would be impossible if a large amount of clay
was needed. One the other hand, making a heavy, low viscosity mud would be difficult if a
light mineral was used to increase density. A light mineral would require more mass and far
more volume of weight material than Baryte in order to make a mud of a given density. The
volume of weight material must be considerably less than the total volume of mud, this
severely restricts the density of mud possible to obtain with a light mineral.
One of the largest problems with the first fresh water mud was that it could swell and dissolve
clay in the ground. This increased the mud viscosity, but worse, it could make the walls of
the well unstable. This problem can be avoided or reduced by using salt water or oil as the
main mud component in stead of fresh water. Salt in the water reduces its ability to dissolve
clay, and oil does not dissolve clay at all. The main problem with this is increasing the mud
viscosity to the desired value, as also Bentonite is not readily dissolved. It was found to be
possible by first treating Bentonite with fresh water, then mixing the wet Bentonite into the oil
or the salt water. The Bentonite then could stay dissolved. The minimum amount of water
required to keep the Bentonite dissolved in oil is about 6%. Also for other reasons it was
found necessary to add water to oil mud, usually quite salt to avoid dissolving clay in the
formation (this water is not the fresh water used to dissolve Bentonite, but additional water to
carry other substances).
Baryte, even if like most minerals it prefer wetting by water rather than oil, is wetted by oil if
it is dry when mixed into oil. Thus, both water based mud and oil based mud consist of a
mixture of water and oil, usually also including Baryte and dissolved Bentonite. The main
difference is in how the oil and water are distributed. As oil and water are immiscible they
cannot dissolve in each other, one of these liquids (phases) has to exist as drops in the other.
In water based mud there is more water than oil, and the oil is found as drops in the
continuous water phase. In oil based mud there usually is more oil than water, and the water
is found as drops in the continuous oil phase. The defining factor is whether oil or water is
the continuous phase, not the relative amount of oil and water. It is possible to make mud
with more water than oil, but where the water exist as drops in the oil. The oil is then the
continuous phase and the mud is an oil based mud even if there is less oil than water.
In both cases the Baryte and the Bentonite are mainly found in the continuous phase. This is a
requirement for the viscosity builder (Bentonite), as the overall viscosity of the mixture is
mainly determined by the viscosity of the continuous phase. Even if the liquid found as drops
should have an infinitely high viscosity (like solid particles), it would not increase the overall
viscosity of the mud very much.
A more complete list of possible additives in the mud and the reason they are used is shown
below. Solid additives are usually supplied ground to a powder. The sizes of the powder
grains may be important for the function of the additive.
16
FUNCTION
ADDITIVE
- Density, giving desired pressure in
the well
Baryte – mineral with density 4230 kg/m3.
Generally a mud density larger than for water is
required. Any substance added in order to
increase mud density is called weigth material,
always ground to a powder.
- Cleaning hole bottom when drilling
No additives, nozzles give high speed jets that
wash away cuttings.
- Carrying cuttings up the well
Substances that increases viscosity and give gel
properties. The most common are Bentonite
(clay), density 2600 kg/m3, and polymers.
- Keep cuttings in suspension (not sinking) Substances that give gel properties, like polymers
when pumping is stopped
and Bentonite.
- Cool and clean the drill bit
No additives, the main mud phase (water or oil)
gives sufficient cooling if jets from the nozzles
and splashback from the hole bottom clean the
drill bit.
- Deposit a mud cake on the hole wall in Light minerals ground to grains still sufficiently
order to stop mud from flowing into the large to plug pore entrances and thereby stop
pore system in the formation (reservoir) smaller grains (weight material) from entering.
Not necessarily required, as the oil drops in water
mud, or water drops in oil mud, also give this
function.
- Stabilizing the hole wall
Salt and other substances that prevent formation
swelling and dissolving, mainly of clay and shale.
- Lubricating the drill string
Oil, added if water based mud is used.
- Prevent corrosion of equipment
Different corrosion inhibitors.
- Prevent bacterial growth in the well
Substances that prevent this growth.
- Prevent chemical reactions between
mud and cement when cementing
Different substances, also, the cement can or
has to be treated in order to avoid this.
- Transmit mud pulse signals
Mud should be free of gas bubbles and larger
particles, these scatter pressure pulses and
strongly reduces the strength and quality of the
signals.
- Deliver hydraulic energy to equipment
An advantage with as small and soft particles as
possible in the mud in order to reduce abrasive
wear of downhole mud motors, turbines,
hydraulic actuators, and other types of
equipments.
- Optimal distribution of water and oil
Tensides (soaplike substances) added. These
17
(size of drops) should be kept stable
accumulate at the interface between oil and water
and stabilize the size of drops.
- Make separation of cuttings and gas
from mud easier (at the surface)
This is easier if mud has a low viscosity, reduce
clay (polymer) content if possible. Adding
surfactants and deflocculants (to collapse foam) is
also useful.
In traditional drilling the mud pressure in the well is larger than the pore pressure in the
formation, but smaller than the fracture pressure. When drilling in porous and permeable
formations the mud will start to flow from the well and into the pores where the pressure is
lower. This gives loss of mud, but even worse in hydrocarbon reservoirs, the grains of the
weight material are sufficiently small to be carried into the pores. There they can get stuck in
narrow openings and block these for hydrocarbon flow into the well when the well is put into
production. As a result the permeability of the reservoir rock can be strongly reduced close to
the well. This zone of mud invasion is called the damaged zone.
In water based mud the drops of oil are in general too large (> 0.1mm) to enter the pore
openings in the hole walls, as these are in the range 0.1mm and downwards. Due to interface
tension, trying to keep these drops spherical, the oil drops are not squeezed into the smaller
pores. The oil stays at the hole wall, blocking the pore entrances. This strongly reduces the
flow of mud into the reservoir. Also, even if the flow of the water component of the mud is
not completely stopped, the solid particles in the mud, mainly the weight material and also to
some degree the clay, may be blocked. This build up a semi-solid layer of mud particles, far
more concentrated than in the original mud. This is called the mud cake. It is not unusual
that the mud penetrates up to and even farther than half a meter into the formation. This can
greatly reduce the production potential of the well. The rate of production will be lower, and
more oil or gas will be left in the reservoir when the rate drop to such a low value that further
production is uneconomical.
Drill string – drill pipes and drill collars
The drill string consists mainly of drill pipes and drill collars that are connected with conical
threads. The drill bit at the bottom of the string is also connected with the standard conical
threads. Both types of pipes are produced in lenghts of approxomately 30’ (feet), or 10 m.
These conical threads have three main advantages:
-
-
-
Only a few turns of the threads are needed to make up the connection, thus the time
used to connect up to a thousand couplings in one of the modern wells is considerably
less than if straight threads had been used.
When thightened the male threads are compressed against the female threads, making
a quite solid connection without any looseness. This is important for a drill string that
is required to stand a lot of beating.
As the threads are compressed against each other, the threads give a better protection
against leakage than straight threads. But as the top of the threads is rounded, while
the bottom is not, there is a leakage channel, see Fig. 9. To ensure no leakage in the
coupling the threads must be covered with gjengepasta, filling all openings between
the threads.
18
To avoid having the threads as the weakest point in the upper section with drill pipes,
couplings are welded to the drill pipes at each end, one with male threads and the other with
female. In the drill string the end with male threads are always oriented downwards, exept for
the drill bit. These couplings have a larger wall thickness than the drill pipes, and are more
resistant to pressure, stretch and bending than the pipe between the couplings. But not for
torque loading. In order to get a really solid connection the torgue used when making up the
connections almost induce yielding in the threads. As threads stand far less torque than a
solid pipe wall, the connections are the weak point for torque loading. When the drill string is
rotated, the torque must not exceed the make up torque for the connections. This is
approximately half the torque tolerated by the pipe walls. But as will be seen later on this is
usually no restriction upon the loading of the drill pipe.
BORERØR
VEKTRØR
Figur 9
Conical threads for connecting drill pipes, drill collars, and equipments in the
drill string. Before connections are made up, the threads are covered by a paste
that fills any opening between threads and making the connection leak-proof.
The thicker walls of the connections of the drill pipes give a considerably larger outer
diameter of the connections than the rest of the drill pipe, as shown in earlier figures. Also,
the inner diameter of the connections are usually somewhat smaller than for the pipe. The
larger outer diameter of the connections protects the drill pipe against wear, as it is mainly the
connections that are in contact with the hole wall, sliding and rotating against it. And due to
the thicker wall the connections stand more wear than the drill pipe between them. Also, the
outer surface of the connections can be covered with a more wear resistent material, or the
19
steel at the surface being tempered to a greater hardness. This is cheaper than treating the
whole length of drill pipe.
When handling the drill pipe, especially with tools that can scratch the surface, it should
always be at the connections, where it stands more abuse. Scratches, wear and other damages
on the drill pipe surface will reduce considerably its ability to withstand the loading it is
subjected to during drilling. Even if handled carefully, the drilling process will give sufficient
wear to require adaption to this in time. This is done by using three classes of drill pipe,
determined by the amount of wear. New, undamaged drill pipe belongs to class I. The drill
pipes are regularly inspected for damage when the drill string is tripped out of the well. There
is a set of clearly defined types and degrees of damages to look for, if the actual wear exceed
this the pipe is degraded to premium class. Now, there is another set of more serious damages
to look for when inspecting the pipe. If the wear exceed these the pipe is degraded to class II,
and so on. The next lower class is class III, but if the pipe gets this classification it is not used
any more in the North Sea.
During drilling the drill string can be subjected to a wide range of mechanical loading. For
instance, drilling a deep well gives a much larger loading than drilling a shallow well. The
actual calculation of these loadings is presented in the next section. But the rather obvious
result is that for drilling the shallow well a class II drill pipe can safely be used, while the
deep well require a much stronger drill pipe. In order to cover all the different loading
situation, a wide range of drill pipes is available.
- The outer diameter of the drill pipe, from around 3” to 6”, in increments of 0.5”
- For each diameter there is two or three different wall thicknesses available
- Four different steel qualities are used for all types of drill pipes, called E, X, G and S,
also denoted E75, X95, G105, and S135. The numbers give the yield limit in 1000
psi.
- For each drill pipe three or four different connections are available.
This gives about 200 different types of drill pipes to chose from. In addition there is the three
different wear classes for each type. This gives the driller the possible choice of 600 different
drill pipes. The types actually available on any given drill rigg is of course far less. Proper
planning would ensure that the types best fitted to the work intended for the rig is present, and
still sufficiently strong after wear degradation, at least to premium class. Drill pipes usually
used in the North Sea are 4.5”, 5” and 5.5”, often of high steel quality. For these large drill
pipe diameters the mass per length unit, including the connections, is around 30 kg/m.
As mentioned before the connections are welded on to the drill pipe. Probably in order to
minimize the size of the connections (and get some standardization) the connections are all
made from the same high steel quality, with a strength (yield limit) of 120,000 psi, midway
between the two top steel qualities used in drill pipes (G and S). But this requires heavier
connections for the higher steel qualities of drill pipe in order to match the increased pipe
strength. The weight of a given size (diameter and wall thickness) of drill pipe therefore
increases with steel quality, not because the pipe itself is heavier, but because the connections
are. Note that the density of steel is almost independent of its quality. For any given outer
diameter the pipe weight per length unit (between the end connections) can therefore be used
as a measure of the wall thickness, independent of the steel quality. This is also usually done.
But remember that this is only a way to classify the pipe, it is useless for actual calculations of
drill string weight because it does not include the weight of the connections. Examples of
tables with drill string data is given in the next section.
20
The main function of the drill collars is to supply weight to the drill bit (WOB). In order to
avoid long pipe sections under compression, the drill collars can have outer diameters
approaching that of the well. The resulting narrow space between the hole walls and the drill
collars cannot then be made even narrower with even larger diameter connections. This
would give a serious restriction for the return flow of drilling mud up the well. There is then
no need for welded on connections. Here the conical threads are machined into the end of the
pipe, as shown in Fig. 9. In this case the connections are the weak points, both for pressure,
axial load (stretch or compression) and torque. But due to the much larger wall thickness
usually found on drill collars as compared to drill pipes, the drill collar connections are still
considerably stronger than the drill pipe.
Also, the drill collars are at the bottom of the drill string, where pressure loading, axial forces
and torque are considerably less than at the top of the string, where the drill pipes are found.
Due to this it is generally assumed that the static load is largest at the top of the drill string,
and that drill collar connections will not fail due to static loads. But dynamic loads (shocks
and vibrations) may be far larger at the bottom of the string than at the top. In fact, quite
often when the drill string fails, it is a drill collar connection that breaks. One of the greatest
improvements in present day drilling is the possibility to monitor downhole vibrations and
change drilling parameters, usually rate of rotation (RPM) and weight on bit (WOB) in such a
way that these vibrations are reduced to safe levels.
For wells in the North Sea drill collars with outer diameters from 6” to 14” can be used, with
mass from 87 kg/m to 750 kg/m. Each size is produced with a number of wall thicknesses, or
inner diameters. For instance, drill collars with outer diameter of 8” are available with eleven
different inner diameters, from 1.5” to 4”, in increments of 0.25”. In practice, for the mud
flow rates often used, the inner diameter should not be less than 3”, this would increase flow
resistance dramatically. In order to avoid excessive flow resistance of the return mud flow,
the outer diameter of the drill collars should be at least 1.5” less than for the drill bit in use,
preferably at least 2” less (the drill bit diameter gives the diameter of the hole).
With this restriction of the outer diameter the weight of the drill collars can be increased by
reducing the inner diameter. But for inner diameters already considerably less than the outer
diameter this does not help much. For instance, for the 8” drill collar, the weight increases
only from 218.8 kg/m to 229.7 kg/m when inner diameter is decreased from 3” to 2.5”. This
is a weight increase of only 5%, while the flow resistance increases by 140% for a flow rate of
2000 l/min.
The usual classification of drill collars is by outer diameter (in inches) and the mass per unit
length (for instance kg/m). From standard tables the inner diameter can then be found. In this
case, where there are no connections with larger diameters, the nominal weight is also the
actual weight including the connections.
In addition to standard drill pipes and drill collars there is also available heavy weight drill
pipes, with a weight somewhere in between drill pipes and collars. These have larger
diameter connections, and an outside often shaped like an elongated spiral.
The drill pipe does not stand axial compression very well, it will buckle and be easily twisted
off and destroyed if drilling is performed with axial compression. The drill pipe should under
all circumstances be in axial tension. The drill collars, with their much larger wall thickness
21
stand axial compression much better. All the downward force on the drill bit should therefore
be supplied by the lower part of the drill collars, as a possible rule of thumb the lower 2/3 of
the drill collars should be resting their weight upon the drill bit, while the rest of the drill
string, the upper 1/3 of the drill collars and the whole drill pipe section should be hanging
from the top drive and thus be in tension.
Depending upon the type and size of the drill bit the recommended WOB is around 5 to 60
tons (50 – 600 kN). This means that a sufficiently large drill collar section would weigh (in
the drilling mud actually used), around 7.5 to 90 tons. If for instance a 8” outer diameter, 3”
inner diameter (mass 218.8 kg/m) is used, the length of the drill collar section should at least
be from 41 to 495 m long (for a mud density of 1200 kg/m3). Note that this is a minimum
length, this section can very well be longer, at least for safety reasons. Also, 41 m is a bit
short, so in this case drill collars with a smaller outer diameter would probably be used.
Usually, the range of drill collar section length is from 50 to 200 m. The drill bit requiring
WOB = 600 kN is probably a large diameter bit, for instance 26”. The large diameter hole
then allows for much heavier drill collars, where a lenght of 200 m would give 600 kN.
As a typical well in the North Sea may easily be several kilometers, by far the largest part of
the drill string will be the drill pipe section.
Figure 10
Centralizer, seen from below and from the side, as mounted on the drill collar
section. Usually, the centralizer would have more slots (6 – 8 slots).
A few places along the drill collar section, usually at least three, centralizers are mounted.
These have an outer diameter close to the hole diameter and keep the drill collar section
centered in the hole, preventing it from jumping around in the well. The excact placements of
these is important for steering of the drill bit, this is discussed in a later section. These
centralizers have slanted slots machined into their outer surface, allowing the return drilling
mud flow up the annulus to flow freely, see Fig. 10.
Drill string – equipment in the string
Almost all of the equipment that is used in the drill string is mounted in in the section with
drill collars, for the following reasons:
22
-
-
For measuring equipment it is most useful to do mesurements close to the drill bit, in
the section of the well being presently drilled. This gives the earliest possible warning
of any changes of the drilling conditions.
Mechanical equipment has in most cases functions related to the drill bit and must be
close to it.
All the equipment must be mounted innside heavy wall pipes to be protected, these
pipes are called the housing of the equipment. These pipes must be sufficiently strong
to stand the loads the drill string is subjected to during drilling. At the same time there
must be a channel innside the pipe where the drilling mud can flow down towards the
drill bit. In most cases the eqipment cannot have an outer diameter larger than the drill
collars. Making equipment sufficiently small to fit innside pipes of the same diameter
as the drill pipes is at present very difficult, if not impossible.
Equipment housing is preferably more or less of the same dimensions as the drill collars, and
with the same type of connections. This ensures that they can be mounted directly in the drill
collar section, just as the drill collars. The lower part of the drill string, the drill collars,
measuring and communication equipment (mud pulses), mechanical equipment, and the drill
bit, is called the bottom hole assembly, often abbreviated to BHA.
TOP
DRIVE
JAR FOR Å SLÅ LØS
FASTKJØRT BORESTRENG
STABLISATOR
SEKSJON
MED
BORERØR
MÅLEUTSTYR OG
DATALAGRING
STABLISATOR
STØT OG VIBRASJONSDEMPER
SLAMMOTOR
SEKSJON
MED
VEKTRØR
BHA
STABLISATOR
STYRING AV BORERETNING
BOREKRONE
BORESTRENG
Figure 11
BHA
Scketch of drill string with its BHA section shown in more detail. Possible
placement of different equipment is indicated. All the equipment units (exept
for the drill bit) are shown strongly compressed in the axial direction.
The equipment in the string can be divided into five groups:
23
1
2
Equipment for steering of the drill bit, especially important when drilling along
reservoirs (horizontal wells) or around hindrances.
Downhole motor and power transmission for rotating the drill bit, and
eventually motors for other equipments. In most cases the downhole motor is a
mud motor, this is a long rod shaped like a cork screw that is forced to rotate
within its housing as the downward flow of drilling mud goes through the
motor.