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Drilling Engineering 1 Course (2nd Ed.)

1. Drilling Fluid Circulation System
A. Mud Pumps (Duplex PDP & Triplex PDP)
B. Solids Control Equipment
a. Mud Cleaners
C. Treatment and Mixing Equipment

1. The Rotary System
A. Introduction
B. Kelly, Kelly Valves, and Kelly Saver Sub
C. Rotary Table and Components
2. Well Control System
3. Well Monitoring System

Introduction
The rotary system is the set of equipment
necessary to promote the rotation of the bit.
The bit must be
mechanically and
hydraulically connected to the rig.
This connection is made by the drillstring.
The purpose of the drillstring is
to transmit axial force,
torque, and drilling fluid (hydraulic power)
to the bit.
Spring14 H. AlamiNia Drilling Engineering 1 Course (2nd Ed.) 5

Drillstring components
The basic drillstring is composed of the following
components:
Swivel,
Kelly and accessories,
Rotary table and components,
Drillstring tubulars
(drill pipe, drill collars, etc.),
Drill bit.
Several other components and equipment
can be connected to the drillstring
to perform several tasks and
to lend to the drillstring special features.

Swivel
The swivel
is suspended by the hook of
the traveling block and
allows the drillstring to rotate
as drilling fluid is pumped
to within the drillstring.
supports the axial load of the
drillstring.
Without the swivel,
drilling fluid could not be
pumped downhole,
or the drillstring could not
rotate.
A flexible hose connects to
the gooseneck
which is hydraulically coupled
to the top of the swivel stem
by a stuffing box.
The stem shoulder
rest on a large thrust tapered
roller bearing,
which transmits the drillstring
weight to the swivel body, and
then to the bail.
The thread connector of the
swivel
is cut left–hand so that
it will not tend to disconnect
when the drillstring is rotated
by the kelly or
by the top drive.

cuts of a swivel
showing the internal parts
Sample of Tapered Roller
Bearings Thrust

kelly
Below and connected to the swivel is
a long four-sided (square) or
six-sided (hexagon)
steel bar with a hole drilled through
the middle for a fluid path called kelly.
The purpose of the kelly is
to transmit rotary motion and torque
to the drillstring
(and consequently to the drill bit),
while allowing the drillstring
to be lowered or raised during rotation.
The square or hexagonal
section of the kelly
allows it to be gripped and turned
by the kelly bushing and rotary table.
A square kelly and
a hexagonal kelly

kelly bushing
Torque is transmitted to
the kelly by
the kelly bushing.
The kelly bushing
has an inside profile
matching the kelly’s
outside profile (either
square or hexagonal),
but with slightly larger
dimensions
so that the kelly can
freely move up and down
inside it.
The overall length
of the kelly
varies from 40 ft to 54 ft.
Kelly bushings

kelly valves
It is common (and advisable) to include
two special valves at both ends of the
kelly,
called kelly valves.
 (The upper kelly valve has left–hand
threads.)
The kelly valve consists of a ball valve
which allows free passage of drilling
fluids without pressure loss.
 This is a safety device that
can be closed to prevent flow from inside
the drillstring during critical operations
like kick control.
 It also
isolates the drillstring from the surface
equipment and allows disconnecting the
kelly during critical operations.
A kelly valve

kelly saver sub
A kelly saver sub is simply a short length pipe with
has male threads on one end
and female on the other.
It is screwed onto the bottom of the lower kelly valve or
top drive and onto the rest of the drillstring.
When the hole must be deepened,
and pipe added to the drillstring,
the threads are unscrewed between the kelly saver sub
and the rest of the drillstring,
as opposed to between the kelly valve or
top drive and the saver sub.

kelly saver sub (Cont.)
This means that the connection between the kelly or
top drive and the saver sub rarely is used,
and suffers minimal wear and tear,
whereas the lower connection is used in almost all cases and
suffers the most wear and tear.
The saver sub is expendable and
does not represent a major investment.
However, the kelly or top drive component threads
are spared by use of a saver sub, and
those components represent a significant capital cost and
considerable downtime when replaced.
It is important that both lower kelly valve and kelly
saver sub be of the same diameter of the drill pipe tool-
joints to allow stripping into the hole during control
operations.

master bushing and master casing
bushing
The kelly bushing fits in
the master bushing,
which, in turn, attach to
the rotary table.
It connects to the master
bushing either by pins of
by a squared link.
The master bushing
transmit torque and
rotation from the rotary
table to the kelly bushing.
A master casing bushing
is used to handle casings.
Master bushings, and casing bushing

Kelly bushing and master bushing
Figure shows
a kelly
bushing,
master
bushing, and
rotary table
assembly.

Drillpipe slip (detail when
set in the master bushing)
The master bushing
(and also the master casing bushing) has
a tapered internal hole.
 The purpose of the tapered hole is to
receive the pipe slips.
 During pipe connection or
drillstring trip operations,
this tapered hole receives either
the drill pipe slips, or the drill collar slips,
or the casing slips,
which grips the tubular and
frees the hook from its weight.
Because of
the slick shape of most drill collars,
 a safety clamp is always used above the
drill collar slips (mandatory!)
 If the drill collars slides in the slips,
the safety clamp works as a stop to force
the slips to grip the drill collar.

DC slips, safety collar, casing slips and
A rotary table
A drill collar slips (a),
a safety collar (b), and
a casing slips (c) are
shown in the Figure.
The rotary table
receives power from
the power system
(either mechanical or
electric.)
A gearbox allows
several combinations of
torque and speed.

well control & kick
The functions of the well control system are
to detect, stop, and remove any undesired
entrance of formation fluids into the borehole.
An undesired entrance of formation fluid
into the borehole is called kick and
may occur due to several reasons
(high pressure formations,
insufficient drilling fluid density,
drillstring swab,
loss of circulation,
formation fracture,
etc).

blowout
If the undesired entrance of fluid feedbacks and
the fluid continuously enters the borehole
reaching the surface,
it is called blowout.
Blowouts (in particular gas blowouts)
are extremely dangerous and
put the crew, the rig, the drilling operation, and
the reservoir at risk.

well control system constituent
The well control system must
detect, control, and remove
the undesired entrance of fluids into the borehole.
The system is composed of
sensors (flow rate, surface volume, annular and
drillstring pressure, and etc,) capable to detect
an increase of flow or volume in the fluid system,
the blowout preventer (BOP),
the circulating pressure control manifold
(choke manifold),
and the kill and choke lines.

the blowout preventer (BOP)
The BOP is a set of pack–offs capable of shutting
the annular space between the surface casing and
the drillstring.
Because of the diversity in shape of the annular,
several different device types exist and
they are normally assembled together
(and in various configurations) called BOP stack.
The BOP stack is located
under the rotary table
in land and fixed marine rigs,
and on the bottom of the sea
in mobile and floating rigs.

BOP stacks
A fixed rig BOP A floating rig BOP

Annular BOP’s
The various types of BOP
devices are:
Annular BOP, Blind ram, Pipe
rams, and Shear rams
Annular BOP:
The purpose of the annular
BOP is to shut the annular
in front of any kind of
drillstring equipment
(except stabilizers) or
even without drillstring.
The active element is an
elastomeric ribbed donut
that is squeezed around
the drillstring
by an hydraulic ram.
It is located
at the top of the BOP stack.

an inside BOP
Controlling the pressure applied
to the ram, it is possible to strip
the drillstring in and out while
keeping the annular closed
(requires the use of an inside-BOP,
which should be connected
immediately to the drillstring
when a kick is identified).
The inside BOP acts as a check
valve, allowing fluid be pumped
down the drillstring,
but blocking back flow.

Blind & Pipe rams
Blind ram:
The blind rams (normally one at the top of all other rams)
allows shutting the borehole with no drillstring element in
front of it. (the upper ram in the figure)
If the blind ram is applied to a drillpipe, the pipe
will be flatten but no seal is obtained.
Pipe rams:
The pipe rams allows shutting the annular
in front a compatible drill pipe (not in front of tool joints.)
Normally two rams are used
a special spool between the two is used where the kill and
choke line is connected. (the lower ram in the figure)
The use of two pipe rams also
permit to snub the drillstring during the well control operation.

shear rams
Shear rams:
The shear ram
(normally one below the
blind ram or below all
other rams) can shear a
drill pipe and provide seal.
This is a last resource
when all other rams and
annular had failed.
Circulation through the
drillstring is lost and,
if the shear ram is the
lower one,
the drillstring falls into the
borehole.

BOP control panels
All these safety devices
are hydraulically actuated
by a pneumatic–hydraulic
system
(actuators and
accumulators),
which can operate
completely
independent of the power
system of the rig.
Two control panels are
normally used,
one at the rig floor,
and a remote one away
from the risky area.
BOP accumulators and control panels

The accumulators
The accumulators are steel bottles lined
with a elastomeric bladers
forming two separated compartments.
One compartment is filled with oil,
which powers the BOP.
The other compartment is filled with air or nitrogen
at high pressure.
The pressure of the gas pressurizes
the oil across the elastomeric liner.
Rig power, during ordinary operation,
keeps the gas in the accumulators under pressure.
The accumulators should be able
to provide hydraulic power to close and open all elements
of the BOP stack a number of times without external power.

Choke Manifold
During a kick control operation, some of the BOP
stack devices are actuated
to close the annulus and
divert the returning fluid to the choke line.
The choke line directs the returning fluid to a manifold
of valves and chokes called choke manifold,
which allows to control the flow pressure
at the top of the annular adjusting the flow area open to flow.
The choke manifold also direct the flow
• to a flare (in case of a gas kick), or
• to the pits (if mud) or
• to special tanks (if oil)

Choke manifold

data required to control of operations
under way in the rig
Several sensors, gauges,
meters, indicators, alarms,
and recorders exist
in the rig to provide all
data required to control
(safely, efficiently, and
reliably) of all operations
under way in the rig.
Among the most
important parameters are:
weight on bit (WOB) and
hook load,
rate of penetration (ROP),
rotary speed,
torque,
circulating (pump) pressure,
flow rate (in and out),
drilling fluid gain/loss,
mud temperature,
mud density,
total hydrocarbon gas
in the drilling fluid.

indication of
hook load and weight on bit
Accurate and reliable indication
of hook load and weight on bit are essential for
the efficient control of rate of penetration, bit life, borehole
cleaning, and borehole direction.
The weight indicator works
in conjunction with the deadline anchor
using either tension or compression hydraulic load cells.
The deadline anchor senses the tension in the deadline and
hydraulically actuates the weight indicator.
Most weight indicators have two hands and two scales.
The inner scale shows the hook load and
the outer one shows the weight-on–bit.

Weight indicator and
a deadline anchor
Weight indicator a deadline anchor

weight–on–bit
To obtain the weight–on–bit,
the driller perform the following steps:
with the bit out of the bottom,
the drillstring is put to rotate and
the weight of the drillstring is observed in the central scale;
using the knob at the rim of the weight indicator,
the outer scale is adjusted so that
the zero of the outer scale aligns with the longer hand.
The driller lowers the drillstring slowly observing the long
hand.
When the bit touches the bottom, part of the weight of the
drillstring is transferred from the hook to the bit
(the weight–on–bit.)
The amount of weight transferred corresponds to
the decrease of hook load,
indicated by the long pointer (turning counterclockwise).

control consoles
All modern rigs have control consoles that
shows all pertinent parameters in analog and
or digital displays.
All parameters and operations may be
recorded in physical (paper) or
magnetic media for post analysis.
Some automated operations like
constant weight–on–bit and
constant torque are possible in most rigs.

Drilling control console

1. Jorge H.B. Sampaio Jr. “Drilling Engineering
Fundamentals.” Master of Petroleum
Engineering. Curtin University of Technology,
2007. Chapter 2

1. Drillstring Tubulars
A. Drill Pipes
a. properties of drill pipes
B. Drill Pipe Elevator
C. Drill Collars & Heavy Wall Drill Pipes

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