Rotary Drilling Methods Basic Petroleum Training

Shell Special Intensive Training Programme Basic Petroleum Technology
Oyeneyin, M.B Page 1 of 15 ©Univation
5 DRILLING MFTHODS - ROTARY DRILLING
5.1 Introduction
This section is focused mainly on the conventional rotary drilling method. A
general introduction to new rig systems such as ram rig is also presented.
There are a number of different drilling methods that have been utilised in the oil
industry or are in their prototype stage of development.
The oldest of the methods is Cable tool drilling method, which uses the
percussion method. This percussion method is now finding its way back with the
advent of the percussion hammer drilling technique, which is still in its
development stage for hard rock drilling.
Other techniques in their development stage include
1. The high Jet velocity bit
2. The Laser drilling system
However, the popular conventional method used in the oil industry is the Rotary
drilling method.
5.2 The Rotary Drilling Method.
In this method, the hole is drilled by the rotating action of the drill bit to which a
downward force is applied. The bit is attached to a drill string made up of the
drillpipe and bottom hole assembly (BHA) . New lengths of drillpipe are added as
drilling progresses. The BHA can be made up of a number of different systems,
which can include drill collar, stabiliser, Measurement While Drilling (MWD) tools,
Mud motor, etc. The generated cuttings are circulated out of the hole via the
annulus by the drilling mud which are continuously circulated down the inside of
the drillstring through the bit nozzles and upward the annular sections and back
to the surface tanks/treatment facilities via the shale shaker.
In order to carry out the drilling, there are number of different types of rotary
drilling rigs available depending on whether they are being used onshore or

offshore. The offshore rigs fall into several categories designed to suit certain
types of offshore environment. Details of these are presented in Section 12.
5.3 Basic Rig Components
The drilling rig performs four major functions. These are:
Hoisting
Rotating
Circulating
Controlling
The principal components of a rotary-drilling rig that perform these functions are
presented in Fig. 5. 1.
The Hoisting System
The hoisting system is made up of:
• The Derrick/Substructure (fig5.2): These support the weight of the drillstring
and provide the vertical clearance required for tripping operation during
drilling. The substructure also supports the rig floor equipment and provides
the workspace for its operation. A joint of drillpipe is about 30ft and a
minimum of three stands of pipe is pulled at a time. So the derrick clearance
must meet this minimum length.
• The Drawworks: This is a spool upon which the heavy steel cable is
wrapped. From the drawworks, the line is threaded through The Crown
Block at the top of the derrick and then through The Travelling Block, which
hangs suspended from the crown block. By reeling, the drilline from the
drawworks drum can be raised or lowered. Hydraulic Brake systems control
the speed of the travelling block and a mechanical brake brings the system to
complete stoppage.
The Drawworks also features an auxiliary axle with rotating spools
Catsheads) on each end.

The hook is attached to the travelling block and is used to pick up the
drillstring via the swivel and kelly units.
Overall, the derrick is chosen based on the following criteria
1. Maximum compressive load anticipated. This is based on the maximum
casing load. The derrick load can be calculated from the following equation :
W
n
n
Fd
2+
=
n = No. of lines through the travelling block.
W = Hook load
During hoisting, velocity of line being spooled at drawworks is :

vL = nvh
2. Maximum wind velocity expected in an area. Wind loads can be calculated as
follows:
Fw = 0.004V2
.
V = Wind velocity, mph.
Drawworks are normally designated by horsepower and depth rating
η
1
.
33000
hWv
HP =
W = Hook load, lb
Vb = Holst,mg velocity
η = Hook to drawworks efficiency.
The Rotating System
The rotating system Is made up of:
• The Swivel: This system allows the drillstem to rotate while supporting the
weight of drillstring and providing a pressure-tight connection for the
circulation of drilling fluid. The fluid enters the swivel via the Gooseneck
connected to the Rotary Hose.
• The Kelly: This can be a 3-, 4-, or 6-sided length of hollow steel which is used
to transmit the rotary movement from the rotary table to the drillstring in a top
drive system.
• Drillstem: Drillstring + Kelly + bit.' A kelly cock prevents back flow through
kelly to the swivel. There is an upper kelly cock near swivel and a lower kelly
cock at end of kelly.
• The Rotary Table: This system transmits the rotation to the drill string and
suspends the pipe weight during trips

The downhole BHA could include a downhole motor especially for drilling
deviated or horizontal wells. In this case, there is no rotation of the drillstring.
Rotation of the bit is effected by the downhole mud motor or turbine.
The Circulating System (Fig. 5.3)
The system is made up of
The Mud Pumps: The pumps circulate the drilling fluid at the required pressure
and flow rate. The most popular is the reciprocating pump which can be double
acting (Pumping in two opposite directions) duplex or triplex (3-piston)pumps.
Merits include ability to handle solid-laden fluid, simplicity of
operation/maintenance' Wide range of flow rate and pressure available with
different piston and liner sizes. Stabilized flow is achieved with surge or pulsation
dampeners.
They are commonly denoted by bore and stroke length as well as horsepower
requirement.
For a duplex pump, pump rate is
[ ]v
v
dDSNNS
dD
S
D
q η
ηπππ 22
222
200679.0
231
.
44
2
4
2 −=











−+





=
q = pumping rate, gpm
D = Liner size, ins.
d = piston rod diameter, in.
N = Pump speed = Piston strake/4
S = Stroke length, in.
η= Volumetric efficiency
Output horse power requirement
HP =
1714
qp
Input Power Requirements

HPInput =
m
qp
η1717
• Mud Tank: The mud pump pumps drilling fluids from the mud tanks up the
standpipe through the rotary hose connected to the swivel via the
gooseneck.
• Return Lines: The fluid from the annulus returns via the return fine to the
Shale shaker, which removes the large cuttings. Then the fluids pass
through the desanders, desilters and degassers where other smaller solids
and gas bubbles are stripped off before the system returns to the suction
tank or active pit.

The control System
A. The BOP System (fig. 5.4)
Controlling the subsurface formation pressure is one of the major parts of a
drilling operation. To help control any potential influx of formation fluid, the
blowout preventers(BOP) plus their support systems provide this service.
The BOPs are stack of series of hydraulically operated powerful sealing elements
designed to close off the annular space between the drillpipe and hole thus
shutting-in the well. During shut-in, the wellbore fluid is forced to flow through a
choke line from where the outflow and pressure can be managed to prevent
blowout.
Fig. 5.4: The BOP System

The BOP system is made up of:
• The Annular Preventer : These are made up of rubber scaling elements that
are hydraulically squeezed to conform tightly around the drillstring in the hole.
• The Ram type preventers: These are made up of the rubber-linen steel rams
called the pipe rang and also the shear or blind rams which can be used to
shear any pipe in two in case of final emergency to close the well.
• Accumulators: The BOPs are hydraulically controlled via the accumulator
which is a choke manifold that houses a series of adjustable chokes
controlled from a remote panel on the rig floor.
B. The Prime Mover (Fig. 5.5)
All the hoisting, rotating and circulating systems are supplied with power by the
prime mover, which are usually diesel engines although the modem rigs do utilise
diesel-electric systems
Fig: 5.5: Prime Movers

5.4 The Drillstem
In addition to the drillbit and drillpipe the drill string Is made up of other BHA
assemblies such as:
• The Drillcollar: This system furnishes the necessary weight an bit(WOB)
expected to keep drill string in tension to maintain rigidity. and
• Crossover sub: Designed to link different sizes of types of BHA systems with
different joints and threads.
• Shock sub: System run behind the bit with a spring or rubber to dampen
impact of bit drilling.
• Bumper sub : Telescoping joint to help maintain a constant weight on bit
• Useful in offshore platforms.
• Stabilisers: These are subs with "blades" to keep the drill collars centred in
the hole.
• Other subs: LWD or MWD subs; Jet subs, etc. as required.
5.5 The Drillbit
The process of 'making the hole' requires the use of a drill bit which is of critical
interest to the mud logger. The rate of bit penetration is controlled by mechanical
operating parameters such as weight on bit (WOB) and rotary speed as well as-
the- physical strength of the formation. Instantaneous changes in formation
penetration rate (ROP) are one of the potential indicators of transition &om
normal to abnormal formation conditions. It indicates possible changes in
porosity, lithology even before cuttings are seen or examined. It also provides a
good source of sampling cuttings, which is a useful aspect of mud logging.
Types of Bits
There are three types of drillbit. These are:

1. The drag bit - This bit works on the principle of plowing the cuttings from the
hole bottom. They include
• the conventional steel cutters popular with water wells
• Diamond bits - These are used for ultra deep drilling of hard and abrasive
formations. They boast of long life and have no moving parts that can be
subject to wear and erosion. They are however expensive, have low ROP, do
not respond to changes in lithology and cuttings quality and recovery are very
poor.
• PDC bits (Polycrystalline diamond bits) - PDC bits (Fig 5. ) are becoming
increasingly popular and are finding successful applications in drilling
sandstones, slitstones and shale. Best applications are in soft, firm and
medium hard, non-abrasive formations. However, combined with optimum
hydraulics design, they have been found to be useful even in gummy, sticky
formations where bit balling is a possibility. Performance in hard formations is
very poor.
• In addition to the double-cone profiles, single cone profiles of various tapers
and flat bottom profiles are used for PDC bits with hydraulic cleaning action
being achieved by using jets and water courses.
• Other important features of the PDC its are the size, shape, and number of
cutters used and the angle of attack between the cutter and surface of the
exposed formation. Cutter orientation is defined in terms of the back rake,
side rake and chip clearance or cutter exposure.
• PDC bits can produce, large, fresh sheared cuttings and are relatively
cheaper than pure diamond bits. They are best with
2. Rolling Cutter Bits - The three-cone roller cutter bit is the most popular bit
type used for most drilling operations. The modern tricone roller cutter uses
three rotating cones with intermeshing teeth to crush and gouge formation
materials from hole bottom. The teeth may be long, slender, and widely
spaced for drilling soft and medium soft formations. They may also be short

and broad for drilling hard formations. Many of the hard formation tricone bits
nowadays have inserts made of sintered tungsten carbide. The three cones
are mounted on bearings and scaled which are cooled and lubricated by
specially arranged nozzles/water courses that regularly clean the bit teeth.
Shape and size of drilled cuttings reflect the shape, length and spacing of bit
teeth. Long, slender teeth produce large freshly broken cuttings from soft
formations. Broad teeth and inserts will produce smaller, more rounded, crushed
and ground cuttings.
Other bits used for special applications are :
1. Hole Reamers - Used for enlarging the size of a borehole
2. Core Bits - For cutting cores. These are used in conjunction with core barrels
for ”sampling" a zone of interest.
5.5.2 IADC Classifications
The International Association of Drilling Contractors (IADC) have classified bits
by different manufacturers into Series numbers . The serialisation is as follows:
Series No. Formation
A. FOR MILLED TOOTH BITS
1 Soft formation with low compressive
strength and high drillability
2 Medium/Medium hard formations with
high compressive strength
3 Hard/Semi abrasive and abrasive
B. INSERT BITS
4. Soft formation with low compressive
strength

5. Soft to Medium hard formations with low
compressive strength
6. Medium hard formations with high
compressive strength
7. Hard /semi abrasive and abrasive
8. Extremely hard/abrasive
5.6 WOB and RPM
Penetration rate (ROP) is a complex relationship between the Weight on bit
(WOB), Rotary speed (RPM), formation strength, type of bit, bit hydraulics and
the prevailing operating conditions and formation pressure.
One mathematical definition gives this as
ROP = K (W/Db)a
*Nb
W = Bit weight with exponent ‘a’
K = Constant of proportionality which accounts for effect of rock strength,
Db = Bit size
N = Rotary speed with exponent b
For a given formation, and prevailing operating conditions in the wellbore
annulus, increase in WOB can result in increase in ROP up to a threshold point
after which it starts decreasing. This can be said to be the critical Weight on bit
and it is the point at which floundering starts occurring. Likewise, at increasing
rotary speed, the ROP will increase but the speed would be limited by the weight
on bit.
The combined effect would change for different lithologies and the best approach
is to set the appropriate correlation for a given lithology and wellbore condition in

the Drill-off test technique. This test establishes the ROP profile for different
WOB and RPM.
Overall the cost per foot of bit run would dictate the optimum WOB and RPM
5.7 WOB Estimation for Deviated and Horizontal Wells
In deviated and horizontal wells, the actual weight on bit at hole bottom is usually
less than the Weight at surface for an equivalent vertical well.
In general the drilling of highly deviated and horizontal wells is usually
accompanied by possible use of downhole motor or turbine instead of the
conventional drill string or top drive rotary table. These are mainly useful for
defining hole trajectory and minimising downhole problems including drillstring
balling and failure.
Determination of True WOB in highly deviated/Horizontal Wells.
1. Estimate the pump off force, Fh
Fh = Fdo - Fob
Fdo = Hook load with bit just dn'iled off
Fob = Hook load with bit off bottom
2. Determine pressure drop across bit, ∆pb,
∆pb = pdo - pob
pdo = Standpipe pressure with bit drilled off
pob = Standpipe pressure with bit off bottom
This involves taking a first reading of standpipe pressure with first hook load
recording.
3. Estimate the Pump-off area, Apo
Apo = Fh/∆pb

Thus will pump off area known and off-bottom standpipe pressure know, it is
possible to compute true Weight on Bit for any surface measurement.
4. Given a new surface indicated WOB' and corresponding standpipe drilloff
pressure of pdo Compute a new pb’= pdo’- pob
5. Compute new pump-off force, Fb
,Fb = ∆pb’* Apo
6. True WOB = WOB' - Fb
Example Illustration
Given that the hook load with pump off bottom = 15200lbf and the corresponding
standpipe pressure is 1920psi. The determined pump-off point = 2525psi.
∆pb = 2525 - 1920 = 605psi
Now, Apo = 15200/605 = 25.1 in2
For a new hook load of 380001bf, standpipe pressure = 2555psi.
∆pb’= 2555 - 1920 = 635psi
New Force, Fb= 635 x 25.1 = 159391bf
Therefore,
True WOB = 3 8000 - 1593 9 = 22061 lbf.

Rotary Drilling Methods Basic Petroleum Training

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