1. Drilling Engineering 1 Course (2nd Ed.)

2. 1. Power System
2. Hoisting System:
A. Introduction
B. The Block & Tackle
a. Mechanical advantage and Efficiency

3. 1. Hoisting System:
A. The Block & Tackle
a. Hook Power
B. Load Applied to the Derrick
2. Drilling Fluid Circulation System
A. Mud Pumps

5. Input vs. output power
For an ideal block–tackle system,
the input power (provided by the drawworks)
is equal to the output or hook power
(available to move the borehole equipments).
In this case,
the power delivered by the drawworks is equal to
the force in the fast line Ff
times the velocity of the fast line vf , and
the power developed at the hook is equal to
the force in the hook W
times the velocity of the traveling block vb.
That is
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6. relationship between the drawworks
power and the hook power
Since for the ideal case n Ff = W, so
that is, the velocity of the block is
n times slower than the velocity of the fast line, and
this is valid also for the real case.
For the real case, Ff=W/nE, and multiplying both
sides by vf we obtain
which represents the real relationship between the
power delivered by the drawworks and the power
available in the hook,
where E is the overall efficiency of the block–tackle system.
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7. The Block & Tackle
A rig must hoist a load of 300,000 lbf.
The drawworks can provide a maximum input
power to the block–tackle system of as 500 hp.
Eight lines are strung between the crown block and
traveling block.
Calculate
(1) the tension in the fast line
when upward motion is impending,
(2) the maximum hook horsepower,
(3) the maximum hoisting speed.
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8. The Block & Tackle
Using E = 0.841 (average efficiency for n = 8) we
have:
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10. The total load applied to the derrick
The total load applied to the derrick, FD
is equal to the load in the hook
plus the force acting in the dead line
plus the force acting in the fast line
for the force in the fast line
The worst scenario is that for the real case.
For the dead line, however,
the worst scenario (largest force) is that of ideal case.
Therefore, the total load applied to the derrick is:
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11. Derrick floor plan
The total load FD,
however, is not evenly distributed
over all legs of the derrick.
In a conventional derrick,
the drawworks is usually located
between two of the legs
The dead line, however must be
anchored close to one of the
remaining two legs
The side of the derrick opposite to
the drawworks is called V–gate.
This area must be kept free to allow
pipe handling.
Therefore, the dead line cannot be
anchored between legs A and B
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12. the load in each leg
From this configuration the load in each leg is:
Evidently, the less loaded leg is leg B.
We can determine under which conditions the load
in leg A is greater then the load in legs C and D:
Since the efficiency E is usually greater than 0.5,
leg A will be the most loaded leg,
very likely it will be the first to fail
in the event of an excessive load is applied to the hook.
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13. The equivalent derrick load and
The derrick efficiency factor
If a derrick is designed to support a maximum nominal
load Lmax, each leg can support Lmax 4 .
Therefore, the maximum hook load that the derrick can
support is
The equivalent derrick load, FDE,
is defined as four times the load in the most loaded leg.
The equivalent derrick load
(which depends on the number of lines)
must be less than the nominal capacity of the derrick.
The derrick efficiency factor, ED
is defined as the ratio of the total load applied to the derrick
to the equivalent derrick load:
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14. derrick load
A rig must hoist a load of 300,000 lbf.
Eight lines are strung between the crown block and
traveling block.
calculate
(1) the actual derrick load,
(2) the equivalent derrick load, and
(3) the derrick efficient factor.
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15. derrick load
Solution:
Using E = 0.841 (average efficiency for n = 8) we have:
(1) The actual derrick load is given by
(2) The equivalent derrick load is given by
(3) The derrick efficiency factor is
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18. drilling fluid roles
The drilling fluid plays several functions in the
drilling process.
The most important are:
clean the rock fragments from beneath the bit and
carry them to surface,
exert sufficient hydrostatic pressure
against the formation
to prevent formation fluids from flowing into the well,
maintain stability of the borehole walls,
cool and lubricate the drillstring and bit.
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19. Drilling fluid circulation
Drilling fluid is forced to circulate in the hole
at various pressures and
flow rates.
Drilling fluid is stored
in steel tanks located beside the rig.
Powerful pumps force the drilling fluid
through surface high pressure connections
to a set of valves called pump manifold,
located at the derrick floor.
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20. Drilling fluid circulation (Cont.)
From the manifold,
the fluid goes up the rig
within a pipe called standpipe
to approximately 1/3 of the height of the mast.
From there the drilling fluid flows through a flexible
high pressure hose to the top of the drillstring.
The flexible hose allows the fluid
to flow continuously
as the drillstring moves up and down
during normal drilling operations.
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21. swivel
The fluid enters in the
drillstring through a special
piece of equipment called
swivel located at the top of the
kelly.
The swivel permits rotating the
drillstring while the fluid is
pumped through the drillstring.
A swivel
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22. drilling fluid in wellbore
In wellbore
The drilling fluid then flows down
the rotating drillstring and
jets out through nozzles in the drill bit
at the bottom of the hole.
The drilling fluid picks the rock cuttings
generated by the drill bit action on the formation.
The drilling fluid then
flows up the borehole through
the annular space
between the rotating drillstring and borehole wall.
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23. drilling fluid at surface
At surface
At the top of the well (and above the tank level),
the drilling fluid flows through the flow line
to a series of screens called the shale shaker.
The shale shaker is designed to
separate the cuttings from the drilling mud.
Other devices are also used to clean the drilling fluid
before it flows back into the drilling fluid pits.
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24. Process of mud circulation
The principal
components of the mud
circulation system are:
pits or tanks,
pumps,
flow line,
solids and contaminants
removal equipment,
treatment and mixing
equipment,
surface piping and valves,
the drillstring.
Rig circulation system
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25. The tanks
The tanks
(3 or 4 – settling tank, mixing tank(s), suction tank)
are made of steel sheet.
They contain a safe excess (neither to big nor to small)
of the total volume of the borehole.
In the case of loss of circulation,
this excess will provide the well with drilling fluid
while the corrective measures are taken.
The number of active tanks depends on
the current depth of the hole
(bypasses allow to isolate one or more tanks.)
The tanks will allow enough retaining time so that
much of the solids brought from the hole
can be removed from the fluid.
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27. reciprocating positive displacement
pumps vs. centrifugal pumps
The great majority of the pumps
used in drilling operations are
reciprocating positive displacement pumps (PDP).
Advantages of the reciprocating PDP when
compared to centrifugal pumps are:
ability to pump fluids with high abrasive solids contents
and with large solid particles,
easy to operate and maintain,
sturdy and reliable,
ability to operate
in a wide range of pressure and flow rate.
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28. positive displacement pumps
compartments
PDP are composed of two major parts, namely:
Power end:
receives power from engines and transform the rotating
movement into reciprocating movement.
The efficiency Em of the power end,
that is the efficiency with which rotating mechanical power is
transformed in reciprocating mechanical power
is of the order of 90%.
Fluid end:
converts the reciprocating power into pressure and flow rate.
The efficiency Ev of the fluid end
(also called volumetric efficiency),
that is, the efficiency that the reciprocating mechanical power is
transformed into hydraulic power, can be as high as 100%.
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29. Pump configurations
Rigs normally have two or three PDPs.
During drilling of shallow portions of the hole,
when the diameter is large,
the two PDPs are connected in parallel
to provide the highest flow rate necessary
to clean the borehole.
As the borehole deepens,
less flow rate and higher pressure are required.
In this case, normally only one PDP is used
while the other is in standby or in preventive
maintenance.
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30. Affecting parameters on flow rate
The great flexibility in the pressure and flow rate
is obtained with the possibility of
changing the diameters of the pair piston–liner.
The flow rate depends on the following
parameters:
stroke length LS (normally fixed),
liner diameter dL,
rod diameter dR (for duplex PDP only),
pump speed N (normally given in strokes/minute),
volumetric efficiency EV of the pump.
In addition, the pump factor Fp is defined as
the total volume displaced by the pump in one stroke.
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31. Types of
the positive displacement pumps
There are two types of PDP:
double-action duplex pump, and
single-action triplex pump.
Triplex PDPs, due to several advantages,
(less bulky, less pressure fluctuation,
cheaper to buy and to maintain, etc,)
has taking place of the duplex PDPs
in both onshore and offshore rigs.
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32. 1. Jorge H.B. Sampaio Jr. “Drilling Engineering
Fundamentals.” Master of Petroleum
Engineering. Curtin University of Technology,
2007. Chapter 2

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