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Drilling Engineering 1 Course (2nd Ed.)

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1. Power System

2. Hoisting System:A. Introduction

B. The Block & Tacklea. Mechanical advantage and Efficiency

1. Hoisting System:A. The Block & Tackle

a. Hook Power

B. Load Applied to the Derrick

2. Drilling Fluid Circulation SystemA. Mud Pumps

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

Spring14 H. AlamiNia Drilling Engineering 1 Course (2nd Ed.) 5

relationship between the drawworks power and the hook powerSince 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.


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.


The Block & Tackle

Using E = 0.841 (average efficiency for n = 8) we have:


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:


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 legsThe dead line, however must be

anchored close to one of the remaining two legsThe 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


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.


The equivalent derrick load andThe derrick efficiency factorIf 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:


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.


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


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.


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.


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.


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 swivelSpring14 H. AlamiNia Drilling Engineering 1 Course (2nd Ed.) 21

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.


drilling fluid at surface

At surfaceAt 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.


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 systemSpring14 H. AlamiNia Drilling Engineering 1 Course (2nd Ed.) 24

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.


reciprocating positive displacement pumps vs. centrifugal pumpsThe 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.


positive displacement pumps compartmentsPDP 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%.


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.


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.


Types of the positive displacement pumpsThere 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.


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

1. Drilling Fluid Circulation SystemA. Mud Pumps (Duplex PDP & Triplex PDP)

B. Solids Control Equipmenta. Mud Cleaners

C. Treatment and Mixing Equipment

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equivalent derrick load

actual derrick load

derrick load solution

alaminia drilling engineering

maximum hook load

excessive load

derrick opposite

derrick floor