CHAPTER-1

INTRODUCTION TO WELL PLANNING

Drilling or digging for oil has occurred in one way or another for hundreds

of years. The Chinese, for instance, invented a bamboo rig to obtain oil and gas

for lighting and cooking. In 1859, oil came spurting out of the ground from a well

69.5 feet deep in Titusville, Pennsylvania. Colonel Drake had just gone down in oil

prospecting history. But although this initiated industrial oil well drilling, a large

number of wells had been drilled long before to produce water, brine and even

naphtha for caulking boats, and for lighting and medicinal purposes.

By the name of a well (borehole) is meant a cylindrical mine opening made

too small forman’s access there to, the diameter of the opening being many

times less than its length. The beginning of the well is called its mouth, collar or

well-head, the cylindrical surface is termed the wall or hole shaft (bore), and its

floor the bottom hole. The distance from the mouth to the bottom hole along

the axis of the borehole shaft is the length of the well, while the projection of

its axis onto the vertical plane represents the depth of the well. The wells are

sunk as straight, slanted or horizontal boreholes. As regards their purpose,

boreholes drilled for geological exploration of the region, search for,

prospecting and exploitation of deposits are classified into key or stratigraphic,

extension or-outpost, structure-exploratory, reconnaissance, prospecting

production and special boreholes.

Structure-exploratory boreholes serve the purpose of a thorough

investigation into the structures encountered in drilling of key and extension

holes and of drawing up a program for exploratory-prospecting drilling into

these structures. The results of the structure-exploratory drilling and of

geophysical investigations are utilized in studying the mode of occurrence,

determining the age and physical properties of the rocks making up the column,

precisely marking the reference or key horizons, and in compiling structural

(subsurface) maps.

Producing wells are drilled into a completely prospected deposit developed

for exploitation. The category of producing wells includes not only the wells

through which oil or gas is recovered (producing wells proper), but also the wells

which help to effectively develop the defining more exactly the reservoir

behavior (drive) and the extent of possible recovery of oil from individual

sections of the pool, ascertaining and accurately delimiting the boundaries of

producing fields.

Injection wells serve the purpose of edge and inter-field boundary

injection of gas or air into the producing reservoir in order in the formation

pressure. Observation wells are put down to affect a regular control over

changes in the pressure, over the position of the water-oil, gas-water and gas-oil

contacts during the operation of the reservoir.

Drilling Methods in Oil Industry

Rocks can be broken up by applying mechanical, thermal, pyhsico-chemical,

electric-spark and other methods. Practical applications in industry have found,

however, only methods involving mechanical disintegration of the rock, the

others continuing so far to be at the stage of development.

In oil industry, mechanical drilling is affected by employing percussive

(cable-tool) drilling and rotary drilling methods. Cable-tool drilling has been

abandoned about 30 years ago, and no longer employed, with some minor

exceptions. However, this method is still used for coal and ore mining industries,

geological engineering, and in drilling of wells for water. Different drilling

techniques are used in oil industry. Early days, cable-tool drilling was the major

method. Recently, rotary drilling systems are widely used. For the last two

decades, downhole motor systems are preferred as directional and horizontal

drilling needs are increasing. Cable-tool drilling will be emphasized in the next

chapter, and the rest of the course will be focused on rotary drilling technique.

Auger Drilling

In order to start an oil well drilling operation, hydraulic hammering or

auger drilling techniques are used for the conductor casing installations. Auger

drilling can be a best solution for dump leaching where dumps are in thickness of

30-60 ft or a bit more, and being in the dump site for long period of time. This

kinds of dumps may be squeezed and show some difficulties to passage of leach

solutions. Portable auger drills can drill fast and adequate sizes of holes which

leach solutions can be poured or dumped in. Drill string components of an auger

drilling system are composed of bits, augers and universal joints and subs.

Augers are usually 5 to 20 ft long. Hexagonal, circular or hollow augers are

available. Rotation of an auger system is achieved by using a top drive system or

a bevel gear. Load on the bit is determined from cable feed, chain feed,

hydraulic feed or combination of these. Cuttings are removed mechanically.

Cable Tool Drilling

The first oil well in the United States was drilled with cable tools in 1859

to a depth of 65feet. This was the historic Drake well located near Titusville,

Pennsylvania; it is credited with having started the American petroleum industry.

The cable tool (also called churn or percussion) drilling method, however, did not

originate in this country, but is believed to have been employed first by the

early Chinese in the drilling of brine wells. In this method, drilling is

accomplished by the pounding action of a steel bit which is alternately raised by

a steel cable and allowed to fall, delivering sharp, successive blows to the

bottom of the hole. This principle is the same as that employed in drilling

through concrete with an air hammer, or in driving a nail through a board. The

original percussion drilling apparatus consisted of a spring pole anchored into the

ground at an angle, with the bit suspended from the free end by a rope. To

impart the necessary reciprocating action to the bit, the Chinese employed a

number of men who alternately jumped on and off the spring pole beam from a

ramp. Many early brine wells in the United States were drilled in the same

manner, except that the spring pole was equipped with stir ups where two or

three men stood and literally kicked the well down. As more and deeper wells

began to be drilled efforts were made to improve the drilling equipment. Steam

engines began to be used; walking beams replaced the spring pole; steecables

replaced manila ropes; and other improvements followed. Although the modern

cable tool rig is a far cry from the ancient Chinese model, the changes have been

in materials and equipment, for the basic operating principle is unchanged

problems previously unsolved except by rig floor trial and error. Further field

verification of the theory is needed; such experiments could possibly aid the

economic application of cable tools.

Rotary Drilling System

Making a hole for the recovery of underground oil and gas is a process

which requires two major constituents; i) man-power, and ii) hardware systems.

The man power includes a drilling engineering group and a rig operator group.

The first provides engineering support for optimum drilling operations, including

rig selection, design of mud program, casing and cement programs, hydraulic

program, drill bit program, drillstring program and well control program. After

drilling begins, the daily operations are handled by a rig operator group which

consists of a tool pusher and several drilling crews. The hardware systems which

make up a rotary drilling rig are :

i) power generation system,

ii) hoisting system,

iii) drilling fluid circulation system,

iv) rotary system,

v) well blowout control system, and

vi) drilling data acquisition system and monitoring system.

Basic Principles of Rotary Drilling

The rotary method uses tricone-type toothed bits or one-piece bits such

as diamond or PDC bits. While the bit is being rotated, a force is applied to it by

a weight. The advantage is that a fluid can be pumped continuously through the

bit, which is crushing the rock formation, and carry cuttings up out of the hole

to the surface with the rising fluid flow. The rotary drilling rig is the apparatus

required to fulfill the following three functions:

-Put weight on the bit

-Rotate the bit

-Circulate a fluid

It is the drill collars, screwed onto the bottom of the drillpipe assembly

just above the bit, that provide the necessary weight, and prevent buckling of

the drillpipes above them. Drill collars, along with drillpipe and bit all make up

the drillstring, which is rotated by the rotary table and the kelly. The drillstring

component parts are hollow down the middle so that the drilling fluid can be

circulated down to the bit. A fluid-tight rotary joint, the swivel, is located at

the top of the kelly and provides a connection between the mud pump discharge

line and the inside of the drillstring. A hoisting system is required to support

the weight of the drillstring, lower it into the hole and pull it out. This is the

function of the derrick, the hook and the drawworks.

The drilling rig is complete with facilities to treat the drilling fluid when

it gets back to the surface, a storage area for tubular goods, shelters and

offices on site. In addition, when a well is being drilled, it is regularly cased. It

is lined with steel pipe, or casing, which is lowered into the hole under its own

weight in smaller and smaller diameters as the hole gets deeper. The first

length of pipe is run in as soon as the bit has drilled the surface formation and is

then cemented in the hole. A casing housing is connected to the top of the

surface casing. All the following lengths of pipe are hung on the casing housing

and cemented at the base to the walls of the hole. After the first drilling phase

is cased, drilling will be resumed with a bit with a diameter smaller than the

inside diameter of the casing string that was run in and cemented. The deeper

the borehole gets and the more casings are set in the well, the smaller the

diameter of the bit must be. The casing housing also serves to hold the safety

equipment, such as blowout preventers.

Drilling Crew

Besides the drilling engineers, geologist and other specialized technical

personnel, there are other men working on a drilling operation those have various

duties. The personnel on an oil or gas well drilling rig consists of a group of

operators who have certain skills and functions which are uniform in the

business of drilling a well. These operators are artisans of a sort who ply their

trade as do carpenters, bricklayers, etc, not caring much for whom they work

for as they do for the opportunity to work on a rig.

A drilling rig operates 7 days a week, 24 hours a day, and a full staff must

be on the job at all times in order that the rhythmical teamwork-type operation

may be accomplished without delays. Drilling rigs are generally staffed for a

tour or shift, by a crew of minimum 5 men. These men consist of a “driller”, a

“derrickman”, a “catheadman”, and two “floormen” (rotary helpers).The driller is

in charge of his crew, and in charge of the rig’s operations during his tour.

Hereports to a foreman who is usually called a “toolpusher”. In his position as

boss of the rig andthe crew, the driller must be responsible for safe, economical

operations at all times. Therelationship between the driller and his crewmen is

such that the driller will often take hiscrew with him when he changes jobs.

Good judgement and alert attention to detail areprobably the two prime

requisites of a driller. Specifically, it is the driller’s function tooperate the

drawworks in the hoisting of the drilling string from the hole and in running it

back into the hole, as well as to maintain the proper characteristics of the

machinery whiledrilling with a bit on bottom. The derrickman works high in the

derrick or mast while making a trip. Stationed on thederrick platform known as

the monkey board, which is 90 ft above the derrick floor, it is hisfunction among

others to seize the upper end of the 90 ft stand of pipe as it comes out of

thehole and pull it over into the rack. He also tests the circulating fluid to

maintain its properties in accordance with the mud program. It is his

responsibility to assure the proper functioningof the mud pumps. The term

catheadman, sometimes referred as “motorman”, is applied to the third ranking

member of the drilling crew. He is usually more experienced in all phases of the

work than the rotary helpers. His job is to operate the manual catheads on the

drawwroks whenever they are used and to supervise service of the motors and

engines for uninterrupted operations. The two rotary helpers are the tong

operators during trip. When the bit is on bottom for drilling, there are

miscellaneous duties for the rotary helper to perform. Maintaining the rig’s

housekeeping is a large order in itself, straightening up the floor, picking up

numerous pieces of equipment, cleaning and painting the machinery, helping the

motorman with the engines, helping the derrickman with the mud treatment, etc.

The toolpusher is actually the manager of his branch of his company’s operation.

During the drilling of the well, he must be available at any time day or night for

consultation with the drillers. Toolpushers must have at least a smattering of

knowledge on labor laws, personnel relationships, of chemistry, hydraulics,

internal combustion engines, etc. He usually has authority to spend money to

keep his rig in operation, cooperating with his supervisor on any items of major

importance. Since he does not drill a foot of hole by himself, it could be said

that his prime function is to assist the drillers and their crews to drill the hole

safely, economically and promptly. The foreman makes his headquarters in an

office at the rig known as “doghouse”, where he must keep accurate records of

daily drilling, performance, purchases of materials, accident reports, and other

paperwork which must go daily to the main office for coordinating with the

other company accounting and records. The foreman’s responsibilities cover

every operation of the rig including clearing and stacking out the drill site,

moving in the rig, and rigging up and tearing it down when the job is finished.

Depending upon the size of the contracting organization, there may be an

assistant drilling superintendent as well as a drilling superintendent. It is the

function of these men primarily to aid the toolpusher in the conduct of their

work. These are the duties of the principal field personnel on a drilling rig.

Behind them in the administrative end of the business, an office force must be

maintained to solicit business, contact clients, estimate for bids, maintain an

equipment yard and repair shop and figure what the company has left after

taxes.

Rig Components

Rotary drilling rigs are used almost all drilling done today. The hole is drilled by

rotating a bit to which a downward force is applied. Generally, the bit is turned

by rotating the entire drillstring, using a rotary table at the surface, and the

downward force is applied to the bit by using sections of heavy thick-walled

pipes, called drill collars, in the drillstring above bit. The cuttings are lifted to

the surface by circulating a fluid down the drillstring, through the bit, and

up the annular space between the hole and the drillstring. The cuttings are

separated from the drilling fluid at the surface.

Rigs

The function of rotary drilling is to allow the drilling and completion of a hole at

the lowest cost possible. The process of making a hole is made by rotating a rock

cutting tool called a bit, upon which a downward force is applied. The generated

cuttings (rock fragments) at the hole bottom are transported by a circulating

drilling fluid down through the drillstring and up the annular space to the

surface.

Rotary drilling rigs are classified as onshore (land) or offshore (marine)

rigs. Their main design features are mobility, flexibility and maximum depth of

operation. Rig components, in general, are common to both onshore and offshore

rigs. The only major difference is the utilization of motion compensation

equipment and an extension pipe (drilling riser between rig floor and seabed

when drilling in a marine environment).

Modern land rigs are built in units and are skid-mounted so that they can

be transported from one drilling site to another. Once on location, the rig

components are easily assembled together to drill the well. The derrick is

designed such that it can be assembled and disassembled with ease. Its

functions are to carry loads that are suspended in the wellbore and to provide

space between rig floor working area and crown block such that certain length

of the drillstring can be made. A rig that can handle singles, doubles or triples is

one that allow length of 30 ft, 60 ft or 90 ft sections of drillstring to be made,

respectively. These sections are called stands. For moderate depth wells, carrier

mounted rigs are used. These portable masts are mounted on flat-bed vehicles

as self-contained single units.

Offshore drilling is performed from space above water provided by

structures which may be classified as i) mobile platforms and, ii) stationary or

fixed platforms. The selection of a particular rig carrier depends on the

operations to be performed and the water depth on location where such

operations are to be conducted. These operations may consist of exploratory

drilling, development drilling, production, storage or a combination of all.

Exploratory drilling, where hydrocarbons might or might not be available

for production, is done most economically by the utilization of mobile rig

carriers. These are defined as units which can be moved from one location to

another as the need arises. Mobile units may be grouped in three categories: 1)

self-elevating (jack-up), 2) column stabilized and, 3) dynamically positioned ship

units.Self-elevating or what are normally referred to as jack-up units are those

which, in their normal operating state, rest on the sea floor by means of legs

with the deck above the highest water level. In the transit stage, these units

float with the legs in the lifted position. Their use is generally recommended in

water depth ranging approximately from 60 feet to 300 feet of water. Column

stabilized units are supported by either caissons with or without footings or by

lower displacement type hulls by means of columns. These units are classified as

submersibles which operate while resting on the seabed or semi-submersibles

which operate when they are a float. Submersibles are generally used in water

depth up to 60 feet. Semi-submersibles and dynamically positioned ships are

used in moderately to extremely deep water depths. In development drilling

where hydrocarbons are known to exist in readily producing reservoirs, drilling

operations are conducted from stationary units which generally referred to as

permanently fixed platforms. These units are of adequate size that they may

contain drilling equipment, production equipment, storage, separation equipment,

living quarters or a combination of all. Based on their construction these units

are classified as tower type, template, tower/template, tender type, tension leg,

etc. They are designed to remain on location through their entire life span. Some

of these units have been erected in water depth of approximately 600 feet. In

the case of tension-leg platforms (TLP), operations in water depth in excess of

3000 ft have been demonstrated. While selecting a derrick or mast, the

drawworks capacity or safe load capacity from the hook load are usually

considered. As a rule of thumb, every 100 ft of borehole requires 10 HP at the

drawworks. Also, the wind load and compressive loads on the joints of the

derrick should also be considered. API has standards and guides for the

selection of proper derrick for a certain drilling operation.

Rig Power System

The hoisting and fluid circulating systems consume most rig power. Total

power requirements for most rigs are from 1000 to 3000 hp. Modern rigs are

powered by internal-combustion diesel engines and generally sub-classified as:

diesel electric type and the direct-drive type depending on the methods used to

transmit power to the various rig systems. Power system performance

characteristics generally are stated in terms of output horsepower, torque, and

fuel consumption for various engine speeds. As illustrated in Fig.1-1, the shaft

power developed by an engine is obtained from the product of the angular

velocity of the shaft, w, and the output torque T:

P = w T

The overall power efficiency determines the rate of fuel consumption, wf at a

given engine speed. The heating values H of various fuels for internal

combustion engines are shown in the following (Table1-1) The heat energy input

to the engine, Qi,, can be expressed by,

Qi = wf H

Since the overall power system efficiency, Et is defined as the energy output

per energy input, then;

Et = P / Qi

Table-1-1 Heating Value of Various Fuels

Fuel type Density, lbm/gal

Heating Value, Btu/lbm

Diesel 7.2 19000 Butane 4.7 21000 Methane - 24000 Gasoline 6.6 20000

Example-1 . A diesel engine gives an output: torque of 1,740 ft-Ibf at an

engine speed of 1.200 rpm. If the fuel consumption rate was 31.5 gal/hr, what is

the output power and overall efficiency of the engine?

Solution.

The angular velocity, w, is given by

W =2 ππππ (l,200) == 7,539.8 rad/min. The power output can be computed,

P = w.T

P =[7,539.8(1740) ft-lbf/min ] / [33,000ft-lbf/min/hp ]

P = 397.5 hp

Since the fuel type is diesel, the density ρ is 7.2 Ibm/gal and the heating value

H is 19,000 Btu/lbm (Table 1-1). Thus, the fuel consumption rate wf is,

wf =31.5 gal/hr (7.21bm/gal) ( 1 hour / 60 min.)

wf =3.781bm/min.

The total heat energy consumed by the engine is equal to;

Qi = wf H

Qi = 3.78 lbm/min (19000 Btu/lbm) (779 ft-lbf/Btu) / 33000 ft-lbf/min/hp

Qi = 1695.4 hp

Thus the overall efficiency of the engine at 1200 rpm is equal to;

Et = P / Qi

Et = 397.5 / 1695.4 = 0.234

Et = 23.4 %

Hoisting System

The function of the hoisting system is to provide a means of lowering or

raising drill strings, casing strings, and other sub-surface equipment into or out

of the hole. The principal components of the hoisting system are

-the derrick and substructure,

-the block and tackle, and

-the draw-works.

Two routine drilling operations performed with the hoisting system are called:

-making a connection and

-making a trip.

Making a connection refers to the periodic process of adding a new joint of drill

pipe as the hole deepens. Making a trip refers to the process of removing the

drill string from the hole to change a portion of the down hole assembly and

then lowering the drill string back to the hole bottom. A trip is made usually to

change a dull bit.

Derrick or Portable Mast:

The function of the derrick is to provide the vertical height required

raising sections of pipe from or lowering them into the hole. The greater the

height, the longer the section of pipe that can be handled and, thus, the faster

a long string of pipe can be inserted in or removed from the hole. The most

commonly used drill pipe is between 27 and 30 ft long. Derricks that can

handle sections called stands, which are composed of two, three, or four joints

of drill pipe, are said to be capable of pulling doubles, thribbles, fourbles,

respectively.

Block and Tackle:

The block and tackle is comprised of (1) the crown block, (2) the

travelling block, and (3) the drilling line. The arrangement and nomenclature of

the block and tackle used on rotary rigs are shown in Fig. 1.16a. The principal

function of the block and tackle is to provide a mechanical advantage, which

permits easier handling of large loads. The mechanical advantage M of a block

and tackle is simply the load supported by the traveling block, W, divided by the

load imposed on the draw-works, Ff.

M = W / Ff

The load imposed on the draw-works is the tension in the fast line. The

ideal mechanical advantage, which assumes no friction in the block and tackle,

can be determined from a force analysis of the traveling block. Consider the

free body diagram of the traveling block as shown in Figure. If there is no

friction in the pulleys, the tension in the drilling line is constant throughout.

Thus, a force balance in the vertical direction yields;

n Ff = W

where, n is the number of lines strung through the traveling block. Solving this

relationship for the tension in the fast line and substituting the resulting

expression in Equation yields;

Mi = W / (W / n) = n

which, indicates that the ideal mechanical advantage is equal to the number of

lines strung between the crown block and traveling block. Eight lines are shown

between the crown block and traveling block. The use of 6, 8, 10, or 12 lines

is common, depending on the loading condition.

The input power Pi of the block and tackle is equal to the draw-works load Ff

times the velocity of the fast line, Vf:

Pi = Ff Vf

The output power, or hook power, Ph is equal to the traveling block load W

times the velocity of the traveling block, Vb.

Ph = W Vb

For a frictionless block and tackle, W = nFf. Since the movement of the fast

line by a unit distance tends to shorten each of the lines strung between the

crown block and traveling block by only 1/n times the unit distance. Then Vb=Vf /

n. Thus, a frictionless system implies that the ratio of output power to input

power is unity:

E = Ph / Pi = [(nFf) (Vf / n)] / (Ff Vf) = 1

Of course, in an actual system, there is always a power loss due to

friction. Approximate values of block and tackle efficiency for roller-bearing

sheaves are shown in the following table. Knowledge of the block and tackle

efficiency permits calculation of the actual tension in the fast line for a given

load. Since the power efficiency is given by;

E = Ph / Pi = (W Vb) / (Ff Vf) = (WVf / n) / (Ff Vf) = W / Ff n

Table 1-2 Efficiency of the Lines

Number of lines (n) Efficiency (E)

6 0.874 8 0.841 10 0.810 12 0.770 14 0.740

Then the tension in the fast line is;

Ff = W / (En)

However, a safety factor should be used to allow for line wear and shock

loading conditions. The line arrangement used on the block and tackle uses the

load imposed on the derrick to be greater than the hook load. As sown in figure,

the load Fd applies to the derrick is the sum of the hook load W, the tension in

the dead line, Fs and the tension in the fast line, Ff.

Fd = W + Ff + Fs

If the load, W, is being hoisted by pulling on the fast line, the friction in

the sheaves is resisting the motion the fast line and the tension in the drilling

line increases from W / n at the first sheave (deadline) to W / En at the last

sheave (fast line). Substituting these values for Ff and Fs in above equation;

Fd = W + (W / En) + (W / n) = [(1+E+En) / En] W

The total derrick load is not distributed equally over four derrick legs.

Since the draw-works is located one side of the derrick floor, the tension in the

fast line is distributed over only two of the four derrick legs. Also, the dead

line affects only the leg to which it is attached. For the arrangement given in

figure, derrick legs C and D should share the load imposed by the tension in the

fast line and leg A would assume the full load imposed by the tension in the

dead line. The load distribution for each leg is given in the following table.

Table 1-3 Load Distribution for Each Leg

Load Total Load Leg A Leg B Leg C Leg D

Hook Load W W / 4 W / 4 W / 4 W / 4

Fast line W / En - - W / 2 En W / 2 En

Dead line W / n W / n - - - Total = W(n+4)/(4n) W / 4 W(En+2)/(4En) W(En+2)/(4En)

-Schematic Diagram of the Load Distribution-

Note that for E>0.5, the load on leg A is greater than the load on the

other three legs. Since if any leg fails, the entire derrick also fails, it is

convenient to define a maximum equivalent derrick load, Fde, which is equal to

four times the maximum leg load.

Fde = [(n + 4) / n] W

A parameter sometimes used to evaluate various drilling line

arrangements is the derrick efficiency factor, defined as the ratio of the

actual derrick load to the maximum equivalent load. For a maximum equivalent

load given by above equation the derrick efficiency factor is

Ed = Fd / Fde = {[(1+E+En) / En] W} / {[(n + 4) / n] W}

=[E (n+1) + 1] / [E (n+4)]

For the block and tackle efficiency values given in previous table, the

derrick efficiency increases with the number of lines strung between the crown

block and traveling block.

The drilling line is subject to rather severe service during normal tripping

operations. Failure of the drilling line can result in

-injury to the drilling personnel,

-damage to the rig, and

-loss of the drillstring in the hole.

Thus, it is important to keep drilling line tension well below the nominal breaking

strength and to keep the drilling line in good condition.

Drilling line does not tend to wear uniformly over its length. The most

severe wear occurs at the pickup points in the sheaves and at the lap points on

the drum of the draw-works. The pickup points are the points in the drilling line

that are on the top of the crown block sheaves or the bottom of the traveling

block sheaves when the weight of the drill string is lifted from its supports in

the rotary table during tripping operations. The rapid acceleration of the heavy

drill string causes the most severe stress at these points.

Drilling line is maintained in good condition by following a scheduled slip-

and-cut program. Slipping the drilling line involves loosening the dead line

anchor and placing a few feet of new line in service from the storage reel.

Cutting the drilling line involves removing the line from the drum of the draw-

works and cutting off a section of line from the end.

API has adopted a slip-and-cut program for drilling lines. The parameter

adopted to evaluate the amount of line service is the ton-mile. A drilling line is

said to have rendered one ton-mile of service when the traveling block has

moved 1 U.S. ton a distance of 1 mile. Note that for simplicity this parameter

is independent of the number of lines strung. Ton-mile records must be

maintained in order to employ a satisfactory slip-and-cut program.

Example-2. A rig must hoist a load of 300000 lbf. The drawworks can provide

an input power the block and tackle system as high as 500 hp. Eight lines are

strung between the crown block and traveling block. Calculate:

1-the static tension in the fast line when upward motion is impending,

2-the maximum hook horsepower available,

3-the maximum hoisting speed,

4-the actual derrick load,

5-the maximum equivalent derrick load, and

6-the derrick efficiency factor.

Solution.

1) The power efficiency for n = 8 is given as 0.8 in Table. The tension in the

fast line is;

Ff = W /En = 300000 / 0.841 (8) = 44590 lbf

2) The maximum hook horsepower available is;

Ph = E Pi = 0.841 (500) = 420.5 hp.

3) The maximum hoisting speed is given by;

Vb = Ph / W = 420.5 hp (33000 ft-lbf/min/hp) / 300000 lbf

Vb = 46.3 ft/min. On the other hand, to pull 90 ft stand would require;

T = 90 ft / 46.3 ft/min. = 1.9 min.

4) The actual derrick load is;

Fd = [(1+E+En) / En] W = [(1+0.841+0.841 (8)] / [0.841 (8)] . 300000 =

382090 lbf

5) The maximum equivalent load is;

Fde = [(n + 4) / n] W = [(8+4) / 8] . 300000 = 450000 lbf

6) The derrick efficiency factor;

Ed = Fd / Fde = 382090 / 450000 = 0.849 or 84.9 %

Drawworks:

The drawworks provide the hoisting and braking power required to raise

or lower the heavy strings of pipe. The principal parts of the drawworks are:

-the drum,

-the brakes,

-the transmission, and

-the catheads.

The drum transmits the torque required for hoisting or braking. It also

stores the drilling line required to move the traveling block the length of the

derrick. The brakes must have the capacity to stop and sustain the great

weights imposed when lowering a string of pipe into the hole. Auxiliary brakes

are used to help dissipate the large amount of heat generated during braking.

Two types of auxiliary brakes commonly used are (1) the hydrodynamic type and

(2) the electromagnetic type. The draw-works transmission provides a means for

easily changing the direction and speed of the traveling block. Power also must

be transmitted to catheads attached to both ends of the draw-works.

Circulating System:

A major function of the fluid-circulating system is to remove the rock

cuttings from the hole as drilling progresses. The drilling fluid is most commonly

a suspension of clay and other materials in water and is called drilling mud. The

drilling mud travels;

-from the steel tanks to the mud pump,

-from the pump through the high-pressure surface connections to the drill

string,

-through the drill string to the bit,

-through the nozzles of the bit and up the annular space between the drill

string and hole to the surface, and

-through the contaminant-removal equipment back to the suction tank.

The principal components of the rig circulating system include;

-mud pumps,

-mud pits,

-mud-mixing equipment, and

-contaminant-removal equipment.

With the exception of several experimental types, mud pumps always have

used reciprocating positive-displacement pistons. Both two-cylinder (duplex)

and three-cylinder (triplex) pumps are common. The duplex pumps generally are

double-acting pumps that pump on both forward and backward piston strokes.

The triplex pumps generally are single-acting pumps that pump only on forward

piston strokes. Triplex pumps are lighter and more compact than duplex pumps,

their output pressure pulsations are not as great, and they are cheaper to

operate. For these reasons, the majority of new pumps being placed into

operation are of the triplex design.

The advantages of the reciprocating positive-displacement pump are the;

-ability to move high-solids-content fluids laden with abrasives,

-ability to pump large particles,

-ease of operation and maintenance,

-reliability, and

-ability to operate over a wide range of pressures and flow rates by changing

the diameters of the pump liners (compression cylinders) and pistons.

The overall efficiency of a mud-circulating pump is the product of the

mechanical efficiency and the volumetric efficiency. Mechanical efficiency

usually is assumed to be 90% and is related to the efficiency of the prime

mover itself and the linkage to the pump drive shaft. Volumetric efficiency of a

pump whose suction is adequately charged can be as high as 100%. Most

manufacturers tables rate pumps using a mechanical efficiency, Em, of 90% and

a volumetric efficiency, Ev, of 100%. Generally, two circulating pumps are

installed on the rig. For the large hole sizes used on the shallow portion of most

wells, both pumps can be operated in parallel to deliver the large flow rates

required. On the deeper portions of the well, only one pump is needed, and the

second pump serves as a stand-by for use when pump maintenance is required.

The theoretical displacement from a double-acting pump is a function of

the piston rod diameter dr, the liner diameter dl and the stroke length Ls. On

the forward stroke of each piston, the volume displaced is given by;

ππππ/4 dl2 Ls

Similarly, on the backward stroke of each piston, the lume displaced is given by;

ππππ/4 (dl2 - dr

2) Ls

Thus, the total volume displaced per complete pump cycle by a pump having two

cylinders is given by;

Fp = ππππ/4 Ls (2dl2 - dr

2) Ev (duplex)

where Ev, is the volumetric efficiency of the pump. The pump displacement per

cycle, Fp, is commonly called the pump factor.

For the single-acting (triplex) pump, the volume displaced by each piston

during one complete pump cycle is given by;

ππππ/4 dl2 Ls

Thus, the pump factor for a single-acting pump having three cylinders becomes;

Fp = 3ππππ/4 (2) Ls Ev dl2 (triplex)

The flow rate q of the pump is obtained by multiplying the pump factor by ,N,

the number of cycles per unit time. In common field usage, the terms cycle and

stroke often are used interchangeably to refer to one complete pump revolution.

Pumps are rated for:

-hydraulic power,

-maximum pressure and maximum flow rate.

If the inlet pressure of the pump is essentially atmospheric pressure, the

increase in fluid pressure moving through the pump is approximately equal to the

discharge pressure. The hydraulic power output of the pump is equal to the

discharge pressure times the flow rate. In field units of hp, psi, and gal/min,

the hydraulic power developed by the pump is given by;

PH = ∆∆∆∆p q / 1714

For a given hydraulic power level, the maximum discharge pressure and

flow rate can be varied by changing the stroke rate and liner size. A smaller

liner will allow the operator to obtain a higher pressure, but at a lower rate. Due

to equipment maintenance problems, pressures above about 3,500 psig seldom

are used.

Example-3 Compute the pump factor in units of barrels per stroke for a duplex

pump having 6.5 inch liners, 2.5 inch rods, 18 inch strokes and a volumetric

efficiency of 90 %.

Solution:

The pump factor for a duplex pump can be determined

Fp = ππππ/4 (2) Ls Ev (2dl2 - dr

2) = ππππ/2 (18) (0.9) [2 (6.5)2 – (2.5)2] = 1991.2

inch3/stroke

There are 231 inch3 in a U.S. gallon and 42 US gallons in a US barrel.

1991.2 inch3 / stroke x gal / 231 inch3 x bbl / 43 gal = 0.2052 bbl/stroke

Rotary System

The rotary system includes all of the equipment used to achieve bit rotation.

The main parts of the rotary system are the: (1) swivel (2) kelly (3) rotary drive

(4) rotary table (5) drill pipe and (6) drill collars.

The swivel supports the weight of the drill string and permits rotation.

The bail of the swivel is attached to the hook of the traveling block, and the

gooseneck of the swivel provides a downward-pointing connection for the rotary

hose. Swivels are rated according to their load capacities. .

The kelly is the first section of pipe below the swivel. The outside cross

section of the kelly is square or hexagonal to permit it to be gripped easily for

turning. Torque is transmitted to the kelly through kelly bushings, which fit

inside the master bushing of the rotary table. The kelly must be kept as

straight as possible. A kelly saver sub is used between the kelly and the first

joint of drill pipe.

The openings in the rotary table that accepts the kelly bushings must be

large enough for passage of the largest bit to be run in the hole. The major

portion of the drill string is composed of drill pipe. API has developed

specifications for drill pipe. Drill pipe is specified by its outer diameter, weight

per foot, steel grade and range length. Drill pipe is furnished in the following

API length ranges.

Table 1-4 API Drill Pipe Ranges

Range Length (ft)

1 18 to 22 2 27 to 30 3 38 to 45

Range-2 drill pipe is used most commonly. Since each joint of pipe has a

unique length, the length of each joint must be measured carefully and recorded

to allow a determination of total well depth during drilling operations. The drill

pipe joints are fastened together in the drill string by means of tool joints. The

female portion of the tool joint is called the box and the male portion is called

the pin. The portion of the drill pipe to which the tool joint is attached has

thicker walls than the rest of the drill pipe to provide for a stronger joint. This

thicker portion of the pipe is called the upset.

The lower section of the rotary drill string is composed of drill collars.

The drill collars are thick-walled heavy steel tubulars used to apply weight to

the bit. The smaller clearance between the borehole and the drill collars helps

to keep the hole straight. Stabiliser subs often are used in the drill collar string

to assist in keeping the drill collars centralized.

In many drilling operations, knowledge of the volume contained in or

displaced by the drill string is required. The term capacity often is used to

refer to the cross-sectional area of the pipe or annulus expressed in units of

contained volume per unit length. In terms of pipe diameter, d, the capacity of

pipe, Ap, is given by;

Ap = ππππ/4 d2

Similarly, the capacity of an annulus, Aa, in terms of the inner and outer

diameter, is

Aa = ππππ/4 (d22 – d1

2 )

The term displacement often is used to refer to the cross-sectional area of

steel in the pipe expressed in units of volume per unit length. The displacement,

As, of a section of pipe is:

As = ππππ/4 (d12 – d2 )

Example-4 A drill string is composed of 7,000 ft of 5-in., 19.5-lbm/ft drill pipe

and 500 ft of 8-in. OD by 2.75-in. ID drill collars when drilling a 9.875-in.

borehole. Assuming that the borehole remains in gauge, compute the number of

pump cycles required to circulate mud from the surface to the bit and from the

bottom of the hole to the surface if the pump factor is 0.1781 bbl/cycle.

Solution

For field units of feet and barrels, the above equation becomes:

Ap = (ππππ/4 d2) in.2 (gal / 231 in.3) (bbl / 42 gal) (12 in. / ft) = (d2 /

1029.4) bbl/ft

The inner diameter of 5-in., 19.5 lbm/ft drill pipe is 4.276 in.; thus, the capacity

of the drill pipe is;

(4.2762 / 1029.4) = 0.01776 bbl/ft

and the capacity of the drill collars is;

(2.752 / 1029.4) = 0.00735 bbl/ft

The number of pump cycles required to circulate new mud to the bit is given by;

[0.01776 (7000) + 0.00735 (500) bbl / 0.1781 bbl/cycle = 719 cycles

Similarly, the annular capacity outside the drillpipe is given by;

(9.8752 - 52) / 1029.4 = 0.0704 bbl/ft

and the annular capacity outside the drill collars is;

(9.8752 - 82) / 1029.4 = 0.0326 bbl/ft

The pump cycles required to circulate mud from the bottom of the hole to the

surface is given by;

[0.0704(7,000) + 0.0326 (500)] bbl / 0.1781 bbl/cycle = 2858 cycles.

The Well Control System:

The well control system prevents the uncontrolled flow of formation

fluids from the well-bore. When the bit penetrates a permeable formation that

has a fluid pressure in excess of the hydrostatic pressure exerted by the

drilling fluid, formation fluids will begin displacing the drilling fluid from the

well. The flow of formation fluids into the well in the presence of drilling fluid is

called a kick. The well control system permits :

-detecting the kick,

-closing the well at the surface,

-circulating the well under pressure to remove the formation fluids and

increase the mud density,

-moving the drillstring under pressure, and

-diverting flow away from rig personnel and equipment.

Failure of the well control system results in an uncontrolled flow of

formation fluids and is called a blow-out. This is perhaps the worst disaster

that can occur during drilling operations. Blow-outs can cause loss of life, drilling

equipment, the well, much of the oil and gas reserves in the underground

reservoir, and damage to the environment near the well. Thus, the well control

system is one of the more important systems on the rig. Annular preventers,

sometimes called bag-type preventers, stop flow from the well using a ring of

synthetic rubber that contracts in the fluid passage. The rubber packing

conforms to the shape of the pipe in the hole. Most annular preventers also will

close an open hole it necessary. Annular preventers are available for working

pressures of 2,000, 5,000, and 10,000 psig. Both the ram and annular BOP’s are

closed hydraulically. In addition, the ram preventers have a screw-type locking

device that can be used to close the preventer if the hydraulic system fails.

Well-Monitoring System:

Safety and efficiency considerations require constant monitoring of the

well to detect drilling problems quickly. Devices record or display parameters

such as (1) depth, (2) penetration rate, (3) hook load, (4) rotary speed, (5)

rotary torque, (6) pump rate, (7) pump pressure, (8) mud density, (9) mud

temperature. (10) mud salinity, (11) gas content of mud, (12) hazardous gas

content of air, (13) pit level, and (14) mud flow rate.

In addition to assisting the driller in detecting drilling problems, good

historical records of various aspects of the drilling operation also can aid

geological, engineering, and supervisory personnel. In some cases, a centralized

well-monitoring system housed in a trailer is used This unit provides detailed

information about the formation being drilled and fluids being circulated to the

surface in the mud as well as centralizing the record keeping of drilling

parameters. The mud logger carefully inspects rock cuttings taken from the

shale shaker at regular intervals and maintains a log describing their

appearance. Additional cuttings are labeled according to their depth and are

saved for further study by the paleontologist. The identification of the

microfossils present in the cuttings assists the geologist in correlating the

formations being drilled. The mud logger using a gas chromatograph analyzes gas

samples removed from the mud. This type of analysis often can detect the

presence of a hydrocarbon reservoir. Recently, there have been significant

advances in sub-surface well-monitoring and data-telemetry systems. These

systems are especially useful in monitoring hole direction in non-vertical wells.

One of the most promising techniques for data telemetry from sub-surface

instrumentation in the drill string to the surface involves the use of a mud

pulser that sends information to the surface by means of coded pressure pulses

in the drilling fluid contained in the drill string.

Ton-miles of a drilling line:

The total service life of a drilling line may be evaluated by taking into

account the work done by the line during drilling, fishing, coring, running casing

and by evaluating the stresses imposed by acceleration and deceleration

loadings, vibration stresses and bending stresses when the line is in contact with

the drum and sheave surfaces. Typical round trip operations include running and

pulling drill pipe during drilling.

Work done in round trip operations = work done by travelling assembly +

work done by drilling line + work done by drill collars. So work done in making a

round trip (Tr);

Tr = [D (Ls + D) We / 10,560,000] + [D (M + C / 2) / 2,640,000] ton-miles

where; M = mass of traveling assembly (lb); Ls = length of each stand (ft) ; D =

hole depth (ft); C = effective weight of drill collar assembly in mud – effective

weight of the same length of drill pipe in mud (LWdc – LWdp) x BF; We =

effective weight per foot of drill pipe in mud.

Drilling Operations:

The ton-mile service performed by a drilling line during drilling operations

is expressed in terms of work performed in making round trips, since there is

always a direct relationship as shown on the following cycle of drilling

operations:

-drill ahead of a length of kelly

-pull up length of kelly

-ream ahead a length of kelly

-pull up a length of kelly

-put kelly in rat hole

-pick up a single (or double)

-lower drill string in hole

-pick up kelly and drill ahead

Operations 1 and 2 give 1 round trip of work done (WD), operations 3 and 4 give

1 round trip of work done, operation 7 gives ½ round trip of work done; and

operations 5,6 and 8 gives approximately ½ round trip of work done. Therefore:

Total work done = 3 round trips = 3 Tr

However, in drilling a length of section from depth d1 to depth d2, the work

done, Td, is:

Td = 3 Tr = 3 (Tr at d2 – Tr at d1) = 3 (T2 –T1)

In coring operations:

Total WD in coring = Tc = 2 round trips to bottom

Tc = 2 (T2 –T1)

In casing operations:

Total work done in setting casing = Ts = ½ [4MD+ Wcs (Ls + D)D]

Ts = ½{[D (Ls +D) x Wcs] / 10,560,000} + (MD / 2,640,000) ton-miles

Example-5 The following data refer to a 1 ½ inch block line with 10 lines of

extra improved plough steel wire rope strung to the travelling block.

Hole depth: 10000 ft

Drill pipe: 5 inch OD / 4.276 inch ID, 19.5 lb/ft

Drill collars: 500 ft, 8 x 2 13/16 inch, 150 lb/ft

Mud weight : 75 lb/ft3

Line and sheave efficiency coefficient: 0.9615

Calculate:

a-weight of drill string in air and in mud

b-hook load, assume weight of traveling block and hook to be 23500 lb

c-dead line and fast line loads, assume an efficiency factor of 0.81

d-dynamic crown load

e-wireline design during drilling if breaking strength of wire is 228000 lb

Solution:

a-weight of string in air = weight of drillpipe + weight of drill collars

weight of string in air = [(10000 – 500) x 19.5] + (500 x 150) = 260250 lb

weight of string in mud = weight of string in air x buoyancy factor =

260250 x (1-75 / 489.5) weight of string in mud = 220432 lb

b-hook load = weight of string in mud + weight of travelling block

hook load = 2204312 + 23500 = 243932 lb

c- deadline load = (HL / N) x K10 / EF) = ( 243932 / 10) x [(0.961510) / 0.81]

deadline load = 20336 lb

fastline load = [HL / (N x EF)] = [342932 / (10 x 0.81)] = 30115 lb

d- dynamic crown load = DL + FL + HL

dynamic crown load = 20336 + 30115 + 243932 = 294383 lb

e-design factor = (breaking strength / fast line load)

desigh factor = 228000 / 30115 = 7.6

Example 1-6 Using the data of the above example, determine:

a-round trip ton-miles at 10000 ft

b-casing ton-miles if one joint of casing = 40 ft

c-ton-miles when coring from 10000 ft to 10180 ft

d-ton,miles when drilling from 10000 ft to 10180 ft

Solution:

a-Tr = [D (Ls + D) We / 10,560,000] + [D (M + C / 2) / 2,640,000]

M= 23500 lb; D = 10000 ft; Ls = 93 ft; We = 19.5xBF = 16.52 lb/ft; C = 55267 lb

Tr = [10000 (93 + 10000) 16.52 / 10,560,000] + [10000 (23500 + 55267/

2) / 2,640,000]

Tr = 157.9 + 193.7 = 351.6 ton-miles

b- Ts = ½{[D (Ls +D) x Wcs] / 10,560,000} + (MD / 2,640,000) ton-miles

Wcs = 29x0.847 = 24.56 lb/ft and Ls = 40 ft

Ts = ½{[10000 (40 +10000) x 24.56] / 10,560,000} + (23500x10000 /

2,640,000)

Ts = ½ (233.5 + 89) = 161.3 ton-miles

c-T2 = round trip time at 10180 ft and T1 = round trip time at 10000 ft

T2 = [10180 (93 + 10180) 16.52 / 10,560,000] + [10180 (23500 + 55267

/ 2) / 2,640,000]

T2 = 163.6 + 197.2 = 360.8 ton-miles

T1 = 351.6 ton-miles (part-a)

Therefore: Tc = 2 (360.8 –351.6) = 18.4 ton,miles

d- Td = 3 (T2 – T1) = 3 (360.8 – 351.6) = 27.6 ton-miles

Example 1-7) A 1.25-in. drilling line has a nominal breaking strength of 138,800

lbf. A hook load of 500,000 lbf is anticipated on a casing job and a safety factor

based on loading conditions on static loading conditions of 2.0 is required.

Determine the minimum number of lines between the crown block and traveling

block that can be used?

Solution:

Safety factor = Ffmax / Ffact

2 = 138,800 / Ffact

Ffact = 69,400 lbf

W / E.n = 69400

E.n = 500,000 / 69,400 = 7.205

So E.vn> 7.205

Use Trial and Error procedure:

For n = 6 ; 6 x 0.874 = 5.244

For n = 8 ; 8 x 0.841 = 6.728

For n = 10 ; 10 x 0.81 = 8.100

Since 8.10 > 7.205

Minimum number of lines is = 10