‫‪Drilling and Production‬‬

‫‪Prepared by‬‬
‫مريم خالد السعيد نافع ‪2020-280‬‬
‫منال محمد فتحي وهبة ‪2020-287‬‬
‫اسماء محمد صابر‪2020-60‬‬
‫ساره السيد عبدالغفار ‪2020-138‬‬
‫اميره محمد عزت ‪2020-80‬‬
‫‪Prepared to‬‬
‫‪Dr.Reham Atef‬‬
‫‪Date‬‬
‫‪19-12-2023‬‬
Figure 1:Cable-tool drilling (Source: “Le pitrole: prospection et production ”, Esso Standard SAF, Training
Department)................................................................................................................................................6
Figure 2:Cable-tool drilling (Source: “Le pitrole: prospection et production ”, Esso Standard SAF,
Training Department)..................................................................................................................................7
Figure 3 : Rotary drilling rig (Source: “Lepitrole: prospection et production”, Esso Standard SAF,
Training Department)..................................................................................................................................8
Figure 4 :simplest cross section of a borehole............................................................................................9
Figure 5 The driller has control console (source :diller console ,martin decker):......................................10
Figure 6:Checking the weight on the bit....................................................................................................11
Figure 7:Adding drillpipe (Source: A primer of oil well drilling, Petex)......................................................12
Figure 8:Round trip. a. Latching the elevator; b. Pulling out a stand (thribble); c. Stacking the stand on
the setback (Source: A primer of oil well drilling, Petex)...........................................................................13
Figure 9:Drilling mast with stacked drill string (Source: Reynolds Aluminum Drill Pipe)...........................13
Figure 10:Three-cone bit terminology (Source: Hughes Tools)..................................................................15
Figure 11:Design of rock bit cones (Source: Hughes Tools).......................................................................16
Figure 12:Ball and roller bearings (Source: Hughes Tools).........................................................................17
Figure 13:Bearing lubrication system (Source: Hughes Tools)...................................................................17
Figure 14:Examples of carbide insert shapes (Source: Hughes Tools).......................................................18
Figure 15:Slanted nozzle (Source: Reed Tool Co.)......................................................................................19
Figure 16:Elongated nozzle (Source: Reed Tool Co.).................................................................................19
Figure 17:Cutters for one-piece bits(Source: Die Boart Stratabit).............................................................20
Figure 18:Natural diamond bit terminology (Source: Hughes Tools).........................................................21
Figure 19:Examples of PX bits....................................................................................................................23
Figure 20:TSP bits (Source: Eastman Christensen).....................................................................................23
Figure 21:Oil and gas production facilities.................................................................................................25
Introduction:
In 1859, oil came spurting out of the ground for the first time from a well 69.5 feet deep
in Titusville, Pennsylvania. Colonel Drake had just gone down in oil prospecting history.
But although this event 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. All boreholes in the olden days, including Drake’s
were drilled using the cable system (Fig.1). A massive bit with an edge similar to a
sculptor’s chisel was attached to the end of a heavy rod (drill collar), which in turn hung
from a walking beam. It was dropped free fall onto the rock which it pounded into slivers.
The walking beam was actuated by man or animal power long ago, then equipped with a
steam engine in the 19th century. But whatever the means of driving the system, the
bottom of the hole still had to be cleared of cuttings periodically. The borehole was filled
with water and the mud made from the water mixed with broken bits of rock was bailed
out with a cylindrical tool. The tool had a valv like end that was run in open and pulled
out closed by means of the drawworks. The deepest well drilled using this method
reached 2250 m in 1918. The cable system is still sometimes used today for shallow
water wells. It was at the beginning of the 20th century that Antony Lucas showed the
whole world how effective rotary drilling was with the discovery of Spindeltop field
(Texas). He combined the use of a rotating bit and continuous mud injection. Since then,
rotary drilling has been used worldwide and upgraded by technical developments.
THE PRINCIPLE 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.

Figure 1:Cable-tool drilling (Source: “Le pitrole: prospection et production ”, Esso Standard SAF, Training Department).
•The rotary drilling rig is the apparatus required to fulfill the following three functions

(Figs. 2 and 3):

 put weight on the bit,

 rotate the bit,
 circulate a fluid.

Figure 2:Cable-tool drilling (Source: “Le pitrole: prospection et production ”, Esso Standard
SAF, Training Department).
 F
ig
ur
e
3
:

Rotary drilling rig (Source: “Lepitrole: prospection et production”, Esso Standard SAF, Training
Department).
It is the drill collars, screwed onto the bottom of the drill pipe assembly just above the bit, that
provide the necessary weight. Drill collars, along with
drill pipe and bit all make up the drill string, which is
rotated by the rotary table and the Kelly .

The drill string 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 drill string. A hoisting system is
required to support the weight of the drill string, lower
it into the hole and pull it out. This is the function of
the derrick, the hook and the draw works . 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 the site. In
addition, when a well is being drilled it is regularly Figure 4 :simplest cross section of a borehole

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 their base to the walls of the hole (Fig.4). fter 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.
1.2 THE MAJOR OPERATIONS:
1.2.1 Drilling (Fig.5):
Though drilling is the basic operation, it is the one that
requires the fewest number of people. The driller operates the
drawworks alone. The rotary table rotates and drives the
drilling bit by means of the drill string and the kelly. The main
control device is the brake lever. The driller controls and
regulates the downward movement of the hook by putting on
the brake. According to the principle of rotary drilling, bits are
used at constant weight. The weight of everything that is
suspended from the hook is constant and the driller knows this
information by reading the weight on the hook when the bit is
off bottom .(Fig.)
The weight applied on the bit is the difference between the
weight on the hook off bottom and on bottom. This is the
difference that the driller reads on the weight indicator
(commonly called Martin Decker). He must keep it constant
Figure 5 The driller has control console (source :diller
by lowering the kelly at the same speed as the rate of console ,martin decker):

penetration of the bit.

The other two parameters, rotation and mud flow rate, are generally preset. The driller
checks and adjusts the values depending on the program and mainly sees to it that the pump
discharge pressure complies with the program and stays that way.

1.2.2 Adding drill pipe:

When the bit has drilled the equivalent of a length of pipe (30 ft.), the drill string must be
lengthened by screwing a new joint of drill pipe onto the bottom of the kelly . The sequence is
illustrated in ( Figs. 7 ).
Figure 6:Checking the weight on the bit.
 During drilling, the crew places a joint of pipe in a sheath, called the mousehole, located
near the rotary table.
 The driller engages the draw works to hoist the drill string to the first length of drill pipe
under the kelly. The crew puts the slips in place and the kelly can be unscrewed since the
drill string is supported by the rotary table. Mud circulation has of course been stopped.
In (Fig. 7), the crew screws the kelly to the box end of the length of drill pipe in the
mousehole. Pipe is screwed and made up in the mousehole.
 The driller hoists the kelly and drill pipe with the draw works (Fig. 7). Once the new joint
of pipe has been screwed and made up on the drill string, the driller resumes drilling fluid
circulation.
 The crew places the kelly bushing back in the rotary table and drilling can be resumed
(Fig. 7).
 1.23 The round trip :
When the bit is worn or when total borehole depth has been reached, all of the drill string must
be pulled out of the hole to change bits or run in casing pipe. The fvst step is to disconnect the
swivel from the hook and place the kelly and the swivel -which is still connected to the mud
pumps by the hose- in a sheath called the rathole (Fig.).
The crew latches the elevator under the tool joint of the first length of drill pipe and the driller
hoists the drill string to a height of three joints of pipe with the draw works. The fourth length of
pipe is clamped in the rotary table by the slips and the connection is unscrewed with the tongs
(Fig. 8). A stand of three lengths of pipe is then hanging from the elevator. The crew pushes the
lower end of the stand so that it rests on the setback. Then the demck man, who stands on the
monkey board, unlatches the elevator, holds the stand and places the upper end of the stand in
the pipe rack (Figs.8 and 9). The operation continues down to the drill collars, that are also
stacked vertically in threes.

Figure 8:Round trip. a. Latching the elevator; b. Pulling out a stand (thribble); c. Stacking the stand on the setback
(Source: A primer of oil well drilling, Petex).
 The stand length depends on how high the derrick is. The largest rigs handle stands in
threes, lightweight rigs in twos and the smallest ones can manage only singles. The running in, or
tripping in, operation is carried out in the same way. During a round trip both rotation and
circulation are at a standstill. If either is needed, the kelly is taken out of the rathole and screwed
back onto the drill string.
1.2.4 Casing:
Once the borehole has been drilled to the depth planned for the current phase, the casing pipe is
run into the well. The operation is hazardous because of the narrow clearance between the casing
and the borehole, and since it is almost impossible to rotate the casing string. Casing pipe is run
in singly joint by joint. Once it is run in, normal circulation (i.e. down the inside of the pipe) is
used to pump cement into the annulus between the casing and the borehole wall.
1.2.5 Installing the wellhead:
When casing has been run into the well and cemented, a variety of hanging and sealing
equipment must be installed on top of the well. The operations are done manually when
wellheads are above ground or above the surface of the sea offshore. Wellhead equipment also
accommodates the blowout preventers (BOP) that have a high-pressure system called kill line
and choke line. A series of pressure tests on the casing, hangers and BOP finalizes the
installation. If everything complies with safety requirements, the following drilling phase can
then commence.
1.2.6 Completion:
This is the final operation just after running in the last casing string (production casing). The
production equipment is run into the well: packer, tubing, safety valve, etc. The connection
between the producing formation and the well must often be enhanced by drilling, perforations,
acidizing, fracturing, etc. Though these operations are often performed by drillers, the techniques
involved come under the heading of downhole production which is dealt with in another book.
Figure 9:Drilling mast with stacked drill string (Source: Reynolds Aluminum Drill Pipe).
The purpose of the following chapters is to describe as completely as possible the materials,
equipment and operating techniques that are involved during drilling. This book aims to serve as
an introduction to an operation that is more complex than it seems. The goal is to help the reader
who is not a driller, but whose activity is related to drilling, understand the basics.
2.1 DRILLING BITS AND THE PARAMETERS FOR THEIR USE :

2.1.1 Roller cone bits: (Based on Airfield Catalog, Hughes Tool Division, Hughes Tool
Company) (Fig.10)
A roller cone bit is made up of three main parts: the cones, the bearings and the body of the
bit. Each cone has concentric rows of teeth that intefit with the rows of teeth in the adjacent
cones. The teeth can be made of steel machined in the cone or tungsten carbide inserts cold-
pressed into holes drilled in the cone. The cones are mounted on bearing shafts that are an
integral part of the body of the bit.
The size and thickness of the component parts of the bit depend on the type of formation to be
drilled. Bits for soft formations require little weight, have smaller bearings, less thick cone shells
and thinner legs. This design leaves more room for long thin cutters. Bits for hard formations
work with more weight, have stubbier cutters, bigger bearings and sturdier bodies.
2.1.1.1 Cone geometry
To understand how cone geometry can affect the way the teeth cut the rock formation,
consider the cone for soft formations as schematically represented in Fig. 11. It has
two basic conical angles and neither of them has its apex in the center of the bit. Since
the cones have to rotate around the axis of the bit, they skid at the same time as they rotate
and provide an effective gouging and chiseling action for drilling soft formations.

Figure 10:Three-cone bit terminology (Source: Hughes Tools).

This effect is enhanced to improve the rate of penetration in soft formations by offsetting the
axes of the cones in relation to the axis of rotation of the bit (Fig. 33). Cones on bits for hard
formations move in what is closer to real rotation, with little offset. As a result, they break down
the rock formation chiefly by crushing it

Figure 11:Design of rock bit cones (Source: Hughes Tools).

2.1.1.2 Bearing design :

There are currently three types of bearings:
1. no sealed ball or roller bearings
2. sealed ball or roller bearings
3. friction bearings.

No sealed, nonlubricated ball or roller bearings are mainly used today in bits for spudding in a
well, when the lifetime of the bit is less of a constraint since hipping times are short. They are
also advisable in instances where high rotational speeds are required (Fig. 12). When the drilling
fluid is either air, gas or foam, no sealed ball and roller bearings are also used. However, these
bits are designed so that part of the drilling fluid is channeled to cool the bearings. The sealed
ball or roller bearing was designed for insert bits. The system is currently used chiefly on toothed
bits and its lifetime is at least the same as that of the cutters. The friction, or journal bearing was
developed so that its lifetime would match that of the carbide cutters. It contains no moving
parts, there is just a bearing shaft fitted to the inside bore of the cone. The contact areas between
the shaft of the bearing and the bore of the cone are carbide treated. They are coated with special
metals and specially treated to better withstand wear and tear and keep from seizing up.

2.1.1.3 Lubricating system:

Sealed-bearing bits have their lubricating system in each arm. The system comprises a grease
reservoir, a rubber membrane compensator and a leak-proof channel. The compensator equalizes
the pressure in the bearing between the pressure of the drilling fluid and the pressure of the
grease encapsulated by the manufacturer.

2.1.1.4 Cutters :
Bits with steel teeth are used when spudding in a well, in soft formations, at high rotational
speeds and in zones where the bed thickness makes insert bits anti economical. Depending on
anticipated use, cones with milled teeth may have tungsten carbide protection on the teeth. Bits
for soft formations are designed with long, widely spaced teeth to help penetrate in the
formation and tear off larger cuttings Bits for medium and medium-hard formations have more
closely spaced teeth. Each tooth also has slightly larger angles to withstand the load required to
overcome the resistance of the formation.

Hard formations have high compressive strength and are usually very abrasive. Bits designed
to drill these formations are equipped with sturdy, closely spaced teeth and thick cone shells so
as to withstand heavy weights. These bits are designed without a skidding effect. The three cones
rotate practically on the bottom, thereby reducing abrasive wear on the teeth. The tungsten
carbide insert bit was originally designed to drill very hard, abrasive silica or quartzite
formations.
 D
Figure 12:Ball and roller bearings (Source: Hughes ue Figure 13:Bearing lubric
Tools).
to
the relatively short lifetime of toothed bits, this
type of formation proved to be very expensive to
drill. Today, because of the progress in
metallurgy and in the shape of the inserts, bits have been developed that are suitable for drilling
economically in a much wider drill ability range. Cylindrical sintered tungsten carbide inserts are
machined into a number of very different shapes .Then they are set in holes precision-machined
in the cones. This assembly gives a cutting structure that withstands abrasion wear and
compression stresses well. The ovoid shape is the sturdiest and is designed for the crushing and
chipping action required in drilling very hard formations. Ogive inserts are a little more pointed
to drill slightly softer formations. The cone also has a sturdy profile that is well suited to the
crushing and chipping type of drilling action. It is used with a scraping action to drill medium-
hard formations. The chisel shape is used in medium and softer formations for maximum
penetration owing to a gouging and scraping action. Specific chisel shapes are chosen according
to the formation and the geometrical features of the bit.
 Figure 14:Examples of carbide insert shapes (Source: Hughes Tools).

2.1.1.5 Bit hydraulics :

What is termed a "conventional" rock bit has a single drilling fluid passage down the axis of the
bit. The fluid washes the bit from the inside of the cones, but is less effective. than in jet bit
nozzles. The conventional bit is usually seen now only in large-diameter Wells. The jet bit has
three nozzles, each located between the arms of two adjacent cones (Figs15). The orifice sizes on
the nozzles can be changed for maximum. effectiveness. Turbulent flow is effective for
velocities ranging from 80 to 150 ds. The purpose of fluid streams is to keep the cones clean,
cool down the bearings and especially. to sweep formation cuttings toward the annulus. On some
bits, elongated nozzles. (Fig 16).improve cleaning efficiency.

Figure 15:Slanted nozzle (Source: Reed Tool Co.). Figure 16:Elongated nozzle (Source: Reed Tool Co.).
2.1.2 Diamond bits:
There are three types of diamond bits:

 with natural diamonds (Fig.14),

 with PDC or polycrystalline diamond cutters,
 with TSP or thermally stable polycrystalline
diamond cutters.

These three types differ in the

nature of the cutting elements
which crush the rock in a
mechanically different way.
Natural diamonds abrade the rock
and work like a large grindstone.
Figure 17:Cutters for one-piece bits(Source: Die Bo
Polycrystalline diamonds shear the rock and cut shavings like a metal lathe . tool. All these
drilling bits are one-piece, and this makes them quite sturdy.

2.1.2.1Natural diamond bits (Fig. 15) :

Diamond (crystallized carbon) is the hardest known mineral. Its compressive strength is
approximately 80,000 bar (tungsten carbide: 50,000; C.45 steel: 15,000). Its melting point is very
high (3650"C), but it turns into graphite on the surface around 1450°C. Diamonds are measured
by weight in units called carats (1 carat = 0.2 gram). For drilling bits, the size of the stones is
measured in the number of stones per carat and usually varies. from 2 to 12.

The size, type and number of diamonds on a given bit depend on the planned rate of
penetration, the size of cuttings and the homogeneity of the formation. When hard formations are
drilled at a slow penetration rate; the cuttings are very small and more easily. swept out of the
hole than at fast penetration rates. Small diamonds can be used to get maximum contact on the
working face without hindering cuttings removal. On the other hand, softer formations need less
load on the working face. Larger diamonds are used to tear out a larger chunk of rock and leave
more mom for the cuttings to pass. Though there are general rules for selecting the size of
diamonds, theexperience gained with previous bits are the best guide.

The bits are still manufactured by hand. The process begins with machining a graphite mold
(Fig.16). Inside the mold the rows and locations for each diamond are drawn along with the
design of the drilling fluid passages. Each diamond location is drilled out with a small mill. The
water courses or waterways for the drilling fluid are built in relief in the mold with a special
putty. The diamonds are then set one by one in each small hole where they are fixed in place.
The mold is filled with tungsten carbide powder with an added binder whose formulation is each
manufacturer's secret. The melting point of the binder is situated between 400 and 1400°C
depending on its formulation and varies according to the hardness required in the final matrix.
After a steel core has been placed in the mold the whole thing is put into a furnace. The
temperature must not exceed the beginning of diamond graphitization. Then the thread is
machined.

The three basic bit profiles-round,

tapered, short or long-fit most
Figure 18:Natural diamond bit terminology (Source: Hughes Tools).
applications. There are an
almost unlimited number of
variations within these categories.
The shape that is best suited to a
specific case is a practical trade-off
between the maximum rotating life
of the bit and the maximum rate of
penetration. The round nose gives
more force in hard formations .while the elongated nose shape promotes faster cutting. Diamond
compound bits are commonly used in mining and are fairly specific in that The diamonds are not
set in the matrix. The diamond compound is made up of tiny diamonds and a metallic binder.
The diamonds are distributed throughout the mass in a layer 5 to 10 mm thick. When the bit is in
operation, worn diamonds come unstuck and further layers of diamonds are exposed.

Use of diamond bits :

As for any bit, the decision to drill with a diamond bit must be based on a cost analysis. Certain
drilling situations suggest that a diamond bit can be used economically:

 When the lifetime of roller bits is very short because of wear and tear on bearings or
teeth, or because teeth have been broken.
 When the rate of penetration is very slow (1.5 m/h or less), because mud density is high,
or because the rig has inadequate hydraulic power.
 With a six-inch diameter or less, when the lifetime of roller bits is short.
 When the hole angle is increased in a directional well.
 When the weight on the bit is limited.
 In turbodrilling, where high rotational speed promotes penetration of a diamond bit.

The use of a diamond bit is limited in certain very hard fractured formations where the

diamonds can be exposed to sharp impacts. Formations containing flint or pyrite shorten

the lifetime of the diamond bit when pieces come loose and roll under the bit, damaging

the diamonds. Certain drilling situations suggest that a diamond bit can be used economically:

teeth, or because teeth have been broken. high, or because the rig has inadequate hydraulic
power

2.1.2.2 PDC bits (Fig. 19)

Bits with polycrystalline diamond blanks or compacts have either a steel body or a matrix.
Steel bodies are machined and then covered with tungsten carbide to slow down erosion.
Matrix bodies are manufactured from the same tungsten carbide material as natural diamond
bits. It was General Electric that developed the synthesis process for the diamond compacts
(Strata Pax) made of a synthetic diamond deposit a few tenths of a millimeter thick on a
tungsten carbide stud. The compacts are then set in the surface of the bit so as to provide
maximum shear to each cutter. The major drawback of the PDC is that it cannot withs and
temperatures above 800°C. This means synthetic diamonds cannot be set in a carbide matrix in
the same way as natural diamonds. They must be set in the matrix by brazing in molded holes.
In bits with steel bodies, PDC compacts are also brazed on cylindrical studs that will then be set
in drilled holes.

The development of these products has constantly widened the applications for PDC bits and
the suitable formation hardness range is located between medium-hard and soft.Limitations
that can be cited are strength in abrasive formations and hydraulic effectiveness in keeping the
PDC compacts clean.

2.1.2.3 TSP bit (Fig.20)

The latest development in diamond bits is the use of thermally stable polycrystalline. diamonds.
In contrast with PDC, TSP diamonds have undergone treatment to eliminate. incompatible
elements from the standpoint of thermal dilation and can therefore withstand. the temperatures
required to manufacture a carbide matrix.
Their triangular shape has sharp edges
for shearing the rock. TSP diamonds are
often used in conjunction with natural
diamonds.
2.1.2.4 IADC classification
Classification is based on four characters and is therefore consistent with the classification of
rock bits. Since the code of bit condition uses the same bit wear designation for three-cone rock
bits and bits with nonmoving cutter elements, daily reports, bit wear reports and data bases are
filled out in the same way.

The first character(M, S, T,) defines the type of cutting element: diamond, PDC and sintered
body, PDC and steel body, TSP, others.

The second character (a number from 1 to 9) defines the type and general shape of the profile.
The third character involves hydraulics in general.

The fourth character (a number from 0 to 9) defines the size of cutting elements and their density
on the bit.

3.1.1 Parameters for using drilling bits :

What is termed drilling parameters are a number of factors that condition how fast the They are
classified into two categories .mechanical parameters which involve the type and shape of the bit, the
weight on the hydraulic parameters, i.e. flow rate, pressure, type of drilling fluid and its well is
deepened. bit and the rotation speed, characteristics (density, viscosity, filtrate).

Figure 20:Examples of PX bits

2.1 Production
This illustration gives an overview of typical oil and gas production facilities:

Figure 21:Oil and gas production facilities

3-Oil and gas production:

3.1 Onshore:

Onshore production is economically viable from a few dozen barrels of oil a day and upward. Oil
and gas is produced from several million wells worldwide. In particular, a gas gathering network
can become very large, with production from thousands of wells, several hundred
kilometers/miles apart, feeding through a gathering network into a processing plant. This
picture shows a well, equipped with a sucker rod pump (donkey pump) often associated with
onshore oil production. However, as we shall see later, there are many other ways of extracting
oil from a non ree flowing well. For the smallest reservoirs, oil is simply collected in a holding
tank and picked up at regular intervals by tanker truck or railcar to be processed at a refinery.
Onshore wells in oil-rich areas are also high-capacity wells producing thousands of barrels per
day, connected to a 1,000,000 barrel or more per day GOSP. Product is sent from the plant by
pipeline or tankers. The production may come from many different license owners, so metering
of individual well-streams into the gathering network are important tasks. Unconventional plays
target very heavy crude and tar sands that became economically extractable with higher prices
and new technology. Heavy crude may need heating and diluents to be extracted. Tar sands
have lost their volatile compounds and are strip-mined or can be extracted with steam. It must
be further processed to separate bitumen from the sand. Since about 2007, drilling technology
and fracturing of the reservoir have allowed shale gas and liquids to be produced in increasing
volumes. This allows the US in particular to reduce dependence on hydrocarbon imports.
Canada, China, Argentina, Russia, Mexico, and Australia also rank among the top
unconventional plays. These unconventional reserves may contain more 2-3 times the
hydrocarbons found in conventional reservoirs. These pictures show the Syncrude Mildred
plant at Athabasca, Canada
Figure22 Figure 23

4.2. Offshore:

A whole range of different structures is used offshore, depending on size and water depth. In the
last few years, we have seen pure sea bottom installations with multiphase piping to shore, and
no offshore topside structure at all. Replacing outlying wellhead towers, deviation drilling is
used to reach different parts of the reservoir from a few wellhead cluster locations. Some of the
common offshore structures are.

4.2.1 Shallow water complex:

which is characterized by several independent platforms with different parts of the process and
utilities linked with gangway bridges. Individual platforms include wellhead riser, processing,
accommodations and power generation platforms.(This picture shows the BP Val Hall complex.)
Typically found in water depths up to 100 meters.

4.2.2Gravity base consists of enormous:

concrete fixed structures placed on the bottom, typically with oil storage cells in a "skirt" that
rests on the sea bottom. The large deck receives all parts of the

process and utilities in large modules. Large fields at 100 to 500 meters of

Water depth were typical in the 1980s and 1990s. The concrete was poured at an onshore
location, with enough air in the storage cells to keep the structure floating until tow-out and
lowering onto the seabed. The picture shows the world's largest GBS platform, Troll A, during
construction.PhotoStatoil

Figure25

4.2.3 Compliant towers:

are much like fixed platforms. They consist of a narrow tower, attached to a foundation on the
seafloor and extending up to the platform. This tower is flexible, as opposed to the relatively
rigid legs of a fixed platform. Flexibility allows it to operate in much deeper water, as it can
absorb much of the pressure exerted by the wind and sea. Compliant towers are used between
500 and 1,000 meters of water depth.
 Figure 23 Figure 24

4.2.4 Floating production:

where all topside systems are located on a floating structure with dry or subsea wells. Some
floaters are: FPSO: Floating Production, Storage and Offloading. Their main advantage is that
they are a standalone structure that does not need external infrastructure such as pipelines or
storage. Crude oil is offloaded to a shuttle tanker at regular intervals, from days to weeks,
depending on production and storage capacity. FPSOs currently produce from around 10,000 to
200,000 barrels per day. An FPSO is typically a tanker type hull or barge, often converted from
an existing crude oil tanker (VLCC or ULCC). Due to the increasing sea depth for new fields,
they dominate new offshore field development at more than 100 meters water depth. The
wellheads or subsea risers from the sea bottom are located on a central or bow-mounted turret, so
that the ship can rotate freely to point into wind, waves or current. The turret has wire rope and
chain connections to several anchors (position mooring - POSMOOR), or it can be dynamically
positioned using thrusters (dynamic positioning – DYNPOS). Most installations use subsea
wells. The main process is placed on the deck, while the hull is used for storage and offloading to
a shuttle tanker. It may also be used for the transportation of pipelines. FPSOs with additional
processing and systems, such as drilling, and production and stranded gas LNG production are
planned. A variation of the FPSO is the Sevan Marine design. This uses a circular hull which
shows the same profile to wind, waves and current, regardless of direction. It shares many of the
characteristics of the ship shaped FPSO, such as high storage capacity and deck load, but does
not rotate and therefore does not need a rotating turret. Photo: Sevan Marine.

Figure 24: Figure 25:

4.2.5 Tension Leg:

Platform (TLP – left side in picture) consists of a structure held in place by vertical tendons
connected to the sea floor by pile secured. templates. The structure is held in a fixed position by
tensioned tendons, which provide for use of the TLP in a broad water depth range up to about
2,000m. The tendons are constructed as hollow high tensile strength steel pipes that carry the
spare buoyancy of the structure and ensure limited vertical motion.

4.2.6. Semi-submersible platforms:

(front of picture) have a similar design but without tautmooring. This permits more lateral and
vertical motion and is generally used with flexible risers and subsea wells. Similarly, Sea star
platforms are miniature floating tension leg platforms, much like the semi- submersible type,
with tensioned tendons. SPAR consists of a single tall floating cylindrical hull, supporting a
fixed deck. The cylinder does not, however, extend all the way to the seabed. Rather, it is
tethered to the bottom by a series of cables and lines. The large cylinder serves to stabilize the
platform in the water and allows for movement to absorb the force of potential hurricanes.
SPARs can be quite large and are used for water depths from 300 up to 3,000 meters. SPAR is
not an acronym, and is named for its resemblance to a ship's spar. SPARs can support dry
completion wells but are more often used with subsea wells.
4.2.7. Subsea production systems:

are wells located on the sea floor, as opposed to the surface. As in a floating production system,
the petroleum is extracted at the seabed, and is then “tied-back” to a pre-existing production
platform or even an onshore facility, limited by horizontal distance or "offset.” The well is
drilled by a movable rig and the extracted oil and natural gas is transported by undersea pipeline
and riser to a processing facility. This allows one strategically placed production platform to
service many wells over a reasonably large area. Subsea systems are typically used at depths of
500 meters or more and do not have the ability to drill, only to extract and transport. Drilling and
completion is performed from a surface rig. Horizontal offsets of up to 250 kilometers/150 miles
are currently possible. The aim of the industry is to allow fully autonomous subsea production
facilities, with multiple well pads, processing, and direct tie-back to shore.

Figure 26
5-Drilling bits:
Drill heads are considered the main and indispensable part in the drilling assortment for oil and
gas production, as they represent the breaks up and cuts rocks penetrate the layers and reaches
the desired goal of drilling the well. In fact, there are many diameters, types, shapes and sizes of
the bits used, as the nature of the layers plays an important role. In the process of selecting the
ileum, the correct selection of ileum is what ensures that the drilling proceeds in a safe and sound
manner. Otherwise, the wrong choice leads to a number of problems such as the collapse of the
gears and teeth of the ileum, thus stopping the drilling process and having to replace the ileum
and insert a new one, which leads to the cessation of operations and prolongation. Human
achievement and increasing economic costs.

6-Classification of ticks:
Minutes are divided into several types according to the purpose of their use. The most important
of these types are: 1-ordinary drilling rings (Rock Bits): these are the rigs through which the
entire surface of human beings is drilled.as shown in (Figure28).

2-core Bits: these are the particles through which the bottom of the well is drilled in an annular
fashion, to obtain a core sample. (cylindrical) excavated rocks, clean and not crumbled. as shown
in (Figure27).

3-Expansion chips (hole opener Bits): These are chips through which the diameter of previously
drilled well is expanded with smaller diameter chips. as shown in (Figure29).

Figure 29: hole opener bite Figure 28: rock bite Figure 27 : core bites
These pimps have gone through a number of stages of evolution to what they are now in the rock
bit standard technology, helping extend the life of the pimp, increasing its mechanical speed, and
we can describe these. Beats in two large timelines:

1-Tricone pickers.

2-picker bevel gears PDC.

3-Tricone Bevel gear chimes.

This group of chimes is characterized by a rotating trombone, with strong teeth on it that chop up
the rock, and it’s been cleared of this. Pickers are numerous models, some in two, three or four
gears, and as a result of a field experiment it was found that tromophilic chimes. They have the
best managers, which are the dominate ones today: the drill head conical trombone sections: the
drill rig cone trombone is composed of several features.

1-percolator: the structure of the percolator, which is spelled into the hole, forms drilling
problems and includes the following sections:

 This is the connection that creates a connection.

 They form the axis of rotation of the bevel gears. (cycling holes) these are three epithelial
openings in the body of the orifice from which the drilling fluid is released from the
inside of the drilling pipes.
 Towards the annular space or some ileum (an additional central opening), thus increasing.
 Mechanism (its function is to facilitate the rotational movement of the conical gears
around the centers of support, and to increase the life of the pellets and the life span of
the ileum. The pellet lubrication.

2- conical lessons: They are three in number (tree cones). They are mounted on the centers of the
stadium located on the body of the ileum and revolve around them with the help of a group of
billets while the ileum works to unfold. as shown in( Figure 6).
3- ileum teeth: They are located on the conical gears, and they form the effective squeeze of the
ileum, through which they are carried out. Under rocks, they can be made in the ground of the
ileum itself and from the touch of its surface or made of hard metals and embedded in the
mineral of the pulp. Teeth can also be made in various shapes, including (cylindrical braces with
circular edges - cylindrical braces with beveled edges - teeth Hemispherical and used for very
hard rocks.

4-The number of these cases is three. They are located between the three ileums, and their main
purpose is to expel the drilling fluid very quickly, helping to smooth out the gears of the ileum
and clean the bottom of the person from the drilled rock fragments. Some ileums have one
central ileum, and some have a central ileum. In addition to the three side valves, these valves are
installed within the openings of the ileum, where they are fixed to them using a special spark, a
plier, or a special nail. The ileum valves are of two types: standard valves (extended jets) and
standard jets.

Figure30:
 Figure 31 : oil and gas production overvie

Reference:
1. https://www.google.com/url?
sa=t&rct=j&q=&esrc=s&source=web&cd=&cad=rja&uact=8&ved=2ahUKEwjEzYWW8IuD
AxX3VaQEHVUjAnIQFnoECA0QAQ&url=https%3A%2F%2Femufeed.com%2Findex.php
%2Far%2Farticle%2F%25D8%25B1%25D8%25A4%25D9%2588%25D8%25B3_
%25D8%25A7%25D9%2584%25D8%25AD%25D9%2581%25D8%25B1_Drilling_Bits_
%25C2%25A0_%25D8%25A7%25D9%2584%25D8%25AC%25D8%25B2%25D8%25A1_
%25D8%25A7%25D9%2584%25D8%25A3%25D9%2588%25D9%2584&usg=AOvVaw0x7
qsNnIu4BlOM-AuRGUFe&opi=89978449.
2. from drilling book (chapter 1, chapter 3)
3. from oil and gas production handbook (onshore and offshore) p. (7-20).