monthly training report drilling june-july 2014
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DrillingTRANSCRIPT
Drilling Operations
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Drilling Operations
DRILLING OPERATIONS SUBMITTED TO: MUHAMMAD AYUB KHAN
SHOUKAT ALI BALOCH
ADNAN SIRAJ TRAINEE MECHANICAL ENGINEER
AUGUST 21, 2014
Drilling Operations
Acknowledgement
In the name of ALLAH, the Most Beneficent, the Most Merciful. All praise and thanks to
ALMIGHTY ALLAH, who Has blessed me with the skills and abilities to complete this report
and hence, thereby, portraying a clear picture of what I have been doing during the course of
my working on a drilling of PKL-7 and PKL-8. I also would like to thank to Mari Petroleum
for providing me a prestigious opportunity of working in a professional field.
I also take this opportunity to express my gratitude to Mr. Muhammad Ayub Khan, Mr.
Shoukat Ali Baloch, Mr. Faisal Amjed, Mr. Sarfraz Ahmad and Mr. Muhammad Rashid
without whom it would be difficult to convert the whole drilling project into a comprehensive
documentation.
My two month’s working on a drilling project of PKL-7 and PKL-8 was a memorable
experience. During the course of my orientation each job that I had done, every moment that I
spent with my colleagues, subordinates and seniors was unforgettable.
I owe enormous thanks to my parents, who always extend their support towards me.
Drilling Operations
Abstract
This report highlights all the learning that I had done, all the jobs in which I assisted and all the
assignments that I had completed during the drilling of PKL-7 and PKL-8.
The synopsis of report is such that it covers the drilling operations, casing and cementing, well
testing, well logging and well completion and the jobs that I had done, as well as, the tasks in
which I participated during the course of my training.
Drilling Operations
Contents
1 Chapter 01: Rotary drilling ............................................................................................................. 1
1.1 Rotary crushing ....................................................................................................................... 1
1.2 Rotary cutting .......................................................................................................................... 1
1.3 Rotary drilling rig components ............................................................................................... 1
1.3.1 Derrick or mast and substructure .................................................................................... 1
1.3.1.1 Mast ............................................................................................................................. 1
1.3.1.2 Derrick ........................................................................................................................ 2
1.3.1.3 Substructure ................................................................................................................ 2
1.3.2 Power and prime movers ................................................................................................. 3
1.3.2.1 Mechanical rig............................................................................................................. 3
1.3.2.2 Electrical drilling rig ................................................................................................... 3
1.3.3 Hoisting system ............................................................................................................... 4
1.3.3.1 Drawworks .................................................................................................................. 5
1.3.3.2 Crown block ................................................................................................................ 5
1.3.3.3 Travelling block .......................................................................................................... 6
1.3.3.4 Dead line anchor ......................................................................................................... 8
1.3.3.5 Supply reel ................................................................................................................ 10
1.3.3.6 Drilling line ............................................................................................................... 10
1.3.3.7 Drilling types ............................................................................................................ 10
1.3.3.7.1 Dead line ............................................................................................................. 10
1.3.3.7.2 Fast line ............................................................................................................... 10
1.3.3.8 Types of wire-rope for drilling line ........................................................................... 10
1.3.3.9 Type of wire rope construction ................................................................................. 11
1.3.4 Rotating system ............................................................................................................. 12
1.3.4.1 Swivel ....................................................................................................................... 12
1.3.4.2 Kelly spinner ............................................................................................................. 14
1.3.4.3 Kelly .......................................................................................................................... 15
1.3.4.4 Top drive ................................................................................................................... 15
1.3.4.5 Kelly bushing ............................................................................................................ 16
1.3.4.6 Master bushing .......................................................................................................... 16
1.3.4.7 Rotary table ............................................................................................................... 17
1.3.5 Circulating system......................................................................................................... 18
1.3.5.1 Mud pump ................................................................................................................. 18
1.3.5.2 Pump manifold .......................................................................................................... 19
1.3.5.3 Stand pipe .................................................................................................................. 20
1.3.5.4 Return line ................................................................................................................. 21
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1.3.5.5 Shale shaker .............................................................................................................. 21
1.3.5.6 Desander ................................................................................................................... 22
1.3.5.7 Desilter ...................................................................................................................... 22
1.3.5.8 Degasser .................................................................................................................... 23
1.3.5.9 Mud pit ...................................................................................................................... 23
1.3.5.10 Well control system .............................................................................................. 24
2 Chapter 02: Tubular and tubular handling equipment .................................................................. 25
2.1 Drill pipe ............................................................................................................................... 25
2.2 Drill collar ............................................................................................................................. 26
2.3 Heavy weight drill pipe (HWDP) ......................................................................................... 26
2.4 Subs ....................................................................................................................................... 26
2.5 Tubular handling equipment ................................................................................................. 28
2.5.1 Elevator links ................................................................................................................ 28
2.5.2 Elevator ......................................................................................................................... 29
2.5.3 Tugger/winch ................................................................................................................ 29
2.5.4 Slips ............................................................................................................................... 30
2.5.5 Safety clamp .................................................................................................................. 31
2.5.6 Tong .............................................................................................................................. 32
2.5.7 Drill pipe spinner .......................................................................................................... 32
2.5.8 Iron roughneck .............................................................................................................. 33
2.5.9 Bit breaker ..................................................................................................................... 33
3 Chapter 03: Drill bits .................................................................................................................... 34
3.1 Roller cone bits ..................................................................................................................... 34
3.1.1 Milled tooth bits ............................................................................................................ 35
3.1.1.1 Soft formation cutting structure ................................................................................ 35
3.1.1.2 Medium formation cutting structure ......................................................................... 35
3.1.1.3 Hard formation cutting structure ............................................................................... 35
3.1.2 Tungsten carbide inserts bits ......................................................................................... 36
3.2 Fixed cutter bits ..................................................................................................................... 36
3.2.1 Polycrystalline diamond compact (PDC) bits ............................................................... 36
3.2.1.1 Cutting action ............................................................................................................ 37
3.2.2 Impregnated bits ............................................................................................................ 38
3.2.3 Diamond bits ................................................................................................................. 38
4 Chapter 04: Casing ........................................................................................................................ 40
4.1 Conductor casing .................................................................................................................. 40
4.2 Surface casing ....................................................................................................................... 40
4.3 Intermediate casing ............................................................................................................... 40
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4.4 Production casing .................................................................................................................. 40
4.5 Liner ...................................................................................................................................... 41
5 Chapter 05: Cementing ................................................................................................................. 42
5.1 Cement additives ................................................................................................................... 42
5.1.1 Accelerators .................................................................................................................. 42
5.1.2 Retarders ....................................................................................................................... 42
5.1.3 Extenders ....................................................................................................................... 42
5.1.4 Pozzolans ...................................................................................................................... 42
5.2 Chemical wash ...................................................................................................................... 43
5.3 Spacer .................................................................................................................................... 43
5.4 Cement slurry ........................................................................................................................ 43
5.5 Cement classification ............................................................................................................ 43
5.6 Cementing procedure ............................................................................................................ 44
6 Chapter 06: Perforations and testing ............................................................................................. 45
6.1 Perforations ........................................................................................................................... 45
6.2 Perforation methods .............................................................................................................. 45
6.2.1 Bullet perforation .......................................................................................................... 45
6.2.2 Jet perforation ............................................................................................................... 45
6.3 Perforation equipment ........................................................................................................... 45
6.3.1 Guns/ carriers ................................................................................................................ 45
6.3.2 Thick walled gun ........................................................................................................... 45
6.3.3 Hollow-carrier guns ...................................................................................................... 45
6.3.4 Through-tubing guns ..................................................................................................... 46
6.3.5 Expendable guns ........................................................................................................... 46
6.3.6 Detonator system........................................................................................................... 46
6.4 Conveyance system ............................................................................................................... 47
6.5 Drill stem test ........................................................................................................................ 47
6.6 DST tools .............................................................................................................................. 47
6.6.1 Mule shoe ...................................................................................................................... 47
6.6.2 Retrievable packer......................................................................................................... 47
6.6.3 Safety joint .................................................................................................................... 47
6.6.4 Hydraulic jar ................................................................................................................. 48
6.6.5 Hydraulic circulating valve (Bypass valve) .................................................................. 48
6.6.6 Gauge carrier ................................................................................................................. 48
6.6.7 Down-hole tester valve ................................................................................................. 48
6.6.8 Rupture disc circulating valve ....................................................................................... 48
6.6.9 Slip joint ........................................................................................................................ 48
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6.6.9.1 Operation ................................................................................................................... 48
6.6.10 Flow head ...................................................................................................................... 49
6.7 Testing procedure of DST ..................................................................................................... 49
6.8 Well killing ........................................................................................................................... 51
6.8.1 Well killing procedure .................................................................................................. 51
7 Chapter 07: Well completion ........................................................................................................ 52
7.1 Open hole completion ........................................................................................................... 52
7.2 Cased hole completion .......................................................................................................... 52
7.2.1 Tubing-less completion ................................................................................................. 52
7.2.2 Packer-less completion ................................................................................................. 52
7.2.3 Single string with hydraulic isolation completion ........................................................ 53
7.2.4 Multiple tubing string completion ................................................................................. 53
7.3 Completion equipment .......................................................................................................... 54
7.3.1 Tubular equipment ........................................................................................................ 54
7.3.2 Flow couplings .............................................................................................................. 54
7.3.3 Blast joints .................................................................................................................... 54
7.3.4 Circulating devices ........................................................................................................ 54
7.3.5 Sliding sleeve ................................................................................................................ 54
7.3.6 Side pocket mandrels .................................................................................................... 55
7.3.7 Expansion joints ............................................................................................................ 55
7.3.8 Landing nipples ............................................................................................................. 55
7.3.9 Wellhead couplings ....................................................................................................... 55
7.4 Completion procedure ........................................................................................................... 55
7.5 Acid job ................................................................................................................................. 56
7.5.1 Silt and particle removal acid system............................................................................ 56
7.5.2 Surfactant ...................................................................................................................... 56
7.5.3 Suspending agent .......................................................................................................... 56
7.5.4 Corrosion inhibitor ........................................................................................................ 56
7.5.5 Acid ............................................................................................................................... 57
7.5.6 Surfactant base KCL brine ............................................................................................ 57
7.5.7 Potassium chloride ........................................................................................................ 57
7.5.8 KCL brine for displacement and trickling .................................................................... 57
7.6 Acid job procedure ................................................................................................................ 57
7.6.1 Perforation wash ........................................................................................................... 57
7.6.2 Main treatment .............................................................................................................. 57
7.6.3 Post flush ....................................................................................................................... 57
8 Chapter 08: Well logging .............................................................................................................. 58
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8.1 Logging operation procedure ................................................................................................ 58
8.2 Resistivity logs ...................................................................................................................... 58
8.2.1 Dual lateral log .............................................................................................................. 58
8.2.1.1 Theory ....................................................................................................................... 59
8.2.2 Micro spherically focused log ....................................................................................... 59
8.2.3 Induction logging .......................................................................................................... 59
8.3 Porosity log ........................................................................................................................... 59
8.3.1 Neutron porosity log ..................................................................................................... 60
8.3.1.1 Advantages ................................................................................................................ 60
8.3.2 Density log .................................................................................................................... 60
8.3.2.1 Tool configuration..................................................................................................... 60
8.4 Gamma ray log ...................................................................................................................... 61
8.4.1 Application .................................................................................................................... 61
8.5 Casing collar locator ............................................................................................................. 61
8.5.1 Purpose .......................................................................................................................... 61
8.5.2 Application .................................................................................................................... 61
8.6 Cement bond log ................................................................................................................... 61
8.6.1 Purpose .......................................................................................................................... 61
8.6.2 Application .................................................................................................................... 61
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List of figures
Figure 1-1 Mast ....................................................................................................................................... 1
Figure 1-2 Derrick ................................................................................................................................... 2
Figure 1-3 Substructure ........................................................................................................................... 2
Figure 1-4 Power and prime mover for Mechanical drilling rig ............................................................. 3
Figure 1-5 Power and prime mover for Electrical drilling rig ................................................................ 4
Figure 1-6 Drawworks ............................................................................................................................ 5
Figure 1-7 Crown block .......................................................................................................................... 5
Figure 1-8 Fast and Crown sheaves of crown block ............................................................................... 6
Figure 1-9 Block of travelling block ....................................................................................................... 7
Figure 1-10 Hook of travelling block ..................................................................................................... 7
Figure 1-11 Hooks for travelling block ................................................................................................... 8
Figure 1-12 Deadline anchor................................................................................................................... 9
Figure 1-13 Supply reel ........................................................................................................................ 10
Figure 1-14 Right lang lay .................................................................................................................... 11
Figure 1-15 Left lang lay ...................................................................................................................... 11
Figure 1-16 Right regular lay ................................................................................................................ 11
Figure 1-17 Left regular lay .................................................................................................................. 11
Figure 1-18 wire rope construction types ............................................................................................. 11
Figure 1-19 Hoisting system ................................................................................................................. 12
Figure 1-20 Swivel ................................................................................................................................ 12
Figure 1-21 Swivel assembly ................................................................................................................ 13
Figure 1-22 Kelly Spinner .................................................................................................................... 14
Figure 1-23 Kelly .................................................................................................................................. 15
Figure 1-24 Top drive (Hydraulically powered device) ....................................................................... 15
Figure 1-25 type HDS: Heavy duty for square drive rotary table ......................................................... 16
Figure 1-26 Type HDP: Heavy duty fits 23" through 49-1/2" rotary table ........................................... 16
Figure 1-27 Type MDS: Medium duty for square drive rotary table .................................................... 16
Figure 1-28 Type MSPC-Type MSPC- Fits 17-1/2" to 27-1/2" rotary table ........................................ 16
Figure 1-29 Type MPCH-Type MSPC- Fits 37-1/2" to 49-1/2" rotary table ....................................... 16
Figure 1-30 Type MSPC- Fits 20-1/2" to 27-1/2" rotary table ............................................................. 16
Figure 1-31 Type MBSS-Type MSPC- Fits 17-1/2" to 27-1/2" rotary table ........................................ 16
Figure 1-32 Rotary tables with master bushings ................................................................................... 17
Figure 1-33 Mud Pump ......................................................................................................................... 19
Figure 1-34 Parts of circulation system ................................................................................................ 19
Figure 1-35 Pump manifold .................................................................................................................. 20
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Figure 1-36 Stand pipe .......................................................................................................................... 20
Figure 1-37 Mud return line .................................................................................................................. 21
Figure 1-38 Shale shaker along with its parts ....................................................................................... 21
Figure 1-39 Desander ............................................................................................................................ 22
Figure 1-40 Desilter .............................................................................................................................. 22
Figure 1-41 Degasser ............................................................................................................................ 23
Figure 1-42 Mud Pit .............................................................................................................................. 23
Figure 1-43 Circulation system ............................................................................................................. 24
Figure 2-1 Components of drill pipe ..................................................................................................... 25
Figure 2-2 Drill pipes ............................................................................................................................ 25
Figure 2-3 Drill collars .......................................................................................................................... 26
Figure 2-4 Heavy weight drill pipe ....................................................................................................... 26
Figure 2-5 Kelly sub, crossover sub, drill collar sub and bit sub .......................................................... 27
Figure 2-6 Subs ..................................................................................................................................... 27
Figure 2-7 Elevator and lifting sub ....................................................................................................... 28
Figure 2-8 Elevator links ...................................................................................................................... 28
Figure 2-9 Single joint elevator ............................................................................................................ 29
Figure 2-10 Center latch elevator.......................................................................................................... 29
Figure 2-11 Side door elevator.............................................................................................................. 29
Figure 2-12 Elevator links along with elevator links ............................................................................ 29
Figure 2-13 Tugger/Air winch .............................................................................................................. 29
Figure 2-14 Casing slips ....................................................................................................................... 30
Figure 2-15 Drill pipe slips ................................................................................................................... 30
Figure 2-16 Drill collar slips ................................................................................................................. 30
Figure 2-17 Usage of slips during drilling operation ............................................................................ 31
Figure 2-18 Safety clamps .................................................................................................................... 31
Figure 2-19 Usage of safety clamp while drilling ................................................................................. 31
Figure 2-20 Make up and break up tongs ............................................................................................. 32
Figure 2-21 drill pipe spinner................................................................................................................ 33
Figure 2-22 Iron roughneck .................................................................................................................. 33
Figure 2-23 Bit breaker ......................................................................................................................... 33
Figure 3-1 Roller cone bit ..................................................................................................................... 34
Figure 3-2 Tooth cutting structure, teeth spacing and tooth angle of milled tooth bit .......................... 35
Figure 3-3 Milled tooth tricone bit ........................................................................................................ 35
Figure 3-4 Tungsten cribde insert tricone bit ........................................................................................ 36
Figure 3-5 Medium PDC bit ................................................................................................................. 37
Figure 3-6 Short PDC bit ...................................................................................................................... 37
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Figure 3-7 TSP bit ................................................................................................................................. 37
Figure 3-8 Impregnated bit ................................................................................................................... 38
Figure 3-9 Diamond bit ......................................................................................................................... 39
Figure 4-1 Casings ................................................................................................................................ 41
Figure 6-1 Slip joint .............................................................................................................................. 49
Figure 6-2 DST tool .............................................................................................................................. 50
Figure 7-1 Packerless completion ......................................................................................................... 52
Figure 7-2 Selective single string completion ....................................................................................... 53
Figure 7-3 Dual string completion ........................................................................................................ 53
Figure 7-4 Single string packer completion .......................................................................................... 53
Figure 7-5 Wellhead and Christmas tree ............................................................................................... 56
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1 Chapter 01: Rotary drilling In rotary drilling, drill bit cuts the rock with energy supplied to it by a rotating drill string.
Rotary drilling can be subdivided into rotary crushing and rotary cutting.
1.1 Rotary crushing
Rotary crushing breaks the rock by high point load (compression), accomplished by a toothed
drill bit, which is pushed downwards with high force. The roller cone type bit is used for rotary
crushing operation.
1.2 Rotary cutting
Rotary cutting creates a hole by shear forces, breaking the rock’s tensile strength. The drill bit
is furnished with cutting inserts of hard metal alloys, and the energy for breaking the rock is
provided by torque. This technique is limited to rock with low tensile strength such as salt, silt
and soft limestone not containing abrasive quartz minerals.
1.3 Rotary drilling rig components
1. Derrick or mast and substructure
2. Power and prime mover
3. Hoisting System
4. Rotating system
5. Circulating system
6. Well control system
7. Tubular and tubular handling equipment
8. Drill bit
1.3.1 Derrick or mast and substructure
1.3.1.1 Mast
A portable derrick that can be raised as unit. For transporting by land, the mast can be divided
into two or more section.
Figure 1-1 Mast
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1.3.1.2 Derrick
A large load bearing structure, usually of bolted construction. The standard derrick has four
legs standing at the corners of the substructure.
Figure 1-2 Derrick
1.3.1.3 Substructure
The foundation in which the derrick or mast and usually the Drawworks sit. In contains space
for storage and well control equipment.
Figure 1-3 Substructure
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1.3.2 Power and prime movers
Internal combustion engine or a turbine that is the source of power for driving equipment on
the Rig.
1.3.2.1 Mechanical rig
A drilling rig in which the source of power is one or more internal combustion engine and in
which power is distributed to rig components through devices such as chains, sprockets,
clutches and shaft is said to be a Mechanical Rig.
1.3.2.2 Electrical drilling rig
A drilling rig in which the source of power is effected by the combination of engines, generator
set, control system and electric motors is said to be an Electric Drilling Rig.
Figure 1-4 Power and prime mover for Mechanical drilling rig
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1.3.3 Hoisting system
The rig system responsible for raising and lowering of drill string is known as hoisting system.
It consists of the following;
1. Mast or derrick
2. Drawworks
Figure 1-5 Power and prime mover for Electrical drilling rig
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3. Crown block
4. Travelling block
5. Deadline anchor
6. Supply real
7. Drilling line
1.3.3.1 Drawworks
The hoisting mechanism on a drilling rig. It is essentially a winch that spools off or takes in the
drilling line and thus raises or lowers the drill string.
1.3.3.2 Crown block
An assembly of sheaves mounted on beams at the top of the derrick/mast and over which the
drilling line is reeved.
Figure 1-6 Drawworks
Figure 1-7 Crown block
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1.3.3.3 Travelling block
An assembly of sheaves or pulleys through which the drilling line is reeved and which moves
up and down in the Derrick or Mast.
Figure 1-8 Fast and Crown sheaves of crown block
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Figure 1-9 Block of travelling block
Figure 1-10 Hook of travelling block
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1.3.3.4 Dead line anchor
An equipment that holds down the dead line part of the wire rope. It is usually bolted on to the
substructure.
Figure 1-11 Hooks for travelling block
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Figure 1-12 Deadline anchor
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1.3.3.5 Supply reel
A spool that stores the unused portion of the Drilling Line.
1.3.3.6 Drilling line
The wire rope used to support the drilling tools. Drilling line runs from supply reel to the crown
block via drawworks and passes through one sheave then it goes down to the traveling block
and wraps around it through one of its sheaves and returns back to crown block. To multiply
the strength of hoisting system, drilling line is back and forth several times between two blocks.
It is known as Block and Tackle arrangement. It increases the mechanical advantage.
1.3.3.7 Drilling types
1.3.3.7.1 Dead line
Drilling line from supply reel to crown block is called deadline, this line cannot move due to
dead line anchor.
1.3.3.7.2 Fast line
Drilling line from drawworks to crown block is called fast-line and it can move. Drum brake
is used to stop fast-line.
1.3.3.8 Types of wire-rope for drilling line
The following are the wire ropes used for drilling line;
Figure 1-13 Supply reel
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Figure 1-14 Right lang lay
Figure 1-15 Left lang lay
Figure 1-16 Right regular lay
Figure 1-17 Left regular lay
1.3.3.9 Type of wire rope construction
Figure 1-18 wire rope construction types
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Figure 1-19 Hoisting system
1.3.4 Rotating system
The system which is responsible for rotating the drill string. It consists of the following;
1. Swivel
2. Kelly spinner
3. Kelly or top drive
4. Kelly bushing
5. Master bushing
6. Rotary table
1.3.4.1 Swivel
The rotary tool that is hung from the hook of the traveling block to suspend the drill string and
permit it to rotate freely. It also provide connection for the rotary hose and provide passageway
for the flow of drilling fluid into the drill string.
Figure 1-20 Swivel
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Figure 1-21 Swivel assembly
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1.3.4.2 Kelly spinner
A pneumatically controlled device mounted below the Swivel that when actuated causes the
Kelly to spin.
Figure 1-22 Kelly Spinner
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1.3.4.3 Kelly
The heavy steel member, usually four or six-sided that is suspended from the Swivel through
the Rotary Table and connected to the top most joint of drill pipe to turn the drill stem as the
rotary table turns. It has a bored passageway that permits fluid to be circulated into the drill
stem and up the annulus or vise-versa.
Figure 1-23 Kelly
1.3.4.4 Top drive
A hydraulically powered device located below the Swivel that when actuated allows the Drill
string to spin and proceed in drilling.
Figure 1-24 Top drive (Hydraulically powered device)
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1.3.4.5 Kelly bushing
A device that when fitted to master bushing transmits torque to the kelly and simultaneously
permits vertical movement of the Kelly to make hole.
1.3.4.6 Master bushing
A device that fits into the rotary table to accommodate the slips and drive the kelly bushing so
that the rotating motion of the rotary table can be transmitted to the Kelly.
Figure 1-26 Type HDP: Heavy duty fits 23" through 49-1/2" rotary table
Figure 1-25 type HDS: Heavy duty for square drive rotary table
Figure 1-27 Type MDS: Medium duty for square drive rotary table
Figure 1-30 Type MSPC- Fits 20-1/2" to 27-1/2" rotary table
Figure 1-29 Type MPCH-Type MSPC- Fits 37-1/2" to 49-1/2" rotary table
Figure 1-28 Type MSPC-Type MSPC- Fits 17-1/2" to 27-1/2" rotary table
Figure 1-31 Type MBSS-Type MSPC- Fits 17-1/2" to 27-1/2" rotary table
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1.3.4.7 Rotary table
Equipment used to turn the drill string and support the drilling assembly. It has a beveled gear
arrangement to create the rotational motion and opening into which bushings are fitted to drive
and support the drilling assembly.
Figure 1-32 Rotary tables with master bushings
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1.3.5 Circulating system
This system is responsible for the movement of drilling fluid within the well as well as solids
removal also incurred by the drilling fluid. Normally the circulation would start from the mud
pits, down the drill-string, up the annulus and back to the mud pits.
The circulation system consists of the following;
1. Mud pump
2. Pump manifold
3. Standpipe
4. Swivel
5. Drill-string
6. Annulus
7. Return line
8. Shale shaker
9. Desander
10. Desilter
11. Degasser
12. Mud pit
1.3.5.1 Mud pump
A large, high-pressure reciprocating pump used to circulate the mud on a drilling rig. A typical
mud pump is a two cylinder, double acting or a three cylinder, single acting piston pump whose
pistons travel in replaceable liners and are driven by a crankshaft actuated by an engine or
motor.
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1.3.5.2 Pump manifold
An arrangement of piping and valves that receives drilling fluid from one or more mud pumps
and transmit the drilling fluid to the succeeding circulating component.
1.Suction tank
2.Prehydration tank
3.Charging pump
4. Agitator motors
5. Mud hopper
6. Suction line
7. Charging pump
(MP)
8. Mud pump
9. Valve and piston
10. Mud pump
discharge manifold
11. Pressure gauge
12. Pulsation
dampener
13. Pressure relief
valve
14. Discharge line
15. Mud pump
engine
16. Intermediate
tank
Figure 1-33 Mud Pump
16 15 15
14
13 13 12
12 12 11
10 10 10
9 9
8 8
7 7
6
6 6
5 4 4 4
3
1
2
11
14
Figure 1-34 Parts of circulation system
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Figure 1-35 Pump manifold
1.3.5.3 Stand pipe
The vertical pipe rising along the side of the Derrick or Mast, which joins mud pump manifold
to the rotary hose.
Figure 1-36 Stand pipe
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1.3.5.4 Return line
The passageway of the drilling fluid as it comes out of the well.
Figure 1-37 Mud return line
1.3.5.5 Shale shaker
An equipment that use a vibrating screen to remove cuttings from the circulating fluid in rotary
drilling operations.
1. Return line
2. Possum belly
3. Electric motor
4. Shaker screen
1
3
4
2
3
4
Figure 1-38 Shale shaker along with its parts
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Shale shakers are designed to handle100-1600 gpm flow rate of mud and be able to remove
cutting to size of 77 microns usinga200 mesh screen.
1.3.5.6 Desander
A centrifugal device for removing sand from the drilling fluid to prevent abrasion of the pumps.
1.3.5.7 Desilter
It’s a centrifugal device for removing free particles of silt from the drilling fluid to keep the
amount of solids in the fluid at the lowest possible point.
Figure 1-39 Desander
Figure 1-40 Desilter
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1.3.5.8 Degasser
It is used to remove the gas from a drilling fluid.
Figure 1-41 Degasser
1.3.5.9 Mud pit
A waste pit, usually an excavated earthen-walled pit, which is used for storage of waste from
drilling fluid.
Figure 1-42 Mud Pit
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Figure 1-43 Circulation system
1.3.5.10 Well control system
This system is responsible for preventing the buildup of unwanted formation fluids that lead to
Blowout. It consists of the following;
1. Annular blowout preventer
2. Ram blowout preventer
3. Blind/shear rams
4. Pipe rams
5. Diverter
6. Drilling spools
7. Manifold, valves and sensors
8. Accumulator
9. Inside BOP
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2 Chapter 02: Tubular and tubular handling equipment Tubular are made of the following equipment;
1. Drill pipe
2. Drill collar
3. Heavy weight drill pipe
4. Kelly subs
2.1 Drill pipe
These are heavy seamless tubing used to rotate the bit and circulated the drilling fluid. Joints
of pipe approximately 30 feet long are coupled together by means of tool joints.
Figure 2-1 Components of drill pipe
Figure 2-2 Drill pipes
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2.2 Drill collar
The heavy, thick-walled tube steel, used between the drill pipe and the bit in the drill string to
provide pendulum effect to the drill string and to provide weight on bit.
2.3 Heavy weight drill pipe (HWDP)
Similar in appearance to a drill pipe, HWDP has the following different dimensional
characteristics; the tube wall is heavier about 1” thick in most sizes, the tool joints are longer,
and the tube section has a larger diameter at mid length to protect the pipe from wear. HWDP
were developed for the following reasons;
1. As a transition member to be run between drill collars and drill pipe.
2. As a flexible weight member to run on directional drilling.
3. As a weight member on small rigs, drilling small diameter holes.
Figure 2-4 Heavy weight drill pipe
2.4 Subs
A short, threaded piece of pipe used to adapt parts of the drilling string that cannot otherwise
be screwed together because of difference in thread size or design. These consist of;
1. Bit sub
2. Cross over
Figure 2-3 Drill collars
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3. Kelly saver sub
4. Lifting sub
5. Bent sub
Figure 2-5 Kelly sub, crossover sub, drill collar sub and bit sub
Figure 2-6 Subs
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Figure 2-7 Elevator and lifting sub
2.5 Tubular handling equipment
Equipment used to move, make and break connection, suspend tubular on the rig. These include
the following:
1. Elevator links
2. Elevator
3. Lifting subs
4. Lifting plug
5. Tugger/winch
6. Slips
7. Safety clamps
8. Tongs
9. Kelly spinner
10. Drill pipe spinner
11. Iron roughneck
12. Bit breaker
2.5.1 Elevator links
Equipment attached onto the Traveling
Block in order to suspend the Elevators.
Figure 2-8 Elevator links
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2.5.2 Elevator
Clamps that grip a stand of casing, tubing, drill pipe or drill collars so that the stand or joint
can be raised from or lowered into the hole opening of the rotary table.
2.5.3 Tugger/winch
A pneumatically operated
drum with wire ropes
pooled onto it to move or
lift heavy objects on the
rig floor.
Figure 2-11 Side door elevator Figure 2-10 Center latch elevator Figure 2-9 Single joint elevator
Figure 2-12 Elevator links along with elevator links
Figure 2-13 Tugger/Air winch
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2.5.4 Slips
A wedge shape piece of metal with teeth or other gripping elements that are used to prevent
pipe from slipping down into hole or to hold the pipe in place.
Figure 2-15 Drill pipe slips
Figure 2-16 Drill collar slips
Figure 2-14 Casing slips
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2.5.5 Safety clamp
These are used on tubulars above the slips to prevent dropping the string should the slips fail
to hold.
Figure 2-17 Usage of slips during drilling operation
Figure 2-18 Safety clamps
Figure 2-19 Usage of safety clamp while drilling
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2.5.6 Tong
Large wrenches used to make or break out tubulars.
2.5.7 Drill pipe spinner
A pneumatically operated device usually suspended on the rig floor used to make fast
connections and spin off of drill pipes.
Figure 2-20 Make up and break up tongs
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2.5.8 Iron roughneck
A pneumatically operated machine that replaces the functions performed by the Kelly Spinner,
Drill pipe Spinner and Tongs.
2.5.9 Bit breaker
A device that is placed on top of the rotary table to enable the bit to be made up to drill string.
Figure 2-21 drill pipe spinner
Figure 2-22 Iron roughneck
Figure 2-23 Bit breaker
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3 Chapter 03: Drill bits Rotary drilling uses two types of drill bits: roller-cone bits and fixed-cutter bits. Roller-cone
bits are generally used to drill a wide variety of formations, from very soft to very hard. Milled-
tooth (or steel-tooth) bits are typically used for drilling relatively soft formations. Tungsten
carbide inserts bits (TCI or button bits) are used in a wider range of formations, including the
hardest and most abrasive drilling applications. Fixed-cutter bits, including polycrystalline
diamond compact (PDC), impregnated, and diamond bits, can drill an extensive array of
formations at various depths.
3.1 Roller cone bits
The primary drilling mechanism of the rolling cutter bits is intrusion, which means that the
teeth are forced into the rock by the weight-on-bit, and pulled through the rock by the rotary
action. For this reason, the cones and teeth of rolling cuttings rock bits are made from specially,
case hardened steel. The action of bit cones on a formation is of prime importance in achieving
a desirable penetration rate. Soft-formation bits require a gouging-scraping action. Hard-
formation bits require a chipping-crushing action. These actions are governed primarily by the
degree to which the cones roll and skid. Maximum gouging-scraping (soft-formation) actions
require a significant amount of skid. Conversely, a chipping-crushing (hard-formation) action
requires that cone roll approach a “true roll” condition with very little skidding. For soft
formations, a combination of small journal angle, large offset angle, and significant variation
in cone profile is required to develop the cone action that skids more than it rolls. Hard
formations require a combination of large journal angle, no offset, and minimum variation in
cone profile. These will result in cone action closely approaching true roll with little skidding.
Roller cone bits are of following types;
1. Milled tooth (Steel tooth) bits
Figure 3-1 Roller cone bit
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2. Tungsten carbide inserts (TCI) bits
3.1.1 Milled tooth bits
There are three basic design features incorporated in steel tooth cutting structures, teeth
spacing, tooth hard-facing, and tooth angle (Figure 3-2). Using variations of these parameters,
bits are separated into formation types.
3.1.1.1 Soft formation cutting structure
Teeth on this type of bit are few in number, widely spaced, and placed in a few broad rows.
They tend to be slender, with small tooth angles (39°to 42°). They are dressed with hard metal.
3.1.1.2 Medium formation cutting structure
Teeth on medium formation bits are fairly numerous, with moderate spacing and depth. The
teeth are strong, and are a compromise between hard and soft bits, with tooth angles of 43°to
46°. The inner rows as well as the gauge rows are hard-faced.
3.1.1.3 Hard formation cutting structure
There are many teeth on this type of bit. They are closely spaced and are short and blunt. There
are many narrow rows with tooth angles of 46o to 50o. The inner rows have no hard-facing,
while the gauge row is hard-faced.
Figure 3-2 Tooth cutting structure, teeth spacing and tooth angle of milled tooth bit
Figure 3-3 Milled tooth tricone bit
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3.1.2 Tungsten carbide inserts bits
TCI design takes the properties of tungsten carbide materials and the geometric efficiency for
drilling of a particular rock formation into account. As noted, softer materials require
geometries that are long and sharp to encourage rapid penetration. Impact loads are low, but
abrasive wear can be high. Hard formations are drilled more by a crushing and grinding action
than by penetration. Impact loads and abrasion can be very high. Tough materials, such as
carbonates, are drilled by a gouging action and can sustain high impact loads and high operating
temperatures. Variations in the way that drilling is accomplished and rock formation properties
govern the shape and grade of the correct TCIs to be selected.
3.2 Fixed cutter bits
It’s a fixed -head bits rotate as one piece and contain no separately moving parts. These bits
are classified as follows;
1. Polycrystalline diamond compact (PDC) bits
2. Impregnated bits
3. Diamond bits
3.2.1 Polycrystalline diamond compact (PDC) bits
PDC bits are designed and manufactured in two structurally dissimilar styles: matrix-body bit
and steel-body bits. The two provide significantly different capabilities, and because both types
have certain advantages, a choice between them would be decided by the needs of the
application. "Matrix" is a very hard, rather brittle composite material comprising tungsten
Figure 3-4 Tungsten cribde insert tricone bit
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carbide grains metallurgically bonded with a softer, tougher, metallic binder. Matrix is
desirable as a bit material because its hardness is resistant to abrasion and erosion. It is capable
of withstanding relatively high compressive loads but, compared with steel, has low resistance
to impact loading. Matrix is relatively heterogeneous because it is a composite material.
Because the size and placement of the particles of tungsten carbide it contains vary (by both
design and circumstances), its physical properties are slightly less predictable than steel.
Steel is metallurgically opposite of matrix. It is capable of withstanding high impact loads but
is relatively soft and without protective features would quickly fail by abrasion and erosion.
3.2.1.1 Cutting action
The method in which rock fails is important in bit design and selection. Formation failure
occurs in two modes: brittle failure and plastic failure. The mode in which a formation fails
depends on rock strength, which is a function of composition and such down-hole conditions
as depth, pressure, and temperature. Formation failure can be depicted with stress-strain curves
(Fig. 5.22). Stress, applied force per unit area, can be tensile, compressive, torsional, or shear.
Strain is the deformation caused by the applied force. Under brittle failure, the formation fails
with very little or no deformation. For plastic failure, the formation deforms elastically until it
yields, followed by plastic deformation until rupture. PDC bits drill primarily by shearing.
Vertical penetrating force from applied drill collar weight and horizontal force from the rotary
table are transmitted into the cutters. The resultant force defines a plane of thrust for the cutter.
Cuttings are then sheared off at an initial angle relative to the plane of thrust, which is
dependent on rock strength. Formations that are drillable with PDC bits fail in shear rather than
compressive stress typified by the crushing and gouging action of roller-cone bits. Thus, PDC
bits are designed primarily to drill by shearing. In shear, the energy required to reach plastic
limit for rupture is significantly less than by compressive stress. PDC bits thus require less
WOB than roller-cone bits.
Figure 3-6 Short PDC bit Figure 3-5 Medium PDC bit Figure 3-7 TSP bit
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3.2.2 Impregnated bits
Impregnated bits are a PDC bit type in which diamond cutting elements are fully imbedded
within a PDC bit body matrix. Impregnated bit bodies are PDC matrix materials that are similar
to those used in cutters. The working portions of impregnated bits are unique, however: matrix
impregnated with diamonds. Both natural and synthetic diamonds are prone to breakage from
impact. When embedded in a bit body, they are supported to the greatest extent possible and
are less susceptible to breakage. However, because the largest diamonds are relatively small,
cut depth must be small and ROP must be achieved through increased rotational speed. Thus,
impregnated bits do not perform well in rotary drilling because of relatively low rotary speeds.
They are most frequently run in conjunction with turbodrills and high-speed positive
displacement motors that operate at several times normal rotational velocity for rotary drilling
(500 to1500 rpm). Impregnated bits use combinations of natural diamond, synthetic diamond,
PDC, and TSP for cutting and gauge protection purposes. They are designed to provide
complete diamond coverage of the well bottom with only diamonds touching the formation.
Variations in diamond size and the ratio of diamond to matrix volumes allow optimization of
performance in terms of aggressiveness and durability. Varying diamond distribution also
affects the ratio of diamond to matrix with similar effects on aggressiveness and durability.
3.2.3 Diamond bits
The term "diamond bit" normally refers to bits incorporating surface-set natural diamonds as
cutters. This bit type, which has been used for many years, was the predecessor to PDC bits
and continues to be used in certain drilling environments. Diamond bits are used in abrasive
formations. They drill by a high-speed plowing action that breaks the cementation between
rock grains. Fine cuttings are developed in low volumes per rotation. To achieve satisfactory
ROPs with diamond bits, they must, accordingly, be rotated at high speeds.
Diamond bits are described in terms of the profile of their crown, the size of diamond stones
(stones per carat), and total fluid area incorporated into the design, and fluid course design
(radial or cross flow). Diamonds do not bond with other materials. They are held in place by
partial encapsulation in a matrix bit body. Diamonds are set in place on the drilling surfaces of
bits.
Figure 3-8 Impregnated bit
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Figure 3-9 Diamond bit
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4 Chapter 04: Casing Well casing consists of a series of metal tubes installed in the freshly drilled hole. Casing serves
to strengthen the sides of the well hole, ensure that no oil or natural gas seeps out as it is brought
to the surface, and to keep other fluids or gases from seeping into the formation through the
well.
Casings are of following five types;
1. Conductor casing
2. Surface casing
3. Intermediate casing
4. Production casing
5. Liner
4.1 Conductor casing
Conductor casing, which is usually no more than 20 to 50 feet (7-17 meter) long, is being
installed before main drilling to prevent the top of the well from caving in and to help in the
process of circulating the drilling fluid up from the bottom of the well.
4.2 Surface casing
Surface casing is the next type of casing to be installed. It can be anywhere from 100 to 400
meters long, and is smaller in diameter to fit inside the conductor casing. Its primary purpose
is to protect fresh water deposits near the surface of the well from being contaminated by
leaking hydrocarbons or salt water from deeper underground. It also serves as a conduit for
drilling mud returning to the surface and helps protect the drill hole from being damaged during
drilling.
4.3 Intermediate casing
Intermediate casing is usually the longest section of casing found in a well. Its primary purpose
is to minimize the hazards associated with subsurface formations that may affect the well.
These include abnormal underground pressure zones, underground shales and formations that
might otherwise contaminate the well, such as underground salt water deposits. Liner strings
are sometimes used instead of intermediate casing. Liner strings are usually just attached to the
previous casing with 'hangers', instead of being cemented into place and are thus less
permanent.
4.4 Production casing
Production casing, alternatively called the 'oil string' or 'long string', is installed last and is the
deepest section of casing in a well. This is the casing that provides a conduit from the surface
of the well to the petroleum producing formation. The size of the production casing depends
on a number of considerations, including the lifting equipment to be used, the number of
completions required, and the possibility of deepening the well at a later date. For example, if
it is expected that the well will be deepened later, then the production casing must be wide
enough to allow the passage of a drill bit later on. It is also instrumental in preventing blow-
outs, allowing the formation to be 'sealed' from the top should dangerous pressure levels be
reached.
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4.5 Liner
A liner is a string of casing that does not reach the surface. They are usually “hung” (attached
to the intermediate casing using an arrangement of packers and slips) from the base of the
intermediate casing and reach to the bottom of the hole. The major advantage of a liner is the
cost of the string is reduced, as are running and cementing times. During the course of the well,
if the liner has to be extended to the surface (making it another string of casing), the string
attaching the liner to the surface is known as a “tie-back” string.
Figure 4-1 Casings
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5 Chapter 05: Cementing Oil well cementing is the process of mixing and displacing a slurry down the casing and up the
annulus, behind the casing, where is allowed to “set”, thus bonding the casing to the formation.
Some additional functions of cementing include:
1. Protecting producing formations
2. Providing support for the casing
3. Protecting the casing from corrosion
4. Sealing off troublesome zones
5. Protecting the borehole in the event of problems
The main ingredient in most cements is “Portland” cement, a mixture of limestone and clay.
5.1 Cement additives
5.1.1 Accelerators
An accelerator is a chemical additive used to speed up the normal rate of reaction between
cement and water which shortens the thickening time of the cement, increase the early strength
of cement, and saves time on the drilling rig. Cement slurries used opposite shallow, low-
temperature formations require accelerators to shorten the time for "waiting-on cement". Most
operators wait on cement to reach a minimum compressive strength of 500 psi before resuming
drilling operations. When using accelerators, this strength can be developed in 4 hours. It is a
good practice to use accelerators with basic cements because at temperatures below 100oF, neat
cement may require 1 or 2 days to develop a 500 psi compressive strength. Common
accelerators are sodium metasilicate, sodium chloride, sea water, anhydrous calcium chloride,
potassium chloride and gypsum.
5.1.2 Retarders
Neat cement slurries set quickly at a BHT greater than 110oF. A retarder is an additive used to
increase the thickening time of cements. Besides extending the pumping time of cements, most
retarders affect the viscosity to some degree. The governing factors for the use of retarders are
temperature and depth.
Common retarders are lignosulfonates, modified cellulose, organic acids, organic materials and
borax.
5.1.3 Extenders
Extended cement slurries are used to reduce the hydrostatic pressure on weak formations and
to decrease the cost of slurries. Extenders work by allowing the addition of more water to the
slurry to lighten the mixture and to keep the solids from separating. These additives change the
thickening times, compressive strengths and water loss.
Common extenders are fly ash, bentonite, and diatomaceous earth.
5.1.4 Pozzolans
Pozzolans are natural or artificial siliceous materials added to Portland cement to reduce slurry
density and viscosity. The material may be either a volcanic ash or a clay high in silica. The
silica in the pozzolans combines with the free lime in dry cement, which means a soluble
constituent is removed from the cement and the new cement is made more resistive. Common
pozzolans are diatomaceous earth and fly ash.
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5.2 Chemical wash
Before releasing the bottom plug chemical washes are pumped. Chemical washes are fluids
containing surfactants and mud thinners, designed to thin and disperse the drilling fluid so that
it can be removed from the casing and borehole. Washes are available for water-based and oil-
based drilling fluids. They are designed to be used in turbulent flow conditions.
5.3 Spacer
Along with chemical washes, spacer is also pumped down the whole. Spacers are fluids of
controlled viscosity, density and gel strength used to form a buffer between the cement and
drilling fluid. They also help in the removal of drilling fluid during cementing.
5.4 Cement slurry
Water is added to dry cement along with additives to cause hydration and to make a pumpable
slurry. To be used correctly, several properties must be known: the yield per unit (cubic feet
per sack), the amount of water required (gallons per sack), and its density (pounds per gallon).
Another important parameter is the cements “absolute volume”. This is the actual volume
occupied by the material (the bulk volume includes the open spaces between the cement
particles). With dry materials (cement and additives), the absolute volume is used along with
the water requirements to determine the slurry.
5.5 Cement classification
The American Petroleum Institute (API) has established a classification system for the various
types of cements, which must meet specified chemical and physical requirements. Table 2-3
lists nine classifications and their applications to depths of 16,000 ft. (4880 m), under various
temperature and pressure conditions.
API Class Application
A 1. Used at depth ranges of 0 to 6000 ft.
2. Used at temperature up to 170 oF.
3. Used when well conditions permit.
4. Economical when compared to premium cement.
B 1. Used at depth ranges of 0 to 6000 ft.
2. Used at temperature up to 170 oF.
3. Used when moderate to high sulphate resistance is required.
4. Used when well conditions permit.
5. Economical when compared to premium cement.
C 1. Used at depth ranges of 0 to 6000 ft.
2. Used at temperature up to 170 oF.
3. Used when high early-strength is required.
4. Used when its special properties are required.
5. It is high in tricalcium silicate.
D,E 1. Class D used at depths from 6000 to 10000 ft. and at temperatures from
170 - 260oF.
2. Class E used at depth from 10000 to 14000 ft. and at temperatures from
170 - 290oF.
3. Both used at moderately high temperatures and high pressures.
4. Both available in types that exhibit regular and high resistance to
sulfate.
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5. Both are retarded with an organic compound, chemical composition and
grind.
6. Both are more expensive than Portland cement.
F 1. Used at depth ranges of 10000 to 16000 ft.
2. Used at temperatures from 230 - 320oF.
3. Used when extremely high temperatures and pressures are encountered.
4. Available in types that exhibit moderate and high resistance to sulfate.
5. Retarded with an organic additive, chemical composition and grind.
G,H 1. Used at depth ranges from 0 to 8000 ft.
2. Used at temperatures up to 200oF without modifiers.
3. A basic cement compatible with accelerators or retarders.
4. Usable over the complete ranges of A to E with additives.
5. Additives can be blended at bulk station or at well site.
6. Class H is a coarser grind than Class G.
J 1. Used at depth ranges from 12000 to 16000 ft.
2. Used for conditions of extreme temperature and pressure: 170 - 320oF
(unmodified).
3. Usable with accelerators and retarders.
4. Will not set at temperatures less than 150oF when used as a neat slurry.
5.6 Cementing procedure
In a jet mixing hopper, the dry cement along is gradually added to the hopper, and a compressed
air thoroughly transfers the cement through cementing cylo to make a slurry (very thin water
cement having additives) in agitator. The dry cement after passing through cementing cylo,
which serves as a reservoir for cement, enters the agitator. Agitator serves as to achieve the
proper mixing of additives in order to make slurry required for a specific cementing job. Special
pumps pick up the cement slurry and send it up to a valve called a cementing head (also called
a plug container) mounted on the topmost joint of casing that is hanging in the mast or derrick
a little above the rig floor. Just before the cement slurry arrives, a rubber plug (called the bottom
plug) is released from the cementing head and precedes the slurry down the inside of the casing.
The bottom plug stops or "seats" in the float collar, but continued pressure from the cement
pumps open a passageway through the bottom plug. Thus, the cement slurry passes through the
bottom plug and continues on down the casing. The slurry then flows out through the opening
in the guide shoe and starts up the annular space between the outside of the casing and wall of
the hole. Pumping continues and the cement slurry fills the annular space. A top plug, which is
similar to the bottom plug except that it is solid, is released as the last of the cement slurry
enters the casing. The top plug follows the remaining slurry down the casing as a displacement
fluid (usually salt water or drilling mud) is pumped in behind the top plug. Meanwhile, most
of the cement slurry flows out of the casing and into the annular space. By the time the top plug
seats on or "bumps" the bottom plug in the float collar, which signals the cementing pump
operator to shut down the pumps, the cement is only in the casing below the float collar and in
the annular space. Most of the casing is full of displacement fluid. After the cement is run,
a waiting time is allotted to allow the slurry to harden. This period of time is referred to as
waiting on cement or simply WOC.
After the cement hardens, tests may be run to ensure a good cement job, usually cement bond
log and variable density log is enough to make sure a good cement job.
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6 Chapter 06: Perforations and testing
6.1 Perforations
Since the pay zone is sealed off by the production string and cement, perforations must be made
in order for the oil or gas to flow into the wellbore. Perforations are simply holes that are made
through the casing and cement and extend some distance into the formation.
6.2 Perforation methods
1. Bullet perforation
2. Jet perforation
6.2.1 Bullet perforation
In bullet perforation small guns lowered into the well that sent off small bullets to penetrate the
casing and cement.
6.2.2 Jet perforation
This consists of small, electrically-fired charges that are lowered into the well. When ignited,
these charges poke tiny holes through to the formation, in the same manner as bullet
perforating.
6.3 Perforation equipment
6.3.1 Guns/ carriers
In shaped-charge perforators, there are two basic carriers:
1. Retrievable hollow carrier
2. Expendable or semiexpendable carrier
6.3.2 Thick walled gun
On the larger diameter, thick-walled guns, there is much less distortion than on the small, thin-
walled through-tubing guns. In wells in which clearances between the gun and tubulars are
critical, the amount of distortion of the gun should be determined from the service company
before the gun is used. Gun body swell ranges from approximately 10% diameter growth in
small, 1 11∕16 -in. guns shot in low pressure wells to less than 1% diameter growth in larger
guns and those shot at high pressure. Gun bowing is often noted in small guns of 2 1/8 in.
diameter or less, whereas larger guns, because of the increased resistance to bending with
increasing diameter, show no evidence of bowing.
6.3.3 Hollow-carrier guns
Hollow-carrier guns can be run either on wireline or on tubing. They may carry large charges,
which normally minimize casing damage. The carrier contains most of the debris from the
charge and the alignment system. Hollow-carrier guns are tubes that contain the shaped
charges. The guns may be of a small size, able to pass through tubing and restrictions and place
initial perforations or add perforations, or of larger sizes that are run through casing, conveyed
by either work strings or the production tubing. Both reusable and single-use guns are offered,
although higher pressure and more expensive wells typically use the single-use guns to
minimize leaks and problems. Single-use guns are designed as expendables because the shaped
charge perforates through the gun body. There is usually a “scallop” spot milled in the outside
of the hollow-carrier tube at the charge location. The scallop contains the exit burr from the
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charge firing, which prevents scoring of polished bores if the gun is moved after firing and may
minimize gun swelling. The scallop also may minimize the metal thickness penetrated,
although this affects the perforation charge performance less than 10%. Keeping the charge
exit point within the scallop becomes critical when through-tubing guns are used in which
polished bores must be traversed with the gun after firing or when tubing clearances are critical.
Hollow-carrier guns, depending on their diameter and design, may be loaded with 1 to 27
shots/ft and have all the commonly used phase angles as well as specialty phasings.
6.3.4 Through-tubing guns
The smaller through-tubing guns should be run through a lubricator and typically are limited
to approximately 40 ft in length, less for larger, heavier guns. The advantages of through-tubing
guns are low cost, the ability to perforate underbalanced, and the ability to maintain positive
well control. The disadvantages of through-tubing guns are limited penetration, small entry
hole, and the production limitation of 0° phasing.
6.3.5 Expendable guns
Expendable guns have charges that are exposed to well fluids and pressures. The expendable
guns are popular for through-tubing applications. They are more vulnerable to damage, but
without the bulk of the gun body, larger charges can be run through any given small or buckled
tubing restriction. The expendable and semi-expendable carriers normally can use a larger
charge for a given tubing or casing size than the hollow-carrier guns because only the skin of
the capsule around each charge separates it from the walls of the casing. With expendable guns,
there is also more flexibility because some bending can be achieved. The expendable guns are
popular for through-tubing applications. The charges are lined together by a common strip,
wire/cable, or a linked body design. The expendable guns force the casing to endure a much
higher explosive load during firing because the recoil is not contained in a sacrificial shell as
in a hollow-carrier gun. Casing splits are sometimes seen with a downhole television camera
after perforating with expendable guns in cased holes with poor cement or low-strength casing.
Expendable guns are used because their perforating performance is significantly better than
hollow-carrier guns in the smaller diameters. When the gun is fired, some or all the linking
materials, as well as the charge capsule remnants, are left in the hole. Problems with these guns
have centered on:
1. Misfires from damage to the detonating cord.
2. Tubing and surface line plugging from debris.
3. Carrier strip disintegration or severe bending after firing.
6.3.6 Detonator system
Once on depth, charges are fired by an initiator or detonator. Detonator systems have been
redesigned in recent years to improve safety and to prevent several perforating problems that
occur from leaks, pressure problems, and temperature effects. Any wireline-conveyed, hollow-
carrier gun should have a detonator system that will not allow the charges to fire if the gun is
completely or partially filled with water. If a water-filled hollow-carrier gun is fired, the outer
body shell may rupture and result in a fishing or milling job. Specialized detonators have
methods of preventing wet (fluid-filled) gun firing, as well as offering a number of other safety
benefits ranging from resisting stray currents, such as static and radio energy, to pressure
switches that prevent accidental surface firing or re-safe the gun when a live gun is pulled from
a well. The standard explosives detonator (also called a blasting cap) is a mainstay of the
construction industry but is not well suited to the petroleum industry. Several accidental
discharges of perforating guns have been linked directly to stray currents or poor electrical
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panel operational procedures. The resistor detonator incorporates resistors that reduce the
possibility of discharge from low-power electrical signals. More modern detonators are
available, including:
1. Flying foil
2. Programmable chips
3. Other units that are radio safe and allow for extra safety
6.4 Conveyance system
The conveyance system for the perforating gun may be:
1. Wireline
2. Tubing
3. Coiled tubing
4. Pumpdown
5. Slickline
6.5 Drill stem test
It’s a procedure to determine the productive capacity, pressure, permeability or extent (or a
combination of these) of a hydrocarbon reservoir. While several different proprietary hardware
sets are available to accomplish this, the common idea is to isolate the zone of interest with
temporary packers. Next, one or more valves are opened to produce the reservoir fluids through
the drill-pipe and allow the well to flow for a time. Finally, the operator kills the well, closes
the valves, removes the packers and trips the tools out of the hole. Depending on the
requirements and goals for the test, it may be of short (one hour or less) or long (several days
or weeks) duration and there might be more than one flow period and pressure buildup period.
6.6 DST tools
6.6.1 Mule shoe
If the test is being conducted in a liner the mule shoe makes it easier to enter the liner top. The
beveled mule shoe also facilities pulling wireline tools back into the test string. If testing with
a permanent packer, the mule shoe allows entry into the packer bore.
6.6.2 Retrievable packer
The packer isolates the interval to be tested from the fluid in the annulus. It should be set by
turning to the right and includes a hydraulic hold-down mechanism to prevent the tool from
being pumped up the hole under the influence of differential pressure from below the packer.
Packer offsets the mud weight of annulus on formation in order to make sure the flow of
reservoir fluid.
6.6.3 Safety joint
Installed above a retrievable packer, it allows the test string above this tool to be recovered in
the event the packer becomes stuck in the hole. It operates by manipulating the string (usually
a combination of reciprocation and rotation) to unscrew and the upper part of the string
retrieved. The DST tools can then be laid out and the upper part of the safety joint run back in
the hole with fishing jar to allow more powerful jarring action.
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6.6.4 Hydraulic jar
The jar is run to aid in freeing the packer if it becomes stuck. The jar allows an over pull to be
taken on the string which is then suddenly released, delivering an impact to the stuck tools.
6.6.5 Hydraulic circulating valve (Bypass valve)
This tool is run in conjunction with retrievable packers to allow fluid bypass while running in
and pulling out of hole, hence reducing the risk of excessive pressure surges or swabbing. It
can also be used to equalize differential pressures across packers at the end of the test. It is
automatically closed when sufficient weight is set down on the packer. This valve should
ideally contain a time delay on closing, to prevent pressuring up of the closed sump below the
packer during packer setting. This feature is important when running tubing conveyed
perforating guns which are actuated by pressure. If the valve does not have a delay on closing,
a large incremental pressure, rather than the static bottom-hole pressure, should be chosen for
firing the guns.
6.6.6 Gauge carrier
The carrier allows pressure and temperature recorders to be run below or above the packer in
order to sense either annulus or tubing pressures along with temperatures.
6.6.7 Down-hole tester valve
The down-hole tester valve provides a seal from pressure from above and below. The valve is
operated by pressuring up on the annulus. The down-hole tester valve allows down-hole shut
in of the well so that after-flow effects are minimized, providing better pressure data. It also
has a secondary function as a safety valve.
Usually a low pressure response nitrogen (LPRN) tester valve is used in drill stem test. LPRN
tester valve, basically a ball valve, is operated by applying pressure through annulus. The
pressure through annulus compresses the nitrogen and the resulting pressurized nitrogen moves
the ball in order to open tester valve.
6.6.8 Rupture disc circulating valve
This ball valve is used to terminate the drill stem test. The high pressure is applied through the
annulus which breaks the rupture disc in order to open the valve. By doing so communication
with annulus is established and after that with the increase of mud weight the formation fluid
is sent back down to reservoir (bull heading).
6.6.9 Slip joint
The Slip Joint is an expansion/contraction compensating tool that accommodates for changes
in string length caused by temperature and pressure changes during a drillstem test.
6.6.9.1 Operation
The Slip Joint has two distinct parts: an outer housing and a moving inner mandrel. Its rugged
design incorporates three main sections. At the top is a splined moving mandrel that allows
torque to be transmitted through the tool. Below this are two pressure chambers, one open to
tubing pressure and the other open to annulus pressure. The tool is hydraulically balanced and
insensitive to applied tubing pressures due to dynamic seals and balance chambers.
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6.6.10 Flow head
It consists of two wing valves i.e production wing valve and kill wing valve, swab valve and
master valve. In DST while flowing the flow is diverted through different chokes using
production wing valve. Whereas kill wing valve is used for direct circulation during well
killing.
6.7 Testing procedure of DST
Testing procedure requires the opening of a section of the borehole to atmospheric or reduced
pressure. The testing string is lowered into the hole on a drill pipe with tester valve closed to
prevent entry of well fluid into the drill pipe, leading to an undesired fishing job and possibly
a stuck drill pipe. The testing procedure can be summarized as follows:
Figure 6-1 Slip joint
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While going in a hole, the packer is collapsed, allowing the displaced mud to rise.
After the drill stem reaches the bottom, and the necessary preparations are completed, the
packer is then set (compressed and expanded) and isolates the lower zone (desired zone) from
rest of the open hole. In other words packer provides a seal above the zone to be tested.
The bypass is closed as the tester valve is opened, here, the packer supports the hydrostatic
pressure load of the well fluid, and the isolated section is exposed through the open tester valve
to the low pressure inside the empty or nearly empty drill pipe, allowing the formation fluid to
enter and the flowing formation pressure can be measured during the flow period.
At the end of the test, the tester valve is closed, trapping any fluid above it and this makes
possible the measurement of static formation’s built up in-pressure (Close-in period).
After the final close-in period the bypass valve is opened in order to equalize the pressure
across the packer.
Formation fluid received during the test can be removed from the drill pipe by reverse
circulation before the pipe is removed from borehole. This reversal is performed by closing the
blowout preventers and pumping mud down the annulus; the mud then enters drill pipe through
the reversing ports, thereby displacing any formation fluids in the pipe.
Finally, the setting weight is taken off and the packer is pulled free. The fluid content of each
successive pipe section is examined when it is removed. The graphic charts are absolutely
essential to get the accurate interpretation of test result.
Figure 6-2 DST tool
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6.8 Well killing
Before unsetting of packer and pulling out of drill string of DST, we perform well killing in
order to put the well in static condition.
6.8.1 Well killing procedure
First close the LPRN-tester valve by releasing the pressure in the annulus then gas pressure in
drill string is released via relief valve, during this separator valves are closed. After this pump
the mud of desired specific gravity through kill wing valve of flow head. Now open the LPRN-
tester valve and start bull heading of mud in order to put the formation fluid back into the
formation. After this kill wing valve is closed and rupture disc is ruptured through annulus
respectively. Now perform the reverse circulation until mud weight in and out are balanced and
check the well for a period of 20 minutes. After that flush the surface testing lines with fresh
water & disconnect upstream line of choke manifold. Now open the pipe rams and connect the
rig pump with flow head kill wing valve. Pull the string in order to unset the packer and start
direct circulation. At the end of direct circulation if the hole static then well is killed.
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7 Chapter 07: Well completion Well completion commonly refers to the process of finishing a well so that it is ready to produce
oil or natural gas. In essence, completion consists of deciding on the characteristics of the intake
portion of the well in the targeted hydrocarbon formation. Therefore completion is defined as
“the design, selection and installation of equipment and the specification of treatment and
procedures necessary to bring the well into production and thereafter to produce in a manner
which satisfies the operator’s objectives for the field development”.
Oil and gas well completions can be divided into two main categories: open hole well
completions, and the case-hole completions.
7.1 Open hole completion
In open hole completions the pay rock is kept as it is, and no cemented casing columns are
needed. This type of completion is realized when the formation is self-supporting or when, on
the contrary, it is too severely fractured to guarantee successful cementation. It is the optimal
solution since the entire drainage surface is available for production, and pressure drops are
limited. Moreover, the absence of casing columns makes it easier to proceed to well
stimulation. On the other hand, in open hole completions it is impossible to control the entrance
of sand and water in the hole, and it is therefore very difficult to isolate the levels and proceed
to their stabilization.
7.2 Cased hole completion
Case-hole completions are more widely used due to technical reasons
relating to the stability of the hole. In this case the well to be completed
is one that has been lined and cemented throughout its entire
development. In order to make production possible, it is necessary to re-
establish hydraulic communication between the pay rock and the hole.
This operation involves drilling the lining, the cementation and the pay
rock.
There are four possible solutions to establish communication between
the productive formation and the surface:
1. Tubing-less completion
2. Packer-less completion (with a tubing string and without
isolation between casing and tubing)
3. Single string with hydraulic isolation completion
4. Multiple string completion.
7.2.1 Tubing-less completion
The tubingless completion method is used in wells where the pay rock
pressure is low and high flow rates are required. In this case production
must take place directly through the final lining of the well, with no
support from production strings or isolation systems.
7.2.2 Packer-less completion
Packer-less completion is a more financially advantageous system. Here,
only the production tubing is placed in the well, and it is possible to
produce both through it and through the annulus. The production tubing Figure 7-1 Packerless completion
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can be used for injecting inhibitors or killing fluid. This method is somewhat limited in terms
of flow conditions and the protection of the tubing materials. Moreover, it is difficult to detect
leaks in the tubing or the casing, and to gather bottom-hole pressure data.
7.2.3 Single string with hydraulic isolation completion
The single string completion using hydraulic isolation and just one string is convenient when
the production layer appears to be homogeneous and a selective-zone production is not
necessary. It consists in the use of a single tubing string that is lowered into the well together
with an isolation device for the formation section to be produced, called the packer.
Where there are several production layers for one fluid, a single selective completion is used.
This system has only one tubing string and several packers that isolate the various production
levels. By using wire-line operations it is possible to open and close the valves so as to allow
production on single layers.
7.2.4 Multiple tubing string completion
The multiple tubing string completion uses, at the most, two or three tubings, isolated by
packers and producing on different levels at the same time. This solution is useful when the
reservoir presents different layers of mineralization, for example gas and oil, or different types
of oil, because it allows us to produce selectively according to necessity, while keeping
Figure 7-4 Single string packer completion
Figure 7-2 Selective single string completion
Figure 7-3 Dual string completion
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production active on various levels at the same time. For the single tubing strings, it is always
possible to adopt a solution similar to the single selective completion, thus obtaining a multiple
selective completion. This system’s drawback is the limited diameter of the tubing which in
turn reduces the flow capacity of each tubing string.
7.3 Completion equipment
7.3.1 Tubular equipment
The main element in completion is the tubing, which is the network of pipes which connect the
area of the reservoir selected for production to the surface. The pipes are made of non-welded
stainless steel, and are classified according to length, diameter, type of steel, weight, thickness,
and according to the type of thread and joint. An alternative to the use of strings of pipes
connected by joints is the use of so-called coiled tubing, which consists in a steel pipe coil
around a drum that is introduced into the well by means of a special tool. This method is
economically convenient because it allows us to get a completion working in very little time,
and to dismantle it very rapidly. Coiled tubing can also be re-used in other completion plants.
It is generally used in temporary completions to carry out long-term well tests, or where the
use of a jointed tubing system would present serious problems.
Special elements are added to the tubular units that make up the production string. These are
needed to carry out specific local functions, and include flow couplings, blast joints, landing
nipples, circulation devices and travel joints.
7.3.2 Flow couplings
Flow couplings are short pipes which are thicker than the tubing. They are used near devices
that are liable to produce high turbulence within the tubing, in order to delay possible damage
due to erosion. The flow couplings are generally twice as thick as the tubing, for an equal
internal diameter, and are usually used with the landing nipples or the circulation devices.
7.3.3 Blast joints
The blast joints also serve to prolong the completion’s life span by protecting it from the erosive
flow which comes into the well via the production string. They have a similar internal diameter
to the tubing, but their external diameter is larger.
7.3.4 Circulating devices
Circulation devices are used to put the inside of the production string in communication with
the annulus tubing-casing. This communication is required to circulate a fluid in the well, to
treat the well with chemical products or to inject fluids into the tubing through the annulus.
There are two different devices for doing this: sliding sleeves and side pocket mandrels.
7.3.5 Sliding sleeve
A sliding sleeve is a cylindrical device with an internal sliding mechanism, or sleeve. Both the
sleeve and the outer cylinder are perforated so as to provide coupled openings, and the sleeve
is moved up and down by a wire-line tool. When the sleeve is brought into the open position,
the relative opening is in line with the opening in the outer cylinder, and allows communication
between the tubing and the casing. The sliding sleeves are usually positioned either above the
uppermost packer in order to carry out circulation and pressure-balancing operations in the
well, or between two packers to allow for selective production on multilevel reservoirs.
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7.3.6 Side pocket mandrels
The side pocket mandrels are special devices that present a chamber parallel to the flow
chamber, in which it is possible to fix devices and connect the annulus to the inside of the string
without occupying the flow diameter. Their main utility is that of providing seats for gas-lift
valves, but they can also be put to a different use: as a means for circulating fluids, and as an
emergency device for well killing. In this case, a valve is installed, which will only open if
there is major external pressure on the tubing, thus allowing the entrance of a fluid.
7.3.7 Expansion joints
One very important element is the expansion joint, usually referred to as the travel joint. These
joints absorb the motion of the production tubing which is due to variations in pressure and
temperature. A travel joint is composed of two concentric tubes fitting into one another, and
hydraulic seal units, which are placed in the internal tube to isolate the annulus between the
two elements during the joint excursion. Travel joints are usually installed above the uppermost
packer, to contain the tubing motion which is otherwise difficult to compensate.
7.3.8 Landing nipples
The landing nipples are thick stub pipes, turned on the inside to create blocking profiles and
landing seats. These joints serve to provide landing seats for flow control devices. Other joints
are used to land removable safety valves. In this case the landing nipples can differ from the
standard joints by presenting a hydraulic control line.
7.3.9 Wellhead couplings
The production string is connected to the wellhead by means of a series of elements that form
the wellhead completion. These are the tubing spool, the tubing hanger, and the Christmas tree.
The tubing spool serves to hold up the production string and to connect, at the bottom, the
casing heads and, at the top, the Christmas tree. The tubing spool includes two lateral openings
that allow annulus control between production tubing and production casing.
The tubing hanger is needed to support the tubing and to establish the annulus seal. The annulus
is positioned in the tubing spool, and the production tubing is screwed on to it. An external
gasket guarantees the seal between the production casing and the tubing. The Christmas tree is
located above the tubing spool. Its function is to consent production regulation, and to create
safe conditions for workover operations inside the well. The Christmas tree is composed of two
main gate valves, called the master valves, which enable the well to be closed. Above these a
crossover connection is installed. Wing valves, which are fixed to the lateral flanges, are used
both for production and for possible workover jobs in the well. On the upper flange there is yet
another valve, similar to a master valve, and a crowning flange that is used to install the
workover equipment without having to stop the flow. The absolute pressure gauge is installed
on the crowning flange in correspondence with the wellhead.
7.4 Completion procedure
Completion involves running of shear sub having a seat in which ball sits, landing nipple,
packer, tubing joints, tubing hanger and installation of Christmas tree. During completion we
first run shear sub, landing nipple, packer and then tubing joints. After running the tubing brine
is used to displace the mud. Circulation of brine continues until the brine weight is balanced
i.e brine weight in is equal to brine weight out. After this tubing hanger is set in tubing head
spool via landing joint. Now ball is being dropped in order to set the packer. After setting the
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packer, back pressure valve is installed and at the same time ram blowout preventer is nipple
down. After this Christmas tree is rig up in order to make the well ready for acid job.
Landing nipple is used as a secondary pressure holding device if the ball fails to sit in shear
sub’s seat. Landing nipple holds the pressure as well as provides seal through plug.
7.5 Acid job
Acid job is performed in order to allow the well to flow at its full potential. The main chemical
agents used in acid job are following:
7.5.1 Silt and particle removal acid system
It comprises on surfactant, suspending (chelating) agent, acid corrosion inhibitor and water.
SRA allows the maximum removal and flow back of mud and suspended particles.
7.5.2 Surfactant
It basically decreases the surface tension of the formation fluid and change the wet ability from
oil wet to water wet.
7.5.3 Suspending agent
Suspending or chelating agent, as the name indicates, suspends the iron (Fe3+) or particles so
that there precipitation can be avoided, which if not done properly, can produce the hindrance
against the formation fluid and ultimately lead to decrease in production.
7.5.4 Corrosion inhibitor
Corrosion inhibitor serves as to avoid the corrosion in coil tubing and tubulars.
Figure 7-5 Wellhead and Christmas tree
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7.5.5 Acid
Acid is used to react with formation so that it can clear the perforations by dissolve the particles
in order to facilitate the well to flow at its maximum potential.
7.5.6 Surfactant base KCL brine
It is used for pre and post flush. It contains potassium chloride, surfactant and water.
7.5.7 Potassium chloride
Potassium chloride is used to avoid damage and swelling otherwise blockage will be produced
which ultimately leads to decrease in production.
7.5.8 KCL brine for displacement and trickling
KCL brine is used for wash out of fluids used in pre and post flush. In addition to that it is used
to remove the tiny particles in the well for cleaning purposes. KCL brine consists of Potassium
chloride and water.
7.6 Acid job procedure
Acid job consists of the following three steps.
7.6.1 Perforation wash
Before performing an acid job through coil tubing unit, conduct pressure test of coil-tubing
stack and then start run in hole, with proper bottom hole assembly, while trickling KCL brine.
KCL brine consist of KCl, surfactant and water such that the mixture having a 4% by volume
KCL. After reaching at top of perforations, commence perforation wash with silt and particle
removal acid system (SRA) in nitrified mode. After doing so displace out SRA by pumping
4% KCL brine to coil-tubing volume. After performing the whole procedure pull coil-tubing
unit above packer depth and continue pumping nitrogen until all the treatment fluids are out of
well.
7.6.2 Main treatment
When the perforation wash fluid is out of the well, close the well and let the well head pressure
(WHP) to stabilize. Then run in hole coiled tubing to the top of perforations and perform half
coil-tubing cycle while pumping half the volume of surfactant based 4% by volume KCL brine,
prepared for main treatment, in nitrified mode through coiled tubing. Now pump SRA,
prepared for main treatment, in nitrified mode while reciprocating coiled tubing against the
perforation interval.
7.6.3 Post flush
Station coiled tubing at the top of perforation interval and pump remaining half volume of
surfactant based brine in nitrified mode as post flush and displace the post flush with 4% KCL
brine equal to coiled tubing volume in nitrified mode. Now stop pumping in order to give
soaking time and then open the well towards flare pit so that the flowing parameters can be
established. If the well shows stabilized behavior then keep monitoring it till pH gets normal.
After that pull out of hole coiled tubing. But if the well quits to flow at any time then run in
hole and kick off the well with nitrogen till it indicates a stabilized behavior.
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8 Chapter 08: Well logging Logging is a general term which means to make a record of something. Well logging means
continuous recording of a physical parameter of the formation with depth. The primary
objectives of the wire line logging are
1. The identification of reservoir
2. The estimation of hydrocarbon in place.
3. The estimation of recoverable hydrocarbon
Well logs are results of several geophysical measurements recorded in a well bore.
They consist of key information about formation drilled i.e
1. To identify the productive zones of hydrocarbon.
2. To define the petro-physical parameters like porosity, permeability, hydrocarbon
saturation and lithology of zones.
3. To determine depth, thickness, formation temperature and pressure of a reservoir.
4. To distinguish between oil, gas and water zones in a reservoir.
5. To measure hydrocarbon mobility.
8.1 Logging operation procedure
Type of Logging operations to be carried out at various rigs is decided based on the requirement
of the well. These jobs are carried out by truck mounted logging units these units are placed in
front of catwalk of the rig. The logging tools are lowered in to the well with the help of logging
cable. For lowering the tools with logging cable two sheaves are used. The bottom sheave is
tied with derrick floor and placed near the well mouth and the top sheave is hung to the traveling
block so that the tools are lowered into the well. The tools are assembled and connected to
logging cable through a rope socket on the catwalk and tested/calibrated prior to lowering into
the well. The tool is lowered to the desired depth and data is acquired while the tool is pulled
up. After completing the survey the Tool is pulled out and rig down process is initiated.
8.2 Resistivity logs
The resistivity of a substance is its ability to impede the flow of electric current through the
substance. Formation resistivity usually fall in the range from 0.2 to 1000 ohm meter.
Resistivities higher than 1000 ohm-m are uncommon in permeable formations. In a formation
containing oil or gas, both of which are electrical insulators resistivity is a function of formation
factor, brine resistivity and water saturation which in term depends on true resistivity. Of the
formation parameters resistivity is of particular importance because it is essential for saturation
determination mainly of the hydrocarbon. Depending upon the environment under which
resistivity logs are recorded. There are two types of resistivity Logs. They are Latero logs and
Induction logs.
8.2.1 Dual lateral log
The dual lateral log has been one of primary resistivity measurement device. DLL is a focused
electrode device designed to minimize influence from borehole fluids and adjacent formations.
The DLL consists of an electronics section and a mandrel section. The mandrel supports the
electrodes which are connected to the electronic circuitry. The measurement current emitted
from center electrode is forced to flow laterally into the formation by the focusing action of
electrodes surrounding the center electrode. It provides two measurements of the subsurface
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resistivity simultaneously. The two measurements have differing depth of investigation are
called deep resistivity (Rd) and shallow resistivity (Rs).
8.2.1.1 Theory
DLL consist of a current emitting center electrode positioned between guard electrodes. A
known current is passed through the current electrode with a return electrode at the surface.
Simultaneously a potential is applied to the focused electrode to keep zero potential difference
between guard and center electrode thereby the current is focused into the formation. Thus the
potential difference produced is equivalent to the formation resistivity. The lateral log current
path is basically a series circuit consisting of the drilling fluid, Mud cake, flushed zone, invaded
zone and the virgin zone, with the largest voltage drop occurring over the highest resistance
zone. The total amount of current emanating from an electrode must flow through any medium
that encompasses the electrode. The depth of investigation of a lateral log is defined as the
depth at which 50% of the total measured voltage is dropped.
8.2.2 Micro spherically focused log
Current from a measure electrode is forced into the flushed zone by guard electrodes to the
return electrode. The current to the measure electrode is measured as is the voltage with respect
to the ground.
The MLL is a single tool contains an arm with the pad attached. The central electrode is the
measure electrode. The eight other electrodes are guard electrodes.
8.2.3 Induction logging
Induction tools are based on principles of electromagnetic induction. A magnetic field is
generated by an AC electrical current flowing in a continuous loop/transmitter coil. The
magnetic field from the transmitter coil induces ground loop currents in the formation. These
ground current loops will in turn have an associated alternating magnetic field which will
induce a voltage in the receiver coil, the magnitude of which is proportional to the formation
conductivity.
1. It works in oil based muds and air filled holes where latero tool fails.
2. Tool accuracy is excellent for formations having low to moderate resistivity (up to 100
ohm-m).
3. The Dual Induction Latero (DIL) tool records three resistivity curves having different
depths of investigation.
Applications of resistivity logs
1. True formation resistivity and flushed zone resistivity.
2. Mud filtrate Invasion profile.
3. Quick look hydrocarbon detection.
4. Indication of producible hydrocarbon.
5. Correlation of different formations.
8.3 Porosity log
Porosity values can be obtained from sonic log, a formation density log or a neutron log. In
addition to porosity these logs are affected by other parameters, such as lithology, nature of the
pore fluids, and shale. For more accurate porosity is obtained from combination of logs. The
readings of these tools are determined by the properties of formation close to the borehole. The
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sonic log has the shallowest investigation. Neutron and density logs are affected by a little
deeper region, depending somewhat on the porosity, but generally within the flushed zone.
8.3.1 Neutron porosity log
In neutron log we use a chemical source such as Americium – Beryllium/Neutron bulb which
provides the emission of neutrons as continuous source of energy of about 4.5 MeV/14 Mev.
When neutron collides with nucleus of the atoms in the formation the neutron losses its energy
and excites the nucleus of the atoms in the formation. When the exited nucleus returns back to
its normal state, it emits Gamma ray characteristic to the atom. The analysis of the γ- ray
spectrum identifies the composition of the elements in the formation viz. C, H, Cl, O etc. when
the energy of the neutron reduces to thermal level and collides with Hydrogen atom its energy
reduces to 0.025eV, also the neutrons are captured emitting gamma ray. Thus the uncaptured
neutron reaching the detector is a measure of Hydrogen index of the formation.
8.3.1.1 Advantages
1. Determination of Porosity.
2. Lithology identification
3. Water saturation.
4. Gas detection.
5. Location & Monitoring of gas / oil and water / oil contacts.
6. Correlation with open hole resistivity logs.
7. Shale indicator.
8.3.2 Density log
The density measures formation bulk density and photo electric absorption index of the
lithologic column penetrated. The δb density depends on fluid density and matrix density in
porous formation, and Pe depends on atomic number used to determine the lithology of
formation. To measure δb and Pe gamma rays are directed to the formation. The detectors
measure the gamma ray flux resulting from scattering and absorption effect of the formation.
The higher the formation density, the lower the gamma ray intensity at the detectors.
8.3.2.1 Tool configuration
The density utilizes
1. A Cesium 137 gamma ray source
2. Two sodium iodide scintillation detectors
3. Small Cesium 137 source near the detectors
All of which are mounted on an articulated pad.
The SS detectors count rates associated with Compton scattering used only in the determination
of bulk density because it is covered by cadmium shield which absorbs all gamma rays of
energy less than 140 KeV. The LS detector count rate depends on Compton scattering and
photoelectric effect used to determine both δb and Pe. The LS detector is covered by beryllium
shield absorbs rays of energy less than 160 KeV.
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8.4 Gamma ray log
The standard gamma ray tool contains no source and it responds only to gamma ray emission
from the down-hole environment. Potassium (K40), Uranium (U238), Thorium (32) are the
main radioactive materials. The main types detectors are Geiger Muller detector or
Scintillation Counters with NaI, CsI or BGO crystals (Photomultiplier, to measure incident
gamma radiation.). The detector is unshielded and will thus accept radiation from any direction.
8.4.1 Application
1. The gamma ray is particularly useful for defining shale beds when sp curve is rounded.
2. It is used as a quantitative indicator of shale content.
3. Detection and evaluation of radioactive minerals.
4. Delineation of non-radioactive minerals including coal beds.
5. Correlation in cased hole operations.
6. The gamma ray log used in connection with radioactive tracer operation.
8.5 Casing collar locator
The CCL detects casing collars and perforations in tubing and casing. The CCL is a magnetic
devices that detects changes in metal mass, such as those induced by the relatively high mass
of a casing collar. The disturbance to the magnetic field is detected as a voltage difference. The
CCL detects changes in metal volume as it moves through tubing or casing. The tool detector
is comprised of a coil mounted between two opposing permanent magnets. As the tool passes
a collar, the lines of magnetic flux between the magnets are disturbed, inducing a low frequency
voltage in the coil. The signal is amplified and gated onto the wireline.
8.5.1 Purpose
To determine the location of casing collars.
8.5.2 Application
Depth correlation.
8.6 Cement bond log
The cement bond tool (CBT) evaluates cement bond integrity. The tool typically has a single
omni directional acoustic transmitter and two receivers. One receiver at three feet and another
receiver at 5 feet. The tool has no azimuthal capability; instead the received signal is an average
from all around the pipe.
The CBT measures based upon the principle of sonic wave-train attenuation, detecting the
amplitude of a sonic signal passing along the casing as an analog waveform. The signal is
reduced where the casing is bonded to the cement, clearly identifying cement bond. The
primary amplitude is detected at 3 feet receiver and variable density log is generated at 5 feet
receiver.
8.6.1 Purpose
Cement bond integrity is requisite to hydraulic isolation.
8.6.2 Application
Cement bond evaluation.
Drilling Operations
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