PNGE 310Class 21Overbalanced Drilling• Mos.docx

PNGE 310
Class 2
1
Overbalanced Drilling
• Most common type of Oil & Gas drilling
• Drilling with Fluid filled hole
• Hydrostatic pressure > formation pressure
• �ℎ = 0.052 ∗ �� ∗ �� ,
• �ℎ�� ℎ �� ℎ� ℎ��
��,
• �� ℎ� �� (
��
��
),��
• �� ℎ� �� ℎ ��
• Freshwater: 8.33 ppg
• Brine: ~8.5- 9.0 ppg

• Muds: ~8.5- 20 ppg
• Water Based Mud
• Diesel Based Mud
• Synthetic Oil Based Mud
2
Overbalanced Drilling:
Rig Components
3
1. Crown Block
2. Cat Line (Hoist)
3. Drill Line
4. Monkey Board
5. Traveling Block (Hook)
6. Top Drive
7. Derrick (Mast)
8. Drill Pipe, Elevators, Bails
9. Doghouse, Drillers Cabin (DS, ODS)
10. BOP (Stack)
11. Rig Water
12. Cable Tray (Festoon)
13. Generators (Gens)
14. Rig Fuel
15. Electric House (VFD)
16. Mud Pumps
17. Bulk Mud Storage
18. Mud Pits
19. Earth Pit (Solids Control)

20. Separator (Gas Buster)
21. Shakers
22. Choke Manifold
23. V-Door
24. Pipe Racks
25. Accumulator
Crown Block
• An assembly of sheaves or pulleys mounted on beams at the
top of the derrick. The drilling line is run over the sheaves
down to the hoisting drum.
4
Traveling Block
• An arrangement of pulleys or sheaves through which drilling
cable is reeved, which moves up or down in the derrick or
mast.
5
Top Drive
• The top drive rotates the drill string without the use of a kelly
and rotary table. The top drive is operated from a control
console on the rig floor or from joysticks in the drillers house.
6

Bails
• Large steel tubular used to connect the elevators to the top
drive. Used when picking up pipe, tripping drill pipe, or
running casing.
7
Elevators
• A set of clamps that grips a stand, or column, of casing,
tubing,
drill pipe, or sucker rods, so the stand can be raised or lowered
into the hole.
8
Drawworks
• The hoisting mechanism on a drilling rig. It is essentially a
large winch that spools off or takes in the drilling line which
raises or lowers the traveling blocks
9
Catwalk

• Equipment where pipe is laid to be lifted to the rig floor by
the
catline or by an air hoist. Can be automated by hydraulics.
• https://www.youtube.com/watch?v=Nzn2m_wqzlM
10
https://www.youtube.com/watch?v=Nzn2m_wqzlM
Drill String Design
• Drill String Components:
• Bit
• Drill Collars
• Tapered/ Non-Tapered
• Drill Pipe
• Tapered/ Non-Tapered
11
Buoyancy
• Buoyancy Factor is the factor that is used to compensate loss
of weight due to immersion in drilling fluid, 0-1.0
• 65.44ppg is the weight of steel

12
�� = 1 −
��
��
��
65.44 − ��[��]
65.44
Drill String Design Checklist
1. Air Weight Calculations
2. Tapered/Non-Tapered DC Calculations
3. Stiffness Ratio
4. Bending Strength Ratio
5. DC Make-Up Torque
6. Drill Pipe Information & Design
7. Margin of Pull (MOP) also called Overpull
13
Drill String Design

Drill String Component Quantity Connections
DC
Section 1: 9" x 3“ 192 #/ft 6 7-5/8" Reg
Section 2: 7-3/4" x 2-13/16“ 139 #/ft 6 5-1/2" FH
Section 3: 6" x 2-1/2“ 79 #/ft ? 4-1/2" FH
HWDP
5" x 3” 49.3 #/ft 6 NC 50
DP
5", 19.5, Grade E-75, Premium ? NC 50 (XH)
5", 19.5, Grade S-135, Premium ? NC 50 (XH) 14
Example:
Desired Parameters
TD 12,000 ft
MW 11 ppg
Bit 12-1/4"
WOB 50,000 lbs
SF 15%

MOP 120,000 lbs
15
Design a tapered drill string utilizing
the inventory listed in the previous
slide. Plan to use all 6 DCs in section 1
and all 6 DCs in section 2. How many
DCs are needed in section 3? Note: all
the WOB should be utilized from the
DCs. Plan on using all the HWDP for
BHA stiffness.
Air Weight Calculations:
Tapered DC
• Section 1 DC
�� = 6 ∗ 30ft ∗ 192 �
lbs
ft
= 34,560 lbs
• Section 2 DC
�� = 6 ∗ 30�� 139 �
��
��
= 25,020 ��
• Section 3 DC → need to calculate length
for tapered string
16

Tapered DC Calculations:
17
• Buoyancy Factor
�� =
65.44 − ��[��]
65.44
�� =
65.44 − 11
65.44
= 0.8319
• Equivalent WOB in Air
�� =
��∗ ��
��
=
50,000 ��∗ 1.15
0.8319
= 69,118 ��
Length of Section 3 DC

��(�3) =
�� − ��(�1) + ��(�2)
��(�3)
��(�3) =
69,118 �� − [34,560 �� + 25,020 ��]
79 #/��
��(�3) = 121 ��
• Round DC(S3) up to even length of 30’ joints → 150 ft (5 DC)
18
Tapered DC Design
• Recalculate the safety factor with designed BHA and check
with original SF. Checks ok
��′�� = 34,560 + 25,020 + 150�� ∗ 79#/��
= 71,430 ��
�� =
��′�� ∗ ��
��
− 1 ∗ 100%
�� =
71,430 ∗ 0.8319
50,000

− 1 ∗ 100% = 18.75%
19
DC Summary
20
• Section 1 DC
�� = 6 � 30ft � 192 �
lbs
ft
= 34,560 lbs
• Section 2 DC
�� = 6 ∗ 30�� 139 �
��
��
= 25,020 ��
• Section 3 DC
��=5 ∗ 30�� 79 �
��
��
= 11,850 ��
BHA Summary

21
Summary
Length [ft]
Total
Length [ft] Wair [lb] Wboy [lb] Wtotal [lb]
Total
Grade S-135 DP
Grade E-75 DP
HWDP 180 690 8,874 7,382 66,805
Section 3 DC 150 510 11,850 9,858 59,423
Section 2 DC 180 360 25,020 20,814 49,565
Section 1 DC 180 180 34,560 28,751 28,751
Non-Tapered BHA
• To find the length of non-tapered Drill Collars:
�� =
�� ∗ ��
�� ∗ ��
��

��
��
22
Stiffness Ratio
• If I/C Ratio is less than 3.5, the stiffness change between two
different components is considered “OK”
�� =
��
��
�� = 0.0982 ∗
��4 − ��4
��
23
Stiffness Ratio
Tapered BHA I/C Ratio
9" x 3" 70.70
7-3/4" x 2-13/16" 44.92 1.57
6" x 2-1/2" 20.57 2.18

Drill Pipe Information
• Ex: 5”, 19.5ppf, Grade E, XH, NC50, Premium
• 5” Tube OD
• 19.5 nominal weight
• Not the actual weight/foot!
• Grade E determines minimum Yield value
• Grades E-75, X-95, G-105, S-135, V-150
• XH is the tool joint description
• XH (extra hole) aka IEU (Internally & Externally Upset)
• IF (internally flush) aka EU (Externally Upset)
• NC50 is the connection threads (Numbered Connection)
• Diameter on pin end, 5/8” from shoulder
• Ex: NC50 = 5.0417”; NC46 = 4.628”
• Premium is the wear classification based on inspections
• New, Premium, and Class 2
• Each classification affects the yield values
24
Minimum Yield
• As DP is used, the material becomes worn. Pipe inspection
companies will inspect the pipe and classify it as Premium or
Class 2. DP is only classified as New one time. After one time
use, the rating falls to Premium.

• Grade E-75 means minimum yield is 75,000psi
• To find the max load (or pull) allowed on the DP:
�� = �� ∗ � ∗ %�� → ��
�ℎ��
�� = 75,000 ∗ 5.2746 = 395,595 ��
�� = 75,000 ∗ 5.2746 ∗ 0.7875 = 311,535 ��
��
�� = 75,000 ∗ 5.2746 ∗ 0.6836 = 270,432 �� (��
2)
25
DP Length Design by Overpull
�� =
�� ∗ 0.9 − �� − ��
�� ∗ ��
�ℎ��: �� ℎ� ��
��,
�� ℎ� �� ,
�� ℎ� �� ℎ� ��
��,
�� ℎ� ��
��
��
�� ℎ� ��,

�� ℎ� ��
�� =
311,535 ∗ 0.9 − 120,000 − 66,805
20.89 ∗ 0.832
= 5,383 ��
26
Drill Pipe Slips & Table Bushing
27
DP Length Design by
Slip Crushing
�� =
�
[��∗ 0.9
�
�ℎ
��
]
− ��
�� ∗ ��

�ℎ��, �
�ℎ
��
�� ℎ� ��,
�� = 0.08,�� 16"
��
�� =
311,535 ∗
0.9
1.42
− 66,805
20.89 ∗ 0.8319
= 7,519 ��
28
Drill String Design
• Use given value of DP Grade E Length
29
Summary
Length [ft]
Total

Total
Grade S-135 DP
Grade E-75 DP 5,383 6,073 112,451 93,548 160,364
HWDP 180 690 8,874 7,382 66,805
Section 3 DC 150 510 11,850 9,858 59,423
Section 2 DC 180 360 25,020 20,814 49,565
Section 1 DC 180 180 34,560 28,751 28,751
Drill String Design
• Calculate the remainder of Grade S Drill Pipe
�� =
�� ∗ 0.9 − �� − ��
�� ∗ ��
�� =
560,764 ∗ 0.9 − 120,000 − 160,364
22.60 ∗ 0.832
�� = 11,930 �� 135
30

Drill String Design
31
Summary
Length [ft]
Total
Total
Grade S-135 DP 5,927 12,000 133,950 111,434 271,788
Grade E-75 DP 5,383 6,073 112,451 93,548 160,354
HWDP 180 690 8,874 7,382 66,805
Section 3 DC 150 510 11,850 9,858 59,423
Section 2 DC 180 360 25,020 20,814 49,565
Section 1 DC 180 180 34,560 28,751 28,751
Check MOP
• Check MOP at weakest anticipated point in the Drill String
• How much over the string weight can the rig pull, before we
should be concerned with failure in the pipe due to tension?
• Expect failure at the top of the Grade E Drill Pipe when

pulling
�� = �� ∗ 0.9 − ��
�� = 311,535 ∗ 0.9 − 160,364 = 120,018 �� → ��
• To illustrate, check MOP at Surface at Total Depth
�� = 560,764 ∗ 0.9 − 271,788 = 232,900 ��
32
Drill Bit Selection
• Drill bit selection depends on
• Expected formations to drill
• Size of hole
• Length to drill
• Type of drilling fluid to be used
• Deviated wellbore or not
• Dogleg Severity needed (DLN)
• Cost
• Fixed Cutter Bit (Polycrystalline Diamond Compact PDC)
• Roller Cone Bit
• Milled tooth

• Tungsten Carbide Insert TCI 33
PDC Bits
34
PDC Features
35
PDC Anatomy
36
PDC Bits
37
PDC Cutters
38
PDC Mechanics

39
PDC Bits
• Mostly soft formations
• Size/Shape of cutters
• Profile shape/size
• Aggressiveness
• # of blades
• Single/Dual row cutters
• Back-up cutters
• # of nozzles
• Moderate WOB
• High RPM
• Expensive
• Used with fluid
• Drills by shearing rock
• https://www.youtube.com/watch?v=R8X6W0G7krg
40

Roller Cone Bits
41
•https://www.youtube.com/watch?v=WR8PTENpSAg
https://www.youtube.com/watch?v=WR8PTENpSAg
TCI Nomenclature
42
TCI Inserts
43
Milled Tooth Nomenclature
44
Roller Cone Anatomy
45
Roller Cone Anatomy

46
Roller Cone Bits
• Wide range of formations
• Various cutter shape/sizes
• Various # of cones
• Wide range of sizes
• Contains bearings
• Cheap
• Used with air or fluid
• High WOB capability
• Various RPM
• Any angle wellbore
• Drills by crushing 47
Roller Cone Bits
48

Milled Tooth Cutting Structure
49
TCI Cutting Structure
50
Bottom Hole Profiles
51
Percussion Bits/Hammers
• https://www.youtube.com/watch?v=-78eb06Z9J8
• Used in hard formations
• Typically vertical holes
• Only used with air
• Wide range of sizes
• Various designs
• Button size/shape
• Breaks rock by tension

• Low WOB
• Slow RPM
52
https://www.youtube.com/watch?v=-78eb06Z9J8
Hydraulics
• Bit Hydraulics
• Cleans the bit and bottom hole
• Cools the bit
• Annular Hydraulics
• Carry cuttings to surface
• Limit annular pressure drop
• Limit hole erosion
• Downhole Tool Hydraulics
• Positive Displacement Motors (PDM)
• MWD Tools
53
Hydraulics

• Pump Pressure or Stand Pipe Pressure (SPP)
• What affects SPP?
• Flow Rate (# strokes per minute SPM)
• Flow Area
• Length of Circulating System
• Fluid Properties
��2 = ��1
��2
��1
2
54
Hydraulics-Bit Nozzles
55
• Nozzles are threaded into the bit prior to drilling
• Measured in 32nds of an inch
• Provides control of the following
• Flow area (TFA) as the fluid exits the bit (pressure loss)
• Fluid velocity as it exits the bit (cleans cutters)

• Provides a Horsepower cutting force as the fluid exits the bit
to assist
cutting rock
Hydraulics
• Pressure drop across the bit
• Nozzles are inserted to provide high hydraulic energy at the
bit
• This cools the cutters, cleans the cutters (prevents bit balling),
and acts as a pressure washer by carrying the rock cuttings away
from the bit
�� =
�� ∗ �2
12,032 ∗ �2
Where MW is the fluid density in ppg, Q is the fluid flow rate
in
GPM, and A is the total nozzle flow area in square inches.
• Bit Hydraulic Horsepower
�� =
�� ∗ �
1714 56

Hydraulics
• Maximum Hydraulic Horsepower Theory
• 65% of available surface pump pressure is lost through the bit
due to
nozzle restriction
• Maximum Jet Impact Force Theory
• 48% of available surface pump pressure is lost through the bit
nozzles
• Nozzle Velocity (Jet Velocity)
• This is the velocity of the fluid as it exits the bit through the
nozzle
�� = 0.321 ∗
�
��
,
�ℎ�� ℎ� ��
��
��
,
� ��
��
��
,

�� ℎ� �� ℎ�
��
2 57
Drilling Engineering
Class 3
1
Drilling Fluids
2
Drilling Fluids
3
Drilling Fluids
• Purpose of Drilling Fluid
• Well Control
• Clean the Wellbore of Cuttings
• Cool the Bit

• Function Downhole Tools (PDM & Turbine Motors)
• Fluid Properties
• Rheological Properties
• HTHP
• Solids Analysis
• Electric Stability
• Water phase salinity
• Alkalinity
4
5
Mud Weight/Funnel Viscosity
• The Mud Weight, MW, or fluid density, is measured in lb/gal
(ppg). MW is measured with a calibrated balance.
• MW is increased by adding the mineral barite
• The Funnel Viscosity, FV, is a relative trend measured with a
Marsh funnel in sec/quart
• The MW and FV trend is monitored closely and periodically
by
the derrickman.

6
Rheological Properties
• Ratio of shear stress to shear rate
‒ Shear stress is the internal resistance of a
fluid to flow at a shear rate
7
Plastic Viscosity
• Plastic Viscosity (cP)
• PV is the rate of change of shear stress as a function of
shear rate between 300 and 600 rpm in centipoise
�� = �600 − �300
• PV is related to the size, shape, and number of particles
in a moving fluid
8
Yield Point
• Yield Point
• Shear stress required to initiate fluid flow

• Directly related to fluid carrying capacity
��[ �� 100��2
] = �300 − ��
9
Rheological Properties
• Gel Strength
• Measure of the rigid or semi-rigid gel structure
developed during periods of no flow
• Maximum measured shear stress at three rpm
– Ten second gel
• After remaining static ten seconds
– Ten minute gel
• After remaining static ten minutes
– Thirty minutes gel
• Used in some critical drilling operations
10
HTHP Filtration
• Process of a fluid filtering through a low permeability
paper filter leaving solids deposited over a 30 minute
period with a pressure differential of 500 PSI and a

temperature of 300°F; The build up of solid cake is
measured in 64ths of an inch.
11
Retort & Solids Analysis
• Retort =Oil, water and solid
percent by volume
• Total Solids Percent
–Low Gravity
• Drilled Solids (2.4 - 2.8 sg)
• Commercial clays (2.6 sg)
–High Gravity
• Barite (4.2 sg)
• Hematite (5.0 sg)
12
Electric Stability
• Tests emulsion stability of fluid sample
• Measures the Voltage required to initiate conductivity
13

Water Phase Salinity
• The calcium analysis results along with the chloride and
water content tests, are used to calculate the WPS.
• Required to avoid water transfer and resulting swelling of
formation clays
• Function of formation vertical depth, pore pressure and
salinity of the water in the shale
• Inspect the cuttings over the shakers (large sharp edged
or small like coffee grinds)
• Only needed in shales with OBM
14
Advantages of an Invert
Emulsion Fluid
• Shale stability
• Temperature stability
• Lubricity
• Corrosion resistance
• Stuck pipe prevention

• Contaminant resistant
• Production protection
15
Invert Emulsion Fluid Phases
16
• Water emulsified into oil
– Three phases
• oil (continuous phase)
• water (discontinuous
phase)
• solids (discontinuous
phase)
Emulsion
• Emulsion
‒Dispersion of one immiscible fluid into another
‒Water into oil base
‒Microscopically heterogeneous mixture

• Emulsifier
‒Surface active agent
‒Decrease interfacial tension
‒Soluble in both water and oil
17
Typical Mud Products
• Emulsifiers
• Wetting agents
• Viscosifiers
• Thinners
• Filtration reducers
• Densifiers
18
Drilling Mud
• Function of Mud
• 1st means of well control
• Stabilize the wellbore

• Clean the hole
• Cool the bit and formation
• Transfer Hydraulic Horsepower HHP from mud pumps
to bit
• Mud is #1 in Drilling Optimization
19
Types of Drilling Fluids
• Water Based Mud: +90% water, ~$60/bbl
• Diesel Based Mud: <5% water, +$100/bbl
• Synthetic/Oil Based Mud: 50-80% water, $200/bbl
• Brine/Water
• Air
• Foam
• Synthetic and Water Based Muds are used in drilling most
Horizontal
Shale wells
• Synthetic Mud uses a Base Oil derived from mineral oil
• Synthetic/Oil based mud is known as an Invert Emulsion Fluid

• We will represent as SBM or OBM
20
Drilling Mud
• Mud Weight (MW)
• Typically measured in lbs/gal (ppg) with a balance
• Must be sufficient so the hydrostatic pressure will overcome
the
formation pressure and control the well
• Marcellus drilling uses MW from 10.0 to 13.0ppg
• A lower MW will help increase rate of penetration (ROP)
• Too high of MW will result in lost circulation and high ECD
• MW should be checked often. i.e. every 20-30min
• Keep a log of MW and monitor MW of the suction and the
flowline returns
• MW[ppg] = specific gravity * 8.33ppg
• Mud Weight Equivalent (MWE) testing
21
Drilling Mud Rheology
• Funnel Viscosity (FV)

• This is a trend, not a value used for calculations
• A quick indicator when something is going on with the mud,
however it will not tell you what the problem is.
• Measured in sec/qt with a Marsh Funnel
• Very sensitive to temperature: Higher temp= lower viscosity
• Rule of thumb: FV ≈ 4*MW
• FV of water is 26 sec/qt @ 68°F
• FV should be checked each time the MW is checked
• Marcellus drilling SBM is ~50-70 sec/qt
22
• Plastic Viscosity PV
• Measured in centipoise (cp)
• Calculated from Viscometer lab tests
�� = �600 − �300
• Measures a resistance to flow primarily caused by the amount
of
solids in the fluid & temperature
23

• Yield Point
• Units of lb/100ft2
• Relates to attractive forces in mud (solids & liquids)
• Sensitive to temperature
• YP influences:
• Equivalent Circulating Density (ECD)
• Tripping Mud Weight
• Swab/Surge Conditions
• Hole Cleaning
24
Equivalent Circulating Density (ECD)
An additional pressure on the wellbore caused by the
fluid while circulating. This is due to friction in the annulus,
cuttings capacity in the fluid, and fluid properties. This
pressure
is in addition to the hydrostatic pressure of the fluid.

��[��] =
∆��
0.052 ∗ �
+��
�� = �� ℎ�, ��
� = ��ℎ �� , ��
∆�� = �� , ��
Annular ΔP is dependent on MW, YP, flow area, fluid velocity,
friction factors (Re, turbulent or laminar)
25
• Low Shear Yield Point (LSYP)
• Good indication of cuttings carrying capacity in horizontal
wellbores
• Treat mud with a low shear modifier to increase LSYP but not
impact YP
• Bio-polymers, Thixotropic, or shear thinning
• Viscosity vs. Shear Rate is inversely proportional
• There is a polymer concentration, where flow psi and
suspension

properties are optimized according to well conditions
�� = 2�3 − �6
�3 = �� @ 3��
�6 = �� @ 6��
26
• Gel Strengths (Gels)
• Related to attractive forces in mud under static conditions
• Simulates a ‘no flow’ condition and quantifies a suspension of
cuttings
• Fann 3rpm reading after static 10sec, 10min, 30min under
constant temperature
27
Solids Control
• Retort Analysis measures the amount of solids in mud
• Provides the following data:
• % Water, % Oil, % Solids, % LGS & HGS

• Low Gravity Solids
• Bentonite & Clays (~2.6 specific gravity)
• Drilled solids
• Can maintain a MW of 8.5 to 10 ppg
• High Gravity Solids
• Barite (~4.2 sg)
• Iron Oxide
• Maintain a MW of 9.5 to 21 ppg
28
Solids Control
• Solids Removal
29
Equipment API Screen Size Micron Removed
Shale Shaker 40 381
80 234
100 178
150 105
200 74

325 44
Desander 50 to 60
Desilter 20 to 30
Centrifuge 5 to 100
Flocculation < 5
Solids Control
• Shale Shakers
• First step in the solids control process
• Receives fluid/cuttings from the flowline
• Uses API sized screens to shake fluid & cuttings. Fluid falls
through
the screens and is collected below in the ‘Sand Trap’ tank.
• Larger sized solids travel across the screen and fall into a
container
to be disposed of.
• Video
•
http://www.slb.com/services/miswaco/services/solids_control.as
px
30

Solids Control
• Centrifuge
• Centrifuge receives fluid containing fine particles from the
‘Sand Trap’
• Removes fine particles from fluid by creating G forces. Solids
in the
fluid with higher specific gravity will separate from the lighter
weight
fluid base.
• Cleaner fluid that exits the centrifuge is typically lighter in
weight and
called ‘Effluent’
• Video
• http://youtu.be/kkAaij_65Zo
31
Class Problem
Building Volume- Oil Based Mud (OBM)
• Make 1,000 bbls of 12ppg OBM with OWR 75/25
• Given base oil wt. = 7.0 ppg

32
Class Problem
• Oil/Water Weight (OWW)
�� → �1��1 + �2��2 = �1 + �2 ��
0.75�� ∗ 7.0�� + 0.25�� ∗ 8.33��
= 0.75 + 0.25 ��
�� = 7.33��
33
Class Problem
• Calculate the Oil/Water volume needed to build the 1000bbls
of OBM
• Use Barite as weighting agent
• 4.2sg * 8.33ppg= 35ppg
• 35ppg * 42gal/bbl = 1470 ppb
�� =
35 −��
35 − ��
∗ �� =
35 − 12��

35 − 7.33��
∗ 1000�� = 831��
• Volume of Water needed
• 831*0.25 = 208 bbls of water
• Volume of Base Oil needed
• 831*0.75 = 623 bbls of base oil 34
Class Problem
• Calculate the amount of Barite needed
#�� = 1470
�� − ��
35 −��
∗ ��
#�� = 1470
12 − 7.33
35 − 12
∗ 831 = 248,032��
�� = 248,032�� ÷ 1470�� = 169��
• Check Material Balance
�� = 208 + 623 + 169 = 1000�� → �� 35

Hole Cleaning
• Factors that influence hole cleaning
• ROP, RPM, flow rate, mud properties, inclination
• Flow rate is controlled by rig pumps and pressure
• Don’t drill faster than you can clean the hole
• Keep the fluid moving
• Spinning drill string helps ‘mix-up’ the cutting beds in high
angle wellbores
• Most difficult hole to clean is between 30 and 60 degrees INC
• Periodically send sweeps/pills
• Circulate a ‘bottoms up’
• Calculate a B/U (in # of strokes)
36
Hole Cleaning
• Carrying Capacity Index (CCI)
• Used as an indicator of good hole cleaning parameters in holes
less than 35deg INC
• If CCI < 1.0, expect poor hole cleaning

• If CCI > or = 1.0, expect good hole cleaning
�� = �� ∗ ��2
��[
��
��
]
14,000 ∗ ��
37
Hole Cleaning
• Annular Cylindrical Volume
� �� =
��2 �� − ��2(��)
1029.4
∗ �(��)
• Calculate a “bottoms up”, B/U, in # of strokes for the given
well. *Ignore the BHA diameter difference
Hole TD = 18,000’ MD; 7250’ TVD
Last Casing String: 9-5/8” 36ppf J-55 set at 4000’
Bit Size = 8-3/4”
Drill Pipe Size = 5”

Calibrated Pump output = 0.081 bbls/stk
38
Class 4
1
Directional Drilling
• Surface Location
• Wellhead coordinates at the surface elevation
• Measured Depth (MD)
• Total footage drilled according to pipe tally
• True Vertical Depth (TVD)
• Vertical depth from surface location
• Inclination (INC): Build/Drop inclination
• Angle from vertical
• 0 degrees is straight downward/ 90 deg is horizontal
• Azimuth (AZ): Turn in azimuth
• Angle from True or Grid North
• 0 degrees is North/ 90 degrees is East, etc.
• Kick off Point (KOP)

• Depth where wellbore begins to build or drop inclination (start
of the curve)
• Tangent
• Section of the curve where the inclination & azimuth is held
constant
• Landing Point (LP)
• Depth at MD & TVD where the curve lands in the target
formation at the start of the lateral
• Target formation/zone
• Desired formation/zone with a set thickness to place the
lateral
• Lateral
• Horizontal part of the wellbore. Follows the target formation
from LP to TD
• Vertical Section (VS)
• A horizontal measurement from the surface location to any
given point in the well. VS is defined with AZ
direction. Usually has same AZ direction as the lateral
2
Directional Drilling
• Why drill directionally?
• Horizontal Drilling
• Maximize wellbore exposure to producing formation

• Multiple producing zones
• Target multiple zones with one surface wellbore
• Relief Well
• Drill into adjacent well to relieve a blown out rig or wellhead
• Side Track
• Kick off and side track around a fish (object stuck downhole)
• Inaccessible locations
• Large cities, protected land, noise, etc.
• Shoreline Drilling
• Much cheaper day rate for land rig than offshore rig
3
Downhole Tools
• Conventional Bent Motors
• Cheaper to drill
• Used on shorter lateral wells to drill curve & lateral in one run
• Rotate and Slide Drilling
• Motor is set to a desired bend before TIH
• Distance from the bit to the bend can vary and greatly affects

build rates
• The achievable dogleg from a set motor is called the “motor
yield”
4
Downhole Tools
• Rotary Steerable Systems (RSS)
• Latest technology
• Expensive
• Designed for long wellpaths
• Constantly Rotates
• Push to Bit Type Steering
• Point to Bit Type Steering
• https://youtu.be/nIAsf1g6wQE
• https://youtu.be/uVrw3InxPyc
5
https://youtu.be/nIAsf1g6wQE
https://youtu.be/uVrw3InxPyc
Downhole Tools

• Rotary Steerable Motors (RSS)
6
Positive Displacement Motors
7
Positive Displacement Motors
8
• Rotor & Stator configuration is selected based on desired
torque & rotary speed.
• Motors come with a specified rev/gal (revolutions per gallon)
• As fluid is pumped through the motor, additional rotary is
gained at the bit
�� = � ∗ �� + �� ,
�ℎ�� ℎ� �� ℎ�
��
��
��
,
� �� ℎ� ��
��
��

, �� ℎ� ��
��
��
,
�� ℎ� ��
�� /��
Directional Plans
• Type I: “L” Profile
• Build and Hold Trajectory
• Drilled vertical from surface
• Relatively shallow KOP
• Casing ran to the End of Build-Up
• Hold INC & AZ in tangent
• Drill tangent to TD
• Typically shallow wells
• Single producing zone
9

Directional Plans
• Type II: “S” Profile
• Build, Hold, Drop Trajectory
• Drilled vertical from surface
• Relatively shallow KOP
• Hold INC & AZ to end of tangent
• Drop INC to near vertical
• Drill vertical to TD
10
Directional Plans
• Type III: “J” Profile
• Drilled vertical to deep KOP
• Quickly build to high INC with low VS
• Reach TD at end of the curve
• Not a common well path
• EX: multiple sand producing zones
11

Directional Plans
• Type IV
• These can combine any of the previous profiles with the
addition
of a lateral section
• Lateral is near 90 degrees INC or following producing
formation
• Increases wellbore exposure to the producing formation
• Thin oil zones
• Low permeability reservoirs
12
Directional Plans
• Typical Horizontal Well Components
13
1
2
3
4
5

6
7
1
2
3
4
5 6 7
1. Vertical
2. KOP #1
3. Tangent
4. KOP #2
5. LP
6. Lateral
7. TD
Well Planning
• Need land/lease permits and coordinates
• Wellhead surface coordinates (Surface Hole Location SHL)
• Well lateral TD coordinates (Bottom Hole Location BHL)
• Need lease line boundaries

• Desired lateral spacing
• Desired Doglegs
• Surrounding wells to avoid (Offset Wells)
• Need to know a landing point (LP)
• LP at desired TVD
• Land at what inclination
• Land at what vertical section (VS)
• Torque/Drag models are run to optimize well plans
14
15
Certified Plat
Well Planning-Torque/Drag Models
16
Well Planning-Torque/Drag Models
17

MWD Surveys
• Typical MWD email survey
“MD: 6295 SD: 6208 Inc: 39.6 Azm: 219.9 TVD: 6074.80
VS:
181.06 DLS: 1.72
Currently we are: 7.6' Low and 7.8 Left of the line, seeing 17'
of
Slide.
Please find attached survey data”
• Typically 45ft between surveys in the curve
• 90ft or shorter between surveys in the lateral
• Accelerometers measure INC & AZ
• All MWD surveying tools provide a relative position.
• Surveys do not provide a location in space
• Each survey would build upon the previous to map the
wellbore 18
EM MWD Surveys
19
• Modern EM (Electromagnetic telemetry) tools are designed to
take a survey and

send the data to surface through formation when the flow of
drilling fluid is stopped.
• The tool sends either a magnetic pulse or electrical current
through the ground to
the receiver at surface.
• On the surface the data is received through ground antennas
and the data is
processed
• Sometimes an antennae can be placed midway in the drill
string to help clarify the
signal.
• Different areas have different formation Resistivity so
Amperage and effectiveness of
the EM signal will vary.
Mud Pulse MWD Surveys
• Positive mud pulse telemetry (MPT) uses hydraulic poppet
valve to
momentarily restrict mud flow through an orifice to generate
increase in
the pressure in form of positive pulse which travel back to the
surface
through the drill string to be detected .
• MPT tools take longer to receive data compared to EM. MPT
is more
reliable in harsh conditions, and the formation type has no
effect on
mud pulse signal.

• Like EM, MPT tools sends survey data back to the surface as
soon as the
flow of fluid is stopped.
20
Postive Negative Continuous
Dogleg Severity
• Numerically describes the severity of a bend, by combining
both inclination and azimuth changes in 3-dimensions
• Measures in degrees per 100 feet
• Several formulas to calculate dogleg severity
• Only accurate with small changes in angles
• Small doglegs decrease Torque and Drag (T&D)
• Increases curve length and decreases lateral footage
• Large doglegs increase T&D
• Provide shorter curves to lateral section
21
Dogleg Severity

• Radius of curvature method
• Calculate Dogleg Angle β
• Calculate DLS by taking Dogleg Angle and normalizing to 100
feet
22
• Dogleg Angle β
• The angle of change between surveys
�ℎ��, � �� ℎ, �� ℎ,
� �� , & ��
��
Dogleg Severity
23
� = cos−1 cos ∆� ∗ sin �� sin � + cos �� cos �
Dogleg Severity
• Dogleg Severity δ
• Describes how ‘severe’ the angle of change is between
surveys.
• Normalized to 100ft in order to compare and communicate
with

ease
• Units of degrees per 100ft
• Abbreviated as DLS
� = �
�
∆� ∗ 100
�ℎ��, � �� ℎ� ��
& ∆� �� ℎ� ��
��
24
Dogleg Severity
• Example:
• Calculate the dogleg severity DLS based on the following two
MWD survey reports in the lateral
25
Survey A Survey B
MD (ft) 11,436 11,531
INC (α) 89.00 90.34
AZM (ε) 320.11 323.94
TVD (ft) 6,349.85 6,350.39

VS (ft) 5,133.05 5,227.50
Geosteering
26
• A pilot well is drilled on a multi well pad to obtain gamma
logs of the
desired target and formations around it.
• Geosteering uses the pilot log as a reference and relies on the
gamma
data to interpret the bit’s location while drilling laterals
Geosteering
• Typical Geosteering email
“As of the last survey at 17304’MD (7317.98’ TVD), based on
the GR
Image and current correlation it appears that we are:
Gamma Ray Sensor Position: ON TARGET, ~2.5’ BELOW
TARGET TOP
Relative Formation Bed Dips: ~91.25deg relative dip (133 deg
AZI)
As of right now, continue with TI of 90.5deg.”
27

Project 1
• https://www.youtube.com/watch?v=XntxeRG3ifQ
28
https://www.youtube.com/watch?v=XntxeRG3ifQ
Class 9
1
Blowout Preventers
• Blowout Preventers (BOPs) are used to seal off the
annular area and prevent flow out of the well.
• When used with associated equipment and well
control practices, a drilling crew can control a kick
before it becomes a blowout.
• Kick- any influx of higher pressured liquids or gasses into the
wellbore.
• Blowout- when a kick is gone undetected and not properly
controlled, the influx can make its way to surface and result in
an uncontrollable release of liquid or gas.

2
BOPs
• The BOP and equipment (BOPE) has 3 main functions:
1. Seal off the annular flow area at the surface (shut-in)
2. Allow the crew to control the release of fluids and/or gas
3. Allow pumping into the well by a means other than through
the
drill string
• BOPE must be rated above maximum anticipated surface
pressure
• Must be enough casing in the ground to anchor the wellhead
and BOP
• BOP must be able to shut the well in with or without pipe in
the hole. (ie. Drillpipe, collars, casing, wireline, nothing) 3
BOP Ratings
• BOP stacks come in a variety of sizes and pressure ratings
• Typically the burst rating of the casing is the weakest link
• BOPE should be pressure tested each time it is assembled,
anytime a seal is broken and put back together, or every 21
days per API.

• Nipple Up (N/U)- when the BOP stack is assembled
• Nipple Down (N/D)- when the BOP stack is disassembled
• The BOP stack should be function tested daily to ensure its in
proper working order
4
BOP Arrangement
• The BOP once it is Nippled Up is sometimes referred to as the
“Stack”
• The stack is described as follows:
1. Working Pressure
2. Size (internal diameter)
3. Arrangement of components
5
BOPE Identification
G Rotating Head
A Annular Preventer
R Single Ram type Preventer

Rd Double Ram type Preventer
Rt Triple Ram type Preventer
S Spool
6
BOP Pressure Ratings
API Class
Working
Pressure
[psi]
Working
Pressure
[pa (105)]
Service
Condition
2M 2,000 138 Light Duty
3M 3,000 207 Low Pressure
5M 5,000 345
Medium
Pressure
10M 10,000 689 High Pressure
15M 15,000 1,034
Extreme
Pressure

BOP Stack Components
• Spool
• Typically on or near the bottom of the BOP stack.
• Attaches directly to the wellhead
• Typically has two ports for use during well control (flow in
and
flow out)
• Choke line- allows flow out through the HCR valve and to the
choke
manifold
• Kill line- permits pumping of kill mud down the annulus if
needed
7
• Ram type BOPs
• Seals the wellbore with two closing arms
• Cannot rotate or reciprocate the pipe when rams are closed
• Typically have more than one in the stack arrangement
• Comes in single, double, & triple ram assemblies

• The ram internals can be interchanged with various sizes or
types
• Blind Rams- Flat steel plates used to seal off the well with no
pipe or
wireline in the hole
• Pipe Rams- Curved plates designed to seal around a specific
sized
pipe
• Shear Rams- Cuts off whatever is in the hole in a last resort
extreme
situation
• Variable Bore Rams- VBRs- Has multiple sizes of curved
plates
designed to seal around a range of pipe sizes (ie. 3.5”-5.5” has 5
plates) 8
9
• Annular Preventer
• Sometimes referred to as the “bag” or “Hydril”
• Seals off the annular space of the well around any size or
shaped

item downhole
• Allows for pipe reciprocation (stripping) but no rotation
• Consists of a internal rubber (WBM) or nitrile (OBM) element
that
will squeeze around the pipe and provide a seal
10
• Annular Preventer
11
• Rotating Head Assembly
• The upper most part of the stack
• Allows centered rotation of pipe through the stack
• The flowline intersects the rotating head assembly
• Contains a rotating rubber element to seal around the pipe
while
circulating the well
• This is not a high pressure seal, but only a means to prevent
fluid and
gas from reaching the rig floor by diverting it out the flowline

12
Well Control Equipment
• Choke Manifold
• Series of piping, pressure gauges, and valves to control the
flow
out of a well anytime the BOP stack is closed
• Typically has 1 entrance of fluid/gas from the well coming
from
the choke line and HCR and has 2 means of exit from the
manifold.
• Continuing Choke Line-Through a choking valve to the
Mud/Gas
separator, then mud goes to the shakers and gas to be flared
• Panic Line-Through a choking valve and to a storage tank
13
• Mud Gas Separator
• Used to separate the gas from the mud and cuttings
• The gas will go to the flare to ignite and the mud and/or
cuttings
will go to the shakers to be processed

• Need sufficient mud leg height so hydrostatic head will force
gas
to the flare stack
14
• Accumulator
• Provides compressed hydraulic fluid to open and close the
BOP.
• Several high pressure cylinders that store nitrogen (in
bladders)
and hydraulic fluid under pressure
• Need sufficient volume to close/open all preventers and
accumulator pressure must be maintained all time.
• According to API RP53, your reservoir tank should have a
total
volume at least 2 times of usable volume to close all BOP
equipment
15
• Accumulators
• Components consist of

• Hydraulic fluid reservoir tank
• Pumping system (compressors)
• Must have 3 independent compressor sources
1. Rig air for pneumatic pump
2. Electric pump
3. Stored bottles of compressed nitrogen
• Manifold, pressure regulators, and lever valves
• Bottles
16
• Accumulator
• The electric pump is the primary compressor. It will provide
compressed
hydraulic fluid to function the BOP
• The pneumatic pumps are a backup to the electric pump
17
• Bottles are used to store pressurized hydraulic
fluid for closing/opening all blow out
preventers.

• Each bottle, with a rubber bladder inside, has a
storage volume of 10 gal.
• The rubber bladder is pre-charged to 1,000 psi
with nitrogen.
• Each bottle (outside the bladder) will be
pressured up 200 psi over the pre-charge
pressure using 1.7 gal of hydraulic fluid to
compress the gas filled bladder. This is called
“minimum operating pressure”.
• Hydraulic fluid will be pumped into the bottle
until pressure in the bottle reaches 3,000 psi,
called “Operating Pressure”.
• Volume of hydraulic fluid used to pressure up
from 1200 psi to 3000 psi, called “Useable
Fluid”, is equal to 5 gal
Well Control
• What is a kick?
• An unscheduled entry of formation
fluid/gas into the wellbore
• The pressure inside the wellbore is
lower than the formation pore
pressure (in a permeable formation).
• Mud density is too low
• Fluid level is too low - trips or lost circ.

• Swabbing/Surge
• Drilled into a fault or hi pressure zone
18
Well Control
• Kick Detection
• Pit Gain
• Increase in flow from drilling fluid
• Drilling Break
• Decrease in circulating pressure (Stand Pipe Pressure)
• Well flows after the pumps are off (flow check)
• Increase in Hookload
• Incorrect fill up volumes on trips
• Goals
• Keep the kick size small (early detection)
• Shut-in well at BOP
• Circulate out the kick using choke to maintain constant bottom
hole pressure BHP
• Replace well with kill weight mud
19

Well Control
• Drillers Method
• Requires 2 complete circulations
1. Circulate the gas bubble to surface
2. Replace original mud with kill weight mud
• Wait and Weight Method (Engineer’s Method)
• Requires 1 complete circulation
1. Circulate the gas bubble to surface using the kill weight mud
• Both Methods
• BOP is closed at first sign of kick (keep kick as small as
possible)
• HCR is opened to allow annular to flow to choke manifold
• From choke manifold the flow travels to the gas buster
• Choke is used to manually control DP and CSG pressure
• CSG pressure is affected immediately upon action of the
choke
• DP pressure will be delayed upon action of the choke
• ~1 second delay per 1,000ft traveled
20

Well Control
• In this class we will focus on the Wait & Weight Method
• Also called the Engineer’s Method
1. Determine stable shut in drill pipe and casing pressures after
shutting in
on a kick.
2. Weight up pits to desired kill mud weight.
3. Bring pump on line to the desired kill rate speed very slowly
in small
increments. At this time, the circulating pressure on the drill
pipe side
becomes your initial circulating pressure. Maintain this
constant drill pipe
side circulating pressure while removing kick from the well.
4. When circulating kill fluid down the drill pipe, follow the
step down chart
found on killsheets for initial circulating pressure to final
circulating
pressure.
5. Circulate kick out of the hole, maintaining final circulating
pressure.
6. Shut well back in a second time and determine if well is
dead. If pressures
increase, additional circulations or additional weight may be
required.
21

Well Control
• Wait and Weight Method (Engineer’s Method)
• Depth= 10,000ft (Vertical Hole)
• Hole Dia.= 12.25”
• Drill Pipe: 4-1/2” OD; 12.74 lb/ft; ID= 4.00”
• Casing: 4,000ft of 13-3/8” OD; 68 lb/ft; L-80; 12.415” ID
• Current MW= 10ppg
From initial shut-in:
• Shut-in Casing Pressure (SICP)= 600psi
• Shut-in Drill Pipe Pressure (SIDPP)= 500psi
• Kick Size= 30bbl (interpreted from mud pit gain)
22
Well Control
• At no time during the process of removing the kick fluid from
the wellbore will the pressure exceed the pressure limits of
• The formation
• The casing

• The wellhead equipment
• When the process is complete, the wellbore will be filled with
a fluid of sufficient density (kill mud) to control the formation
pressure.
• Under these conditions the well will not flow when the BOP’s
are
opened.
• Keep the BHP constant throughout the circulation process.
23
Well Control
• From the initial shut-in data, we can calculate:
1. Bottom Hole Pressure BHP
2. Casing Shoe Pressure (compare to casing burst rating)
3. Density of kill weight mud
4. Length of the kick at surface
24
1. BHP= SIDPP + Hydrostatic Pressure in DP
= 500psi + 0.052 * 10.0ppg * 10,000ft
BHP = 5,700 psi

Well Control
2. Pressure at the casing shoe
• Pshoe = SICP + HYD_ANN Surface to shoe
• Pshoe = SICP + 0.052 * 10ppg * 4,000ft
• Pshoe = 2,680 psi
3. Density of kill weight mud
• KMW= SIDPP/(0.052*TVD) +MW
• = 500/ (0.052*10,000) + 10 = 10.96 = 11ppg 25
Well Control
26
Annulus Drill String
SICP + HYD_ANN + PKICK = SIDPP + HYD_DP
600 + [0.052*10*(10,000-231)] + PKICK = 500 +
(0.052*10*10,000)
600 + 5,080 + PKICK = 500 + 5,200
Well Control

27
lb/gal 67.1
231*052.0
20
KB
This kick is composed primarily of gas
PKICK = 20psi
Well Control
28
?
[bottom] ][
000
00
surface
RTnZ
VP

RTnZ
VP
BBB
• Goal is to keep BHP constant throughout
the entire Kill process
• Casing and Drill Pipe Pressure will change
• What will be the height of the kick once it
reaches the surface?
• Let’s look at the annulus:
Ignoring changes due to compressibility factor (Z) and
temperature, we get:
Since cross-sectional area = constant: assume
minimal change from open hole and casing
Well Control
29
.)(
..
0

00
000
00
constAA
hPhPei
hAPhAP
VPVP
Bot
BotBot
BotBotBot
BotBot
Well Control
30

�0ℎ0 = ��ℎ�� → Τℎ0 = ��ℎ�� 0
• We have two unknowns, P0 and h0
4. Calculate Height of Kick
BHP = Surface Pressure + Hydrostatic Head
5,700 = P0 + Pkick + HYDANN
5,700 = P0 + 20psi + 0.052*10*(10,000-h0)
5,700 - 20 - 5,200 = P0 - 0.52 *
0
P
hP
BotBot
Well Control
31
psi 102,1862240
2
684,684*4480480
0684684P480
231*5700*52.0 480

0
2
0
0
2
0
2
00
P
P
P
PP
�0ℎ0 = ��ℎ�� → 1102�� ∗ ℎ0 = 5700�� ∗
231��

∴ ℎ0 = 1195��,
this is the height of the gas kick once at surface if controlled by
the choke.
What if the kick was not detected? (ie. �0= 14.7psi)
Well Control
• It is important to keep a Slow Pump Rate recorded while
drilling.
• Driller will stop drilling several times a day and turn the
pumps on
slow (~30-40spm) and record pump pressure (SPP)
• This provides system pressure loss or Kill Rate Pressure
(KRP)
• Use SPR= 40spm on pump #1 @ 1200psi
• Initial Circulating Pressure (ICP)
�� = �� + �� = 500 + 1200 = 1700��
• Final Circulating Pressure (FCP)
�� = �� = 1200��
11
10 = 1320��
• Strokessurface to bit (stksS-B):use 2000stks for this example
��−� = �� ÷ ��
• Last step is to complete the Pressure Chart

• You are now ready to begin to pump and kill the well
32
Well Control
• Pressure Chart
• “Kill Sheets” are documents provided
by service companies to help guide
the calculations of killing a well
• Need: # strokes from surface to bit,
ICP, FCP
• As the pumps are brought online, the
choke will be adjusted to maintain DP
pressure according to the chart
• Actual DP Pressure will be recorded in
the field while the pumping is taking
place to compare calculated to actuals
33
Pressure Chart
Step # strokes
Calculated
DP
Pressure
Actual DP

Pressure
1 0 ICP=
2
3
4
5
6
7
8
9
10
Bit FCP=
Surface to Bit Strokes =
Class 7
1

Extended Reach Drilling
• What is extended reach drilling (ERD)?
• Pertains to deviated wells
• Typically looks at the ratio of TVD vs Vertical
Section
• In this class we will consider a TVD ratio of at least
2:1 as ERD
• Ex: TVD= 8,000’; VS= 16,000’ or greater
2
Extended Reach Drilling
• 1978-1980
• Esso Australia on Mackerel Project
• Wells were about 18,000’ MD
• Took up to one year to drill with numerous stuck BHA’s
• 1988
• Industry started exploring ERD after rise in oil prices
• 1996
• BP successfully drills Wytch Farm well at 26,000’
• 1999
• Total drills Tierra del Fuego CN-1 at +33,000’ lateral
• First well to reach TVD ratio of 5:1
• Unocal drills offshore California C30 at 4872’ lateral (963’

TVD)
• Current record is Maersk Oil Qatar’s BD04A
• 37,956’ lateral (3,500 TVD)
• Northeast Onshore Record
• Utica well in OH (Eclipse Resources 2016)
• 18,544’ Lateral (27,031’ MD, ~9,000 TVD)
• North American Land Record
• North Slope Alaska (Conoco Phillips 2018)
• 21,478’ Lateral (7,900’ TVD)
• Included 2 laterals from a single wellbore
• 34,211’ combined Lateral Length
• 42,993’ combined total footage
3
4
ERD Planning
• Target formation/interval
• Point target or formation exposure?
• Well trajectory to minimize risks
• Hole Size
• Casing Plan

• Rig
• Is a bigger rig always better?
• Typically hydraulics is the limiting component
• Electrical power (top drive TQ limits, mud pump
requirements)
• Solids control
5
ERD Friction Factor
6
Hole Cleaning
• Transporting the cuttings is extremely difficult in high angle
wellbores.
• Gravity pulls downward and creates downward direction for
slip velocity on the cuttings
• The mud is the carrying force on the cuttings
• In horizontal wells the mud travels horizontally in the
direction
of the lateral

• The cuttings will continue to fall from the top of the wellbore
to the bottom
• Mud flow is not uniform throughout the cross section of the
wellbore
7
Hole Cleaning
• Laminar flow profile in the wellbore cross section
• There is a dead zone on the low side of the well
8
Hole Cleaning
• Rotation is the key factor in hole cleaning efficiency for high
angle holes
• The active flow are is at the top of the hole
• Pipe and cuttings lay at the bottom in the dead zone
• Agitation is required to “throw” the cuttings up into the fluid
flow
zone
• Viscous Coupling- the fluid in tension around the pipe that
rotates
with the drill string creating movement of cuttings to the active

flow
area
• Required rotary is dependent on hole size, pipe size, and ROP
9
Hole Cleaning
10
Hole Cleaning
11
Hole Cleaning
• Annular velocities create laminar flow
• Cleaning efficiencies depend greatly on geometry
• Pipe-Hole Area Ratio PHAR
• �ℎ
2 ÷ ��
2 = ��;
if < 3.25: small hole rules; if > 3.25: large hole rules
12

Hole Cleaning
13
Hole Cleaning
14
Class 8
1
Casing
• What is casing?
• Pipe that is API certified for its specific application
• Why is casing set?
• Zonal Isolation when cemented in place
• Casing point selection

• Regulations
• Area Geology
• Formation Pressures
• As the operator, who decides on casing points?
2
Casing
• API casing is available in standard sizes from 4-1/2” to 20”
OD
• Usually steel but can be aluminum, fiberglass, stainless steel,
plastic, titanium etc.
• One piece of casing pipe is referred to as a “joint” of casing
• Casing length is dependent on the “range” of pipe
• Range-1: 18-22ft
• Range-2: 27-30ft
• Range-3: 38-45ft
• Casing Threads are defined by the coupling type
• API Threads
• LTC: Long thread coupling
• STC: Short thread coupling

• BTC: Buttress thread coupling
• Semi & Premium Threads
• See VAM Presentation
3
Casing
• Casing Components
• Casing
• Size, Weight, Grade, Threads
• 9-5/8" 53.5# P-110 LTC Rg 3
• See Casing Data Chart
• What is Drift Diameter?
• Pup Joints
• Float Collars
• Float Shoe
• Guide Shoe
• Centralizers
• Baskets
• Scratchers/Scrapers

4
Casing
• Running Casing
• Bales/Elevators
• Power Tongs
• Torque Turn
• Calculate weight and Hookload HL
• Calculate collapse, how often should you fill the pipe?
• Is the pipe taking the proper amount of fluid to fill? CSGcap
• Is the proper amount of fluid coming back to the pits as the
casing is run in the hole? CSGcap & CSGdisp
• Once casing is landed, circulated mud. Calculate B/U
5
Casing
• Centralization
• Vertical Wells
• Never truly vertical, usually spiral
• Typically use bow spring type centralizers

• There are state regulations on centralizer placement
• The shoe is very important to be centralized
• Horizontal Wells
• Balance between too many and not enough centralizers
• Many types: rigid, floating, bow spring, bladed, spiral bladed,
etc.
• Centralizer design software can model the well as drilled and
suggest
centralizer placement
• High dogleg areas need more frequent centralizers to obtain
sufficient standoff
6
Casing
• Stand-off
• Pipe Stand-off is a major contributor to hole cleaning, mud
removal, and cement quality.
• % �� = �
��
�2−�1
∗ 100%

7
Casing
• Stand-off
• The Stand-off formula results a percentage, where 0%
represents
the pipe in contact with the wellbore wall. 100% represents the
pipe is perfectly centered in the well.
• When the pipe is not centered, the wider portions will promote
flow due to less resistance. There can be pockets of cuttings or
mud in the tighter areas causing contamination to cement.
• Modeling software can analyze the As Drilled deviation
surveys
and generate a casing centralization plan with the casing’s
properties.
• 100% standoff is desirable but not realistic
• Industry minimum standard is 67% over the entire well
8
Casing
• Casing Centralizers
• Casing Baskets

• For lost circ zones
• Scratchers
• For mud cake removal
• Float/Guide Shoe
• Float Shoe will guide and has a one way valve
• Guide Shoe will guide the casing string down
the well
9
Running Casing
• Manual Tongs were commonly used, but few are used today.
• Power Tongs are used to make up (torque) casing joints
10
Running Casing
11
Running Casing
• Casing Running/Rotating Tool (CRT)

• Commonly used in ERD wells
• Used to rotate the casing string to achieve further
depths in the lateral section
• Allows the rig to pump fluid and circulate the
casing
• The combination of rotating and circulating
greatly reduces friction
• Static friction is overcome- Kinetic friction is lower
• The fluid gel strengths are broken down due to
movement
• Show Tesco video 12
Casing Connections
• API Connections
• First developed thread connections
• Cheap, easy to machine, designed to seal liquids
• LTC, STC, & BTC
• Weakest point in the casing string
• Premium Connections
• Developed after years of API thread failures
• Connections are stronger than pipe body
• Designed to seal liquid & gas
• Very expensive
• Semi-Premium Connections

• Developed most recently bc ‘Premium’ is so expensive
• Much stronger and more reliable than API connections
• Much cheaper than Premium
• Designed for liquids and limited gas
• See Vallourec & VAM Presentation
13
Cement
• Why cement?
• Zonal Isolation
• Isolation for completions frac stages
• Goals
• Protect ground water
• Prevent gas migration
• Stimulate more reservoir
• Protect casing from corrosion
• Increase life of well
• Two Types of Cementing Techniques
• Grouting- Utilizing gravity to pour cement from surface down
the
annulus

• Displacement- Pumping cement down the inside of casing and
using
a plug to push cement into the annulus from the bottom of the
well
to surface
14
Cement
• What is considered a good cement
job?
• Poor isolation is contributed by:
• Channeling
• Micro annulus
• Mud contaminated cement
• In horizontal and deviated wells:
• Mud removal is the most difficult
factor to overcome to achieve a
good cement bond
15
Cement
• How to improve the quality of the cement job

• Casing movement
• Casing centralization
• Hole and mud conditioning
• Mud properties
• Effective spacers
• Fluid velocity while pumping
• Wiper plugs
• Quality of shoe- single or double floats
• Circulating after casing is landed
• Lowers the viscosity, PV, the fluids resistance to flow
• Lower MW if at all possible
• Clean wellbore
• Calculate B/U
16
Cement
• Casing Movement
• Requires special equipment
• CRT with rotating cement head

• Pipe reciprocation/rotation
• At least one should be practiced if possible
• Energy is needed to break-up the gelled mud
• Mechanical interaction between the pipe and wellbore
• Changes the flow paths
• Monitor Torque and Drag while moving pipe
• Casing Centralization
• Enhances mud removal thus better cement bonds
• Wider annulus promotes flow
17
Cement
• Cement Blend and Requirements
• State regulations specify the type and properties of cement to
be
used
• Typically require Class A or H cement to be used
• Compressive strength of 500psi before any disturbance of the
casing, commonly 8-12hrs: time is crucial in operations
• Compressive strength of 1250psi in 72hrs

• Limited use of Calcium (CaCl or KCl) in blends (Disturb
surface
water)
• Thickening time of gels
• Little to zero free water
18
Cement
• All cement blends are lab tested and come with quality reports
• Cement should be tested in the lab to mimic field conditions
• Water temperature- how does this effect cement?
• Formation temperature
• Quality of water used; take samples from location
• How do Chlorides effect cement? (brine, saltwater)
• Pumps times should be calculated based on volumes and pump
truck output
• We want the cement to thicken quickly to minimize waiting
time,
but we need it to remain “pump-able” until the job is complete
plus
a safety factor (70 bc time)

• Two stage cement jobs (lead & tail) can help reduce ECD and
lower
costs
• See example Lab Test Results & Cement Additives on
ecampus
19
Cement Procedures
1. Once the casing is landed, the driller will begin circulating
the
well with mud while monitoring TQ/Drag. Pump highest flow
rate possible through the shoe, with at least several B/U.
a) The mud engineer will monitor mud properties. Attempt to
lower PV and MW if at all possible. Why?
b) Derrickman will monitor the shakers for cuttings/debris
return
and notify driller of anything abnormal.
c) Floor hands/Motorman will rig down the power tongs and
clean
the rig floor.
2. While circulating, the cement crew will stage their trucks and
equipment, plumb into water tanks and cement silos, then
begin to batch mix the spacer.
20

Cement Procedures
3. Next step is to hold a cement job safety meeting
a) Communicate the plan/procedure to everyone on location
b) Define each persons roles/responsibilities
c) Talk through pump schedule going over calculations with
cement supervisor
4. Stop circulating, rig up cement head equipment, and plumb
well into cement
pump truck
5. Cement crew will fill lines with water and pressure test
equipment
6. Begin pumping following a pump schedule
c) Spacer with Chemical Wash
d) Lead Cement Slurry
e) Tail Cement Slurry (if two stage)
f) Drop wiper plug and displace with water
g) Slow down the pump rate as plug approaches shoe
h) Land the plug with landing pressure
i) “Bump” the plug with ~500psi over landing pressure
j) Check that the floats hold: release pressure and measure
water returns. Should
get no more than a few bbls back
k) Bleed pressure to zero and wait on cement, WOC 21
Cement
• Spacer- A liquid (typically water &
Barite), weighted heavier & more

viscous then the circulating mud, that
pushes the mud out of the well ahead
of the cement. In OBM systems it will
help water wet the casing & formation
and enhance the cement bond.
Recommended to have 10min contact
time or 1,000ft of coverage.
• Wash- A low dense liquid chemical
pumped to break up mud cake off the
wellbore and treat the formation for a
better cement bond. 22
Cement Calculations
• Converting cement slurry volume to sacks of cement
• Cement blends will have a slurry yield (given)
#�� =
��(��) ∗ 5.6146(
��3
��
)
�� (
��3
��
)
• Cylindrical Volume

� �� =
�2 ��
1029.4
∗ �(��)
23
Cement Calculations
• Annular Cylindrical Volume
� �� =
��2 �� − ��2(��)
1029.4
∗ �(��)
• Lifting force on the casing
�� = �� ∗ � ∗ �� − (�� ∗ �)
Where, �� is the net lifting force in lbs: denote downward as
positive
�� is the air weight of casing in lbs/ft, D is the casing set
depth in
ft, BF is buoyancy factor, �� is the pressure required to land
the wiper
plug at the shoe in psi, A is the cross sectional area of the shoe
in
inches. 24

Cement Calculations
• Example: A. Calculate how many sacks of cement is required
for
the single stage cement job below. Assume perfect hole (no
excess), and cement to surface
20” 94ppf J-55 STC Rg2 casing is previously set at 800’
12-1/4” hole TD= 3500’
9-5/8”, 36#/ft, J-55 Casing run to 3450’
Yield: 1.2 cu.ft/sk; 8.5gal H2O per sack for 14ppg slurry
25
Cement Calculations
• Example cont’d
B. How many sacks of cement are needed if we pumped 30%
excess in the open hole section?
C. How many bbls of water is needed to mix the slurry (with
30%
excess OH) and to displace the wiper plug to the shoe?
D. What will be the pressure needed to land the wiper plug,
ignoring friction?

E. How much pressure is needed to hold the cement in place if
the float shoe happened to fail?
F. Given the floats hold, what is the lifting force on the casing?
26
Cement Plugs
• Plugs can be “spotted” for several reasons
• Abandon a well
• Artificial KOP
• Lost tools downhole
• Directional driller is off plan and can’t achieve doglegs to
recover
• Pilot well was vertically logged deep beyond producing zone
• Class H cement is designed for plugs
• High compressive strength
• Plugs can be set in air or fluid filled hole
27

Class 6
1
Drilling Trends
2
• The driller communicates with the hole through monitoring
trends
• You will not see trends unless you write the numbers and
make a log
• Establish a base line for trends in a clean wellbore
• Watch the trends periodically and when you see changes,
figure out why.
• Monitoring trends and reacting to unusual changes will
prevent unscheduled events
Hole Trends
• Pump Pressure and Pump Rate (Strokes)
• This is the most important trend to watch
• Driller periodically takes a slow pump rate pressure
• Factors that influence Pressure/Stroke relationship:

• Hole Depth, Hole/Pipe Geometry, Surface Plumbing, Mud
Properties,
Downhole Tools, Pump Characteristics
• �2 = �1
��2
��1
2
3
Hole Trends
• Pressure/Stroke Relationship
• Any sudden change in pressure while drilling could indicate
one
or more of the following:
• Hole Restriction
• Hole Loading with cuttings- Dirty wellbore
• Kick taking place
• Drill String Washout
• Loss Circulation to formation
4

Hole Trends
• Example: Pressure/Stroke Relationship
• Driller has the following properties while drilling:
• Stand Pipe Pressure = 3,000psi
• Pumps set at 100 spm
• The driller then observes the following change:
• The SPP suddenly drops 200psi to 2800psi
• He double checks the pumps and they are still set at 100 spm
• What is happening?
• What should you tell your driller to do?
5
Hole Trends
• Example: Pressure/Stroke Relationship
• Could mean
• Drill String Washout
• Lost Nozzle in the bit

• Taking a kick
• What should the driller do?
• Stop the pumps and check if the well is flowing
• Have the derrickman check the pumps for leaks (blown
seals/gaskets)
• Running a downhole motor? Does the directional driller still
see
differential pressure? Can he downlink a survey?
• If SPP is still low, begin to TOH and check for washout in
string 6
Hole Trends
• Drag Trends
• Pick up/Slack off weights (PU/SO)
• The driller must establish the drag trend in a clean hole
• By trending the PU/SO weights a drag trend can be formed
• This can tell you when it is time to stop drilling and circulate
to
clean the wellbore
• This data is imported into Torque and Drag models to help
determine friction factors
7

Hole Trends
• Torque Trend
• This is a measurement of rotational torque in the drill string
• Torque is influenced by the following:
• The drill string making contact with the wall of the wellbore
• Bit penetrating the rock
• Doglegs and well geometry
• Drilling fluid lubricity
• Amount of cutting beds
• Gradual increase in TQ
• Possibly cuttings build up. Circulate a bottoms up and see if it
decreases
• Sudden increase in TQ
• Possible formation change
• Downhole Tool Failure
• Bit under gauge: Motor or stabilizer entering the under gauged
hole
8
Hole Trends

• Rate of Penetration ROP
1. In non permeable zones, like shale, the ROP is directly
proportional to the porosity of that rock
2. In permeable zones, ROP is mainly effected by mud
properties
3. The plot of ROP will appear very similar to a neutron
porosity
plot on the same scale
• Bit wear
• As the bit wears, the ROP will slowly decrease over the
footage
drilled. At some point when it is uneconomical to continue
drilling
with that bit, a bit trip is necessary.
9
Hole Trends
• Tripping Trends are used for T&D models to determine FF
• Tripping out of the hole TOH
• You will see drag trends as the BHA is pulled through
doglegs,
cutting beds, and other tight spots
• It may be a good idea to ream around these spots until the drag

decreases. This will help prevent issues when running casing
• Is the hole taking the proper amount of fluid to fill?
• Tripping in the hole TIH
• Same drag trends as above
• Same to watch mud volume as you fill
• Once on bottom and circulate the mud, do you see gas cut
mud?
Should the MW or YP be adjusted? 10
Hole Trends
• Cuttings Trends
• The cuttings over the shakers can tell you the most about what
is
going on downhole
• The amount, size, and shape of the cuttings
• The formation lithology being drilled can be identified
• Background gas coming to surface
11
Torque & Drag Modeling

12
• T&D modeling is an essential step in planning for horizontal
wells.
• Optimum drilling parameters can be estimated and
simulations can be evaluated to predict if/when drill pipe
buckling and/or failure may occur
• Sinusoidal Buckling
• Helical Buckling
• Tensional Yield Failure
• Torsional Yield Failure
• Occasional Sinusoidal Buckling is
a common phenomenon while
drilling Horizontal wells.
• Helical Buckling is dangerous and
will cause fatigue and failure
much quicker
• https://www.youtube.com/w
atch?v=4gTaEyx8aTE
T&D Example
13
14

Drilling Production
Curve/Lateral
Planned Drilling T&D
Model w/ sensitivity FF
15
Planned Casing Run
with sensitivity FF
16
T&D Model with PU/SO data
while drilling
-What open hole friction
factor is this well trending?
17
T&D Model with TOH data
after well was TD’d
-Now what open hole friction
factor can be interpreted?
18

Running Production Casing Plan
-How much should the driller see
on the weight indicator at TD
while running casing?
Stuck Pipe
• Causes of Stuck Pipe
• Differentially Sticking
• Requirements: Permeable formation, High Differential
pressure, Wall
contact by the drill string, lack of pipe movement, mud
properties to
form a mud cake
• Formation Related Stuck Pipe
• Sloughing shales, Fractured shales, Clay/Shale swelling,Salts
• Mechanically Related Stuck Pipe
• Doglegs, Keyseats
• Cutting beds
• Wash out sections
• Junk downhole
19

Freeing Stuck Pipe
• Drill String Data (in order from surface to TD)
• 7000’ DP, 5”, 19.5ppf, Grade S-135, XH
• 5000’ DP, 5”, 19.5ppf, Grade E-75, XH
• 720’ DC, 6-1/2” X 3-13/16”
• Mud
• MW= 14ppg;
• �� =
65.44−14
65.44
= 0.786
20
Freeing Stuck Pipe
1. Calculate air weight of the string
• Adjusted weights from charts
• DP, S-135: 22.60#/ft * 7000ft = 158,200
• DP, E-75: 20.89#/ft * 5000ft = 104,450
• DC: 91#/ft * 720ft = 63,700

�� = 326,350 ��
21
Freeing Stuck Pipe
2. Calculate weight indicator weight if the blocks weigh
100,000 lbs
�� = �� ∗ �� + ��
�� = 326,350 ∗ 0.786 + 100,000 = 356,511 ��
Summary:
�� = 326,350 ��
�� = 356,511 ��
22
Freeing Stuck Pipe
3. Calculate volume of mud required to pull out of hole
• You can look up the pipe displacement in charts for each
section
of pipe, or you can estimate by using the following:
• Steel weighs 2,748 lbs/bbl
�� = �

��
2748
�� =
326,350
2748
= 118.8 ��
23
Freeing Stuck Pipe
4. Calculate the estimated stuck point ESP
1. Pull ½ of MOP = 50,000 lbs
2. Mark the pipe
3. Pull an additional 40,000 lbs
4. Measure the stretch, e in inches; use 37.5” for class example
5. Repeat to verify
• One size drill pipe
�� =
735,294 ∗ � ∗ ��
�
‘e’ is the stretch in inches, P is the differential pull in lbs

Obtain Plain End Weight from Table Q: New Drill Pipe
Dimensional Data
Plain End Weight: �� = ��
2 − ��2 ∗ 0.7854 ∗ 3.4
24
Freeing Stuck Pipe
�� =
735,294 ∗ � ∗ ��
�
�� =
735,294 ∗ 37.5 ∗ 17.93
40,000
= 12,360 ��
The estimated stuck point is in the drill collars
Summary:
�� = 326,350 ��
�� = 356,511 ��
�� = 118.8 ��
�� = 12,360 ��
25
Freeing Stuck Pipe

• If you cannot get circulation or rotation or pull the string free,
we can either:
• Mechanical Backoff: recover partial of the string with a
mechanical back off, then fish the remaining string.
• String Shot: try to recover as much of the string as possible,
then
either fish the remaining pipe or place a cement plug and go
around the fish.
• Wireline free point tools can be used to see torque, locate tool
joints, and find stuck point in a directional well
• Be sure not to back off near the casing shoe
26
Freeing Stuck Pipe
5. Calculate the back off weight BOW to make a mechanical
back off at 3,000 ft (note the grade of DP at 3,000ft).
��ℎ = � ∗ �� ∗ �� + ��
��ℎ = 3000 ∗ 22.60 ∗ 0.786 + 100,000
��ℎ@3000�� = 153,291 ��
Mechanical Back Off Procedure:
a) Put RH torque in DS with full indicator weight
b) Adjust weight to BOW_mech

c) Put LF torque in DS for back off (unscrew thread connection)
27
Fishing
• A fish is any unwanted object downhole in a wellbore
• Can occur during drilling, completion, or production phases
• Examples: twisted off bit or drill pipe, wrenches, tools, etc.
• Fishing Tools
• https://www.youtube.com/watch?v=7-WqVgksKtk
• Weatherford Drilling Jars
• https://www.youtube.com/watch?v=z3WdcSrfvDM
28
https://www.youtube.com/watch?v=z3WdcSrfvDM
Fishing
29
• Parted Pipe
• Twist off

• Washout
• Cyclic stress
Fishing
30
• Cable & wireline
• Running logs
• Setting plugs (completions)
Fishing Economics
• Engineers must quickly perform economics to determine the
path forward
• Call out a fishing service team and begin fishing operations
• Leave the fish where it is and sidetrack around it to finish
drilling
• Leave the fish where it is and produce the well at current
depth
• Plug and abandon the well
• Experience has great value in fishing
31

Fishing Economics
• Fishing Economics Decision Making
• This only considers the economics for the rig. What about for
the company and delayed production? 32
� =
� + ��
� + ��
,
D = # of days allowed to fish for a breakeven NPV
V = replacement value of fish ($)
��= Estimated cost to sidetrack ($)
R = daily cost of fishing tools and services ($/day)
��= daily rig operating cost ($/day)
PNGE 310: Drilling Engineering; Project #2 - Summer 2019
Due Date: 7/25/19
In groups of 2, you will design a casing and cementing plan for
a horizontal shale gas well. The proposed well
is located just outside of Morgantown, WV and has a planned
TD of 18,500ft MD (7,420ft TVD) in the Lower
Marcellus Shale. Utilize the provided geologic prognosis and

the WV DEP regulations on “Casing and
Cementing Standards” on eCampus to justify the setting depths
of each string of casing. The regulations will
also provide guidance on cementing standards such as top of
cement for each string. All casing should be
new, steel, and API certified. You are allowed to combine the
coal casing string and the freshwater casing
string in this area.
Casing:
Your design should include the following casing strings for the
proposed well: conductor, surface,
intermediate, and production. Specify the hole size that will be
drilled and to what depth. There should be at
least 1.5 inches of cement around the casing in the annular on
all sides (per regulations) and sufficient rat hole
below the casing (30-50ft). Provide the size & type of casing
you chose and to what depth it should be set.
The drift diameter must be larger than the next section bit size.
Provide any details of auxiliary equipment
utilized such as a float shoe or centralizers and their placement.
Be sure to check for casing failure against
burst & collapse during cementing, and consider the lifting
force on the casing after the cement is pumped.

The production casing will be perforated in the lateral and the
Lower Marcellus formation will be stimulated
(frac’d). The pressure gradient of the Marcellus is estimated at
0.86psi/ft. The fracture gradient is measured
to be 1.12psi/ft on an offset well. The burst rating of the
production casing must support at least 20% above
the anticipated fracture pressure.
Cement:
You should provide a plan for cementing each string of casing.
The plan should include the slurry volumes,
displacement volumes, total water required on site, the number
of sacks of cement, and how many hours you
will wait on the cement to cure (WOC) for each string of casing.
The conductor may be grouted, but all other
strings must utilize the displacement method.
Well Construction Diagram

Casing String
Density
[ppg]
Yield
[ft
3
/sk]
Mix
Water
[gal/sk]
500psi Time
[hr:mm]
70Bc
[hr:mm]
Conductor 15.6 1.197 5.247 7:04 3:47
Surface 15.6 1.197 5.247 7:04 3:47
Intermediate 14.8 1.39 6.73 5:27 2:38
Production 14.5 1.260 5.770 9:43 7:30
Cement Slurry Blends
Shallow oil/gas & saltwater

Geologic Prognosis
WELL: WVU#1 COUNTY & STATE: Monongalia County
LOCATION: Pad Elevation: 1085
Top Depth from
Ground Elevation
(TVD)
Formation Possible Show Coal Seam
Thickness (FEET)
Minable Coal
Seam
General Rock Type
0- 80
Zones of fill and shallow water
FRESH
WATER
399 Waynesburg #2 Seam
0.95 NO Coal

404 Waynesburg #1 Seam
FRESH
WATER
3.24 YES Coal
665 Sewickley Coal Seam
FRESH
WATER
6.18 YES Coal
753 Roof Coal Zone Seam
FRESH
WATER
4.20 YES Coal
758 Pittsburgh Coal Seam
FRESH
WATER
7.34 YES Coal
1598 Clarion
Sandstone
2320 Big Lime
Limestone
2411 Big Injun Top
SALT WATER Sandstone

2651 Big Injun Base
Grey Shale
3097 50 Foot
OIL & GAS Sandstone
3120 Nineveh Sand
OIL & GAS Sandstone
3233 Gordon
GAS / WATER Sandstone
3362 Fourth
GAS / WATER Sandstone
3407 Fifth
SALT WATER Sandstone
4861 Elk
Siltstone
6837 Rhinestreet
Grey Shale
7197 Burkett
Black Shale
7222 Tully
Limestone
7261 Hamilton
Grey Shale
7364 Upper Marcellus
GAS Black Shale

7400 Purcell
Limestone
7404 Middle Marcellus
GAS Black Shale
7416 Cherry Valley
Limestone
7418 Lower Marcellus
GAS Black Shale
7435 Onondaga
Limestone
O.D. Nominal Grade Collapse Body Wall I.D. Drift Diameter
(inch) Weight Pressure Yield (inch) (inch)
T & C (psi) 1000 lbs
lbs/ft PE STC LTC BTC STC LTC BTC API LSS
4.500 9.50 J-55 3310 4380 4380 101 152 0.205 4.090 3.965
4.500 9.50 K-55 3310 4380 4380 112 152 0.205 4.090 3.965
4.500 9.50 LS-65 3600 5180 5180 135 180 0.205 4.090 3.965
4.500 10.50 J-55 4010 4790 4790 4790 132 203 166 0.224 4.052
3.927

4.500 10.50 K-55 4010 4790 4790 4790 146 249 166 0.224
4.052 3.927
4.500 10.50 LS-65 4420 5660 5660 5660 154 231 195 0.224
4.000 3.927
4.500 11.60 J-55 4960 5350 5350 5350 5350 154 162 225 184
0.250 4.000 3.875
4.500 11.60 K-55 4960 5350 5350 5350 5350 170 180 277 184
0.250 4.000 3.875
4.500 11.60 LS-65 5560 6320 6320 6320 6320 179 188 256 217
0.250 4.000 3.875
4.500 11.60 L-80 6350 7780 7780 7780 212 291 267 0.250
4.000 3.875
4.500 11.60 HCL-80 8650 7780 7780 7780 223 312 267 0.250
4.000 3.875
4.500 11.60 N-80 6350 7780 7780 7780 223 304 267 0.250
4.000 3.875
4.500 11.60 HCN-80 8650 7780 7780 7780 223 312 267 0.250
4.000 3.875
4.500 11.60 C-90 6810 8750 8750 8750 223 309 300 0.250
4.000 3.875
4.500 11.60 S-95 8650 9240 9240 9240 245 338 317 0.250
4.000 3.875
4.500 11.60 T-95 7030 9240 9240 9240 234 325 317 0.250
4.000 3.875

4.500 11.60 C-95 7030 9240 9240 9240 234 325 317 0.250
4.000 3.875
4.500 11.60 HCP-110 8650 10690 10690 10690 279 385 367
0.250 4.000 3.875
4.500 11.60 P-110 7580 10690 10690 10690 279 385 367 0.250
4.000 3.875
4.500 13.50 LS-65 7300 7330 7330 7330 228 295 249 0.290
3.920 3.795
4.500 13.50 L-80 8540 9020 9020 9020 257 334 307 0.290
3.920 3.795
4.500 13.50 HCL-80 10380 9020 9020 9020 270 359 307 0.290
3.920 3.795
4.500 13.50 N-80 8540 9020 9020 9020 270 349 307 0.290
3.920 3.795
4.500 13.50 HCN-80 10380 9020 9020 9020 270 359 307 0.290
3.920 3.795
4.500 13.50 C-90 9300 10150 10150 10150 270 355 345 0.290
3.920 3.795
4.500 13.50 S-95 10380 10710 10710 10710 297 388 364 0.290
3.920 3.795
4.500 13.50 T-95 9660 10710 10710 10710 284 374 364 0.290
3.920 3.795
4.500 13.50 C-95 9660 10710 10710 10710 284 374 364 0.290
3.920 3.795

4.500 13.50 P-110 10680 12410 12410 12410 338 443 422 0.290
3.920 3.795
4.500 15.10 L-80 11090 10480 10480 10480 308 384 353 0.337
3.826 3.701
4.500 15.10 HCL-80 12330 10480 10480 9790 325 408 353
0.337 3.826 3.701
4.500 15.10 S-95 12330 12450 12450 11630 357 446 419 0.337
3.826 3.701
4.500 15.10 P-110 14350 14420 14420 13460 406 509 485 0.337
3.826 3.701
4.500 15.10 Q-125 15840 16380 16380 15300 438 554 551
0.337 3.826 3.701
4.500 15.10 LS-140 17240 18350 18350 17140 487 616 617
0.337 3.826 3.701
4.500 15.10 V-150 18110 19660 19660 18360 519 658 661
0.337 3.826 3.701
5.000 11.50 J-55 3060 4240 4240 133 182 0.220 4.560 4.435
5.000 11.50 K-55 3060 4240 4240 147 182 0.220 4.560 4.435
5.000 11.50 LS-65 3290 5010 5010 162 215 0.220 4.560 4.435
5.000 14.00 J-55 3120 4270 4270 172 222 0.244 5.012 4.887
5.000 14.00 K-55 3120 4270 4270 189 222 0.244 5.012 4.887
5.000 14.00 LS-65 3360 5050 5050 200 262 0.244 5.012 4.887

5.000 13.00 J-55 4140 4870 4870 4870 4870 169 182 252 208
0.253 4.494 4.369
5.000 13.00 K-55 4140 4870 4870 4870 4870 186 201 309 208
0.253 4.494 4.369
5.000 13.00 LS-65 4590 5760 5760 5760 5760 196 212 288 245
0.253 4.494 4.369
5.000 15.00 J-55 5560 5700 5700 5700 5700 207 223 293 241
0.296 4.408 4.283
5.000 15.00 K-55 5560 5700 5700 5700 5700 228 246 359 241
0.296 4.408 4.283
5.000 15.00 LS-65 6280 6730 6730 6730 6730 240 259 334 284
0.296 4.408 4.283
5.000 15.00 L-80 7250 8290 8290 8290 295 379 350 0.296
4.408 4.283
5.000 15.00 HCL-80 9380 8290 8290 8290 311 408 350 0.296
4.408 4.283
5.000 15.00 N-80 7250 8290 8290 8290 311 396 350 0.296
4.408 4.283
5.000 15.00 HCN-80 9380 8290 8290 8290 311 408 350 0.296
4.408 4.283
5.000 15.00 C-90 7840 9320 9320 9320 311 404 394 0.296
4.408 4.283
5.000 15.00 S-95 9380 9840 9840 9840 342 441 416 0.296
4.408 4.283

5.000 15.00 T-95 8110 9840 9840 9840 326 424 416 0.296
4.408 4.283
5.000 15.00 C-95 8110 9840 9840 9840 326 424 416 0.296
4.408 4.283
5.000 15.00 P-110 8850 11400 11400 11400 388 503 481 0.296
4.408 4.283
5.000 15.00 V-150 10250 15540 15540 15540 497 651 656
0.296 4.408 4.283
5.000 18.00 LS-65 8730 8240 8240 8240 331 403 343 0.362
4.276 4.151
5.000 18.00 L-80 10500 10140 10140 9910 377 457 422 0.362
4.276 4.151
5.000 18.00 HCL-80 11880 10140 10140 9910 396 492 422
0.362 4.276 4.151
5.000 18.00 N-80 10500 10140 10140 9910 396 477 422 0.362
4.276 4.151
5.000 18.00 HCN-80 11880 10140 10140 9910 396 492 422
0.362 4.276 4.151
5.000 18.00 C-90 11530 11400 11400 11150 396 484 475 0.362
4.276 4.151
(inch)
Casing Data
Internal Yield Pressure Joint Strength
Minimum Yield (psi) 1000 lbs

(inch)
Casing Data
5.000 18.00 S-95 12030 12040 12040 11770 436 532 501 0.362
4.276 4.151
5.000 18.00 T-95 12030 12040 12040 11770 416 512 501 0.362
4.276 4.151
5.000 18.00 C-95 12030 12040 12040 11770 416 512 501 0.362
4.276 4.151
5.000 18.00 P-110 13470 13940 13940 13620 495 606 580 0.362
4.276 4.151
5.000 18.00 Q-125 14830 15840 15840 15480 535 661 659
0.362 4.276 4.151
5.000 18.00 LS-140 16080 17740 17740 17340 594 735 738
0.362 4.276 4.151
5.000 18.00 V-150 16860 19010 19010 18580 634 785 791
0.362 4.276 4.151

5.000 21.40 L-80 12760 12240 10810 9910 466 510 501 0.437
4.126 4.001
5.000 21.40 N-80 12760 12240 10810 9910 490 537 501 0.437
4.126 4.001
5.000 21.40 C-90 14360 13770 12170 11150 490 537 564 0.437
4.126 4.001
5.000 21.40 T-95 15160 14530 12840 11770 515 563 595 0.437
4.126 4.001
5.000 21.40 C-95 15160 14530 12840 11770 515 563 595 0.437
4.126 4.001
5.000 21.40 P-110 17550 16820 14870 13620 613 671 689 0.437
4.126 4.001
5.000 21.40 Q-125 19940 19120 16900 15480 662 724 783
0.437 4.126 4.001
5.000 23.20 L-80 13830 13380 10810 9910 513 510 543 0.478
4.044 3.919
5.000 23.20 HCL-80 15820 13380 10810 9910 540 516 543
0.478 4.044 3.919
5.000 23.20 N-80 13830 13380 10810 9910 540 537 543 0.478
4.044 3.919
5.000 23.20 HCN-80 15820 13380 10810 9910 540 537 543
0.478 4.044 3.919
5.000 23.20 C-90 15560 15060 12170 11150 540 537 611 0.478
4.044 3.919

5.000 23.20 S-95 16430 15890 12840 11770 594 590 645 0.478
4.044 3.919
5.000 23.20 T-95 16430 15890 12840 11770 567 563 645 0.478
4.044 3.919
5.000 23.20 C-95 16430 15890 12840 11770 567 563 645 0.478
4.044 3.919
5.000 23.20 P-110 19020 18400 14780 13626 675 671 747 0.478
4.044 3.919
5.000 23.20 Q-125 21620 20910 16900 15480 729 724 849
0.478 4.044 3.919
5.000 24.10 L-80 14400 14000 10810 9910 538 510 566 0.500
4.000 3.875
5.000 24.10 N-80 14400 14000 10810 9910 558 537 566 0.500
4.000 3.875
5.000 24.10 C-90 16200 15750 12170 11150 567 537 636 0.500
4.000 3.875
5.000 24.10 T-95 17100 16630 12840 11770 595 563 672 0.500
4.000 3.875
5.000 24.10 C-95 17100 16630 12840 11770 595 563 672 0.500
4.000 3.875
5.000 24.10 P-110 19800 19250 14870 13620 708 671 778 0.500
4.000 3.875
5.000 24.10 Q-125 22500 21880 16900 15480 765 724 884
0.500 4.000 3.875

5.000 24.10 V-150 27000 26250 20280 18580 907 858 1060
0.500 4.000 3.875
5.500 15.50 J-55 4040 4810 4810 4810 4810 202 217 300 248
0.275 4.950 4.825
5.500 15.50 K-55 4040 4810 4800 4810 4810 222 239 366 248
0.275 4.950 4.825
5.500 15.50 LS-65 4470 5690 5690 5690 5690 235 253 342 293
0.275 4.950 4.825
5.500 17.00 J-55 4910 5320 5320 5320 5320 229 247 329 273
0.304 4.892 4.767
5.500 17.00 K-55 4910 5320 5320 5320 5320 252 272 402 273
0.304 4.892 4.767
5.500 17.00 LS-65 5510 6290 6290 6290 6290 267 287 376 323
0.304 4.892 4.767
5.500 17.00 L-80 6390 7740 7740 7740 338 428 397 0.304
4.892 4.767
5.500 17.00 HCL-80 8580 7740 7740 7740 356 462 397 0.304
4.892 4.767
5.500 17.00 N-80 6390 7740 7740 7740 348 446 397 0.304
4.892 4.767
5.500 17.00 HCN-80 8580 7740 7740 7740 356 462 397 0.304
4.892 4.767
5.500 17.00 C-90 6740 8710 8710 8710 356 456 447 0.304
4.892 4.767

5.500 17.00 S-95 8580 9190 9190 9190 392 498 471 0.304
4.892 4.767
5.500 17.00 T-95 6940 9190 9190 9190 374 480 471 0.304
4.892 4.767
5.500 17.00 C-95 6940 9190 9190 9190 374 480 471 0.304
4.892 4.767
5.500 17.00 HCP-110 8580 10640 10640 10640 445 568 546
0.304 4.892 4.767
5.500 17.00 P-110 7480 10640 10640 10640 445 568 546 0.304
4.892 4.767
5.500 17.00 HCQ-125 8580 12090 12090 12090 481 620 620
0.304 4.892 4.767
5.500 17.00 Q-125 7890 12090 12090 12090 481 620 620 0.304
4.892 4.767
5.500 17.00 LS-140 8580 13540 13540 13540 534 690 695
0.304 4.892 4.767
5.500 20.00 LS-65 7540 7470 7470 7470 353 442 379 0.361
4.778 4.653
5.500 20.00 L-80 8830 9190 9190 8990 416 503 466 0.361
4.778 4.653
5.500 20.00 HCL-80 10630 9190 9190 8990 438 542 466 0.361
4.778 4.653
5.500 20.00 N-80 8830 9190 9190 8990 428 524 466 0.361
4.778 4.653

5.500 20.00 HCN-80 10630 9190 9190 8990 438 542 466 0.361
4.778 4.653
5.500 20.00 C-90 9630 10340 10340 10120 438 436 525 0.361
4.778 4.653
5.500 20.00 S-95 10630 10910 10910 10680 482 585 554 0.361
4.778 4.653
5.500 20.00 T-95 10010 10910 10910 10680 460 563 554 0.361
4.778 4.653
5.500 20.00 C-95 10010 10910 10910 10680 460 563 554 0.361
4.778 4.653
5.500 20.00 P-110 11100 12630 12630 12360 548 667 641 0.361
4.778 4.653
5.500 20.00 Q-125 12080 14360 14360 14050 592 728 729
0.361 4.778 4.653
5.500 20.00 LS-140 12950 16080 16080 15740 657 810 816
0.361 4.778 4.653
5.500 20.00 V-150 13460 17230 17230 16860 701 865 874
0.361 4.778 4.653
5.500 23.00 L-80 11160 10560 9880 8990 489 550 530 0.415
4.670 4.545

(inch)
Casing Data
5.500 23.00 HCL-80 12450 10560 9880 890 514 551 530 0.415
4.670 4.545
5.500 23.00 N-80 11160 10560 9880 8990 502 579 530 0.415
4.670 4.545
5.500 23.00 HCN-80 12450 10560 9880 8990 514 579 530 0.415
4.670 4.545
5.500 23.00 C-90 12380 11880 11110 10120 514 579 597 0.415
4.670 4.545
5.500 23.00 S-95 12940 12540 11730 10680 566 637 630 0.415
4.670 4.545
5.500 23.00 T-95 12940 12540 11730 10680 540 608 630 0.415
4.670 4.545
5.500 23.00 C-95 12940 12540 11730 10680 540 608 630 0.415
4.670 4.545
5.500 23.00 P-110 14540 14530 13580 12360 643 724 729 0.415
4.670 4.545
5.500 23.00 Q-125 16070 16510 15430 14050 694 782 829
0.415 4.670 4.545

5.500 23.00 LS-140 17500 18490 17290 15740 771 869 928
0.415 4.670 4.545
5.500 23.00 V-150 18390 19810 18520 16860 823 927 995
0.415 4.670 4.545
5.500 26.00 C-90 14240 13630 11110 10120 598 579 676 0.476
4.548 4.423
5.500 26.00 T-95 15030 14390 11730 10680 628 608 714 0.476
4.548 4.423
5.500 26.00 C-95 15030 14390 11730 10680 628 608 714 0.476
4.548 4.423
5.500 26.00 P-110 17400 16660 13580 12360 748 724 826 0.476
4.548 4.423
5.500 26.00 Q-125 19770 18930 15430 14050 808 782 939
0.476 4.548 4.423
5.500 26.00 V-150 23720 22720 18520 16860 957 927 1127
0.476 4.548 4.423
5.500 26.80 C-90 14880 14320 707 0.500 4.500 4.375
5.500 26.80 T-95 15700 15110 746 0.500 4.500 4.375
5.500 29.70 C-90 16510 16090 785 0.562 4.376 4.251
5.500 29.70 T-95 17430 16990 828 0.562 4.376 4.251
5.500 32.60 C-90 18130 17900 861 0.625 4.250 4.125
5.500 32.60 T-95 19140 18810 909 0.625 4.250 4.125

5.500 35.30 C-90 19680 19670 935 0.687 4.126 4.001
5.500 35.30 T-95 20760 20770 987 0.687 4.126 4.001
5.500 38.00 C-90 21200 21480 1007 0.750 4.000 3.875
5.500 38.00 T-95 22380 22670 1063 0.750 4.000 3.875
5.500 40.50 C-90 22650 23250 1076 0.812 3.876 3.751
5.500 40.50 T-95 23920 24540 1136 0.812 3.876 3.751
5.500 43.10 C-90 24080 25060 1144 0.875 3.750 3.625
5.500 43.10 T-95 25400 26450 1208 0.875 3.750 3.625
5.625 26.70 L-80 12420 11870 9880 8990 488 550 617 0.477
4.671 4.544
5.625 26.70 HCL-80 14750 11870 9880 8990 501 550 617 0.477
4.671 4.544
5.625 26.70 H2S-90 14750 13360 11110 10120 514 579 694
0.477 4.671 4.544
5.625 26.70 H2S-90 14750 14100 11730 10680 539 608 733
0.477 4.671 4.544
5.625 26.70 P-110 17080 16320 13580 12360 642 724 849 0.477
4.671 4.544
5.750 16.50 J-55 3720 4620 4620 314 234 0.276 5.198 5.073
5.750 18.10 J-55 4520 5090 5090 344 286 0.304 5.142 5.017

5.750 18.10 L-80 5700 7400 7400 447 416 0.304 5.142 5.017
5.750 18.10 N-80 5700 7400 7400 466 416 0.304 5.142 5.017
5.750 18.10 C-95 6380 8790 8790 502 494 0.304 5.142 5.017
5.750 18.10 P-110 6640 10180 10180 594 572 0.304 5.142
5.017
5.750 19.70 J-55 5410 5610 5610 377 313 0.335 5.080 4.955
5.750 19.70 L-80 7030 8160 8160 490 456 0.335 5.080 4.955
5.750 19.70 N-80 7030 8160 8160 511 456 0.335 5.080 4.955
5.750 19.70 C-95 7980 9690 9690 550 541 0.335 5.080 4.955
5.750 19.70 P-110 8530 11220 11220 651 627 0.335 5.080
4.955
5.750 21.80 L-80 8740 9130 9130 545 507 0.375 5.000 4.875
5.750 21.80 N-80 8740 9130 9130 568 507 0.375 5.000 4.875
5.750 21.80 C-95 10050 10840 10840 611 602 0.375 5.000
4.875
5.750 21.80 P-110 10960 12550 12550 723 697 0.375 5.000
4.875
5.750 24.20 L-80 10650 10230 10230 605 563 0.420 4.910
4.785
5.750 24.20 N-80 10650 10230 10230 630 563 0.420 4.910
4.785

5.750 24.20 C-95 12370 12140 12140 679 668 0.420 4.910
4.785
5.750 24.20 P-110 13700 14060 14060 803 774 0.420 4.910
4.785
6.625 20.00 H-40 2520 3040 3040 184 229 0.288 6.049 5.924
6.625 20.00 J-55 2970 4180 4180 4180 4180 245 266 374 315
0.288 6.049 5.924
6.625 20.00 K-55 2970 4180 4180 4180 4180 267 290 453 315
0.288 6.049 5.924
6.625 20.00 LS-65 3190 4940 4940 4940 4940 285 309 428 373
0.288 6.049 5.924
6.625 24.00 J-55 4560 5110 5110 5110 5110 314 340 453 382
0.352 5.921 5.796
6.625 24.00 K-55 4560 5110 5110 5110 5110 342 372 548 382
0.352 5.921 5.796
6.625 24.00 LS-65 5080 6040 6040 6040 6040 366 397 518 451
0.352 5.921 5.796
6.625 24.00 L-80 5760 7440 7440 7440 473 592 555 0.352
5.921 5.796

(inch)
Casing Data
6.625 24.00 N-80 5760 7440 7440 7440 481 615 555 0.352
5.921 5.796
6.625 24.00 C-90 6140 8370 8370 8370 520 633 624 0.352
5.921 5.796
6.625 24.00 C-95 6310 8830 8830 8830 546 665 659 0.352
5.921 5.796
6.625 24.00 P-110 6730 10230 10230 10230 641 786 763 0.352
5.921 5.796
6.625 28.00 LS-65 7010 7160 7160 7160 483 607 529 0.417
5.791 5.666
6.625 28.00 L-80 8170 8810 8810 8810 576 693 651 0.417
5.791 5.666
6.625 28.00 N-80 8170 8810 8810 8810 586 721 651 0.417
5.791 5.666
6.625 28.00 C-90 8880 9910 9910 9910 633 742 732 0.417
5.791 5.666
6.625 28.00 C-95 9220 10460 10460 10460 665 780 773 0.417
5.791 5.666
6.625 28.00 P-110 10160 12120 12120 12120 781 922 895 0.417

5.791 5.666
6.625 32.00 L-80 10320 10040 10040 9820 666 783 734 0.475
5.675 5.550
6.625 32.00 N-80 10320 10040 10040 9820 677 814 734 0.475
5.675 5.550
6.625 32.00 C-90 11330 11290 11290 11050 732 837 826 0.475
5.675 5.550
6.625 32.00 C-95 11810 11920 11920 11660 769 880 872 0.475
5.675 5.550
6.625 32.00 P-110 13220 13800 13800 13500 904 1040 1009
0.475 5.675 5.550
6.625 32.00 Q-125 14530 15680 15680 15340 989 1138 1147
0.475 5.675 5.550
7.000 20.00 H-40 1970 2720 2720 176 230 0.272 6.456 6.331
7.000 20.00 J-55 2270 3740 3740 3740 3740 234 257 373 316
0.272 6.456 6.331
7.000 20.00 K-55 2270 3740 3740 3740 3740 254 281 451 316
0.272 6.456 6.331
7.000 20.00 LS-65 2480 4420 4420 4420 4420 272 300 427 374
0.272 6.456 6.331
7.000 23.00 J-55 3270 4360 4360 4360 4360 284 313 432 366
0.317 6.366 6.241 6.250
7.000 23.00 K-55 3270 4360 4360 4360 4360 309 341 522 366
0.317 6.366 6.241 6.250

7.000 23.00 LS-65 3540 5150 5150 5150 5150 331 364 494 433
0.317 6.366 6.241 6.250
7.000 23.00 L-80 3830 6340 6340 6340 435 565 532 0.317
6.366 6.241 6.250
7.000 23.00 HCL-80 5650 6340 6340 6340 485 614 532 0.317
6.366 6.241 6.250
7.000 23.00 N-80 3830 6340 6340 6340 442 588 532 0.317
6.366 6.241 6.250
7.000 23.00 HCN-80 5650 6340 6340 6340 485 614 532 0.317
6.366 6.241 6.250
7.000 23.00 C-90 4030 7130 7130 7130 479 605 599 0.317
6.366 6.241 6.250
7.000 23.00 H2S-90 5650 7130 7130 7130 485 614 599 0.317
6.366 6.241 6.250
7.000 23.00 S-95 5650 7530 7530 7530 512 659 632 0.317
6.366 6.241 6.250
7.000 23.00 T-95 4140 7530 7530 7530 505 636 632 0.317
6.366 6.241 6.250
7.000 23.00 H2S-95 5650 7530 7530 7530 505 636 632 0.317
6.366 6.241 6.250
7.000 23.00 C-95 4140 7530 7530 7530 505 636 632 0.317
6.366 6.241 6.250
7.000 26.00 J-55 4320 4980 4980 4980 4980 334 367 490 415
0.362 6.276 6.151

7.000 26.00 K-55 4320 4980 4980 4980 4980 364 401 592 415
0.362 6.276 6.151
7.000 26.00 LS-65 4800 5880 5880 5880 5880 389 428 561 491
0.362 6.276 6.151
7.000 26.00 L-80 5410 7240 7240 7240 511 641 604 0.362
6.276 6.151
7.000 26.00 HCL-80 7800 7240 7240 7240 570 696 604 0.362
6.276 6.151
7.000 26.00 N-80 5410 7240 7240 7240 519 667 604 0.362
6.276 6.151
7.000 26.00 HCN-80 7800 7240 7240 7240 570 696 604 0.362
6.276 6.151
7.000 26.00 C-90 5740 8140 8140 8140 563 687 679 0.362
6.276 6.151
7.000 26.00 H2S-90 7800 8150 8150 8150 570 696 679 0.362
6.276 6.151
7.000 26.00 S-95 7800 8600 8600 8600 602 747 717 0.362
6.276 6.151
7.000 26.00 T-95 5880 8600 8600 8600 593 722 717 0.362
6.276 6.151
7.000 26.00 H2S-95 7800 8600 8600 8600 593 722 717 0.362
6.276 6.151
7.000 26.00 C-95 5880 8600 8600 8600 593 722 717 0.362
6.276 6.151

7.000 26.00 HCP-110 7800 9950 9950 9950 693 853 830 0.362
6.276 6.151
7.000 26.00 P-110 6230 9950 9950 9950 639 853 830 0.362
6.276 6.151
7.000 29.00 LS-65 6090 6630 6630 6630 492 628 549 0.408
6.184 6.059
7.000 29.00 L-80 7020 8160 8160 8160 587 718 676 0.408
6.184 6.059
7.000 29.00 HCL-80 9200 8160 8160 8160 655 780 676 0.408
6.184 6.059
7.000 29.00 N-80 7020 8160 8160 8160 597 746 676 0.408
6.184 6.059
7.000 29.00 HCN-80 9200 8160 8160 8160 655 780 676 0.408
6.184 6.059
7.000 29.00 C-90 7580 9180 9180 9180 648 768 760 0.408
6.184 6.059
7.000 29.00 H2S-90 9200 9180 9180 9180 655 780 760 0.408
6.184 6.059
7.000 29.00 S-95 9200 9690 9690 9690 692 836 803 0.408
6.184 6.059
7.000 29.00 T-95 7830 9690 9690 9690 683 808 803 0.408
6.184 6.059
7.000 29.00 H2S-95 9200 9690 9690 9690 683 8080 803 0.408
6.184 6.059

7.000 29.00 C-95 7830 9690 9690 9690 683 808 803 0.408
6.184 6.059
7.000 29.00 HCP-110 9200 11220 11220 11220 797 955 929
0.408 6.184 6.059
7.000 29.00 P-110 8530 11220 11220 11220 797 955 929 0.408
6.184 6.059
7.000 29.00 HCQ-125 9200 12750 12750 12750 885 1045 1056
0.408 6.184 6.059
7.000 29.00 Q-125 9100 12750 12750 12750 885 1045 1056
0.408 6.184 6.059
7.000 29.00 V-150 9790 15300 15300 15300 1049 1243 1267
0.408 6.184 6.059
7.000 32.00 L-80 8610 9060 9060 8460 661 791 745 0.453
6.094 5.969 6.000
(inch)
Casing Data

7.000 32.00 HCL-80 10400 9060 9060 8460 738 832 745 0.453
6.094 5.969 6.000
7.000 32.00 N-80 8610 9060 9060 8460 672 823 745 0.453
6.094 5.969 6.000
7.000 32.00 HCN-80 10400 9060 9060 8460 738 860 745 0.453
6.094 5.969 6.000
7.000 32.00 C-90 9380 10190 10190 9520 729 847 839 0.453
6.094 5.969 6.000
7.000 32.00 H2S-90 10400 10190 10190 9520 738 860 839
0.453 6.094 5.969 6.000
7.000 32.00 S-95 10400 10760 10760 10050 779 922 885 0.453
6.094 5.969 6.000
7.000 32.00 T-95 9750 10760 10760 10050 768 891 885 0.453
6.094 5.969 6.000
7.000 32.00 H2S-95 10400 10760 10760 10050 768 891 885
0.453 6.094 5.969 6.000
7.000 32.00 C-95 9750 10760 10760 10050 768 891 885 0.453
6.094 5.969 6.000
7.000 32.00 P-110 10780 12460 12460 11640 897 1053 1025
0.453 6.094 5.969 6.000
7.000 32.00 Q-125 11720 14160 14160 13220 996 1152 1165
0.453 6.094 5.969 6.000
7.000 32.00 LS-140 12540 15850 15850 14810 1107 1283 1304
0.453 6.094 5.969 6.000

PNGE 310Class 21Overbalanced Drilling• Mos.docx

PNGE 310Class 21Overbalanced Drilling• Mos.docx

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PNGE 310Class 21Overbalanced Drilling• Mos.docx