Casing and Cement Course
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Transcript of Casing and Cement Course
-
1Course IntroductionCourse Introduction
Chapter 1
1 - 2
Course Objectives ICourse Objectives I
Acquire Foundation Level Skills: Casing Depth Selection Size Selection Load Determination Preliminary Casing Design Final Casing Design Casing Running and Landing Practices
-
21 - 3
Course Objectives IICourse Objectives II Acquire Foundation Level Skills: Cementing
Types of Cement and Testing Cementing Equipment Primary Cementing
Casing and Liner Cementing Displacement of Mud Stage Cementing
Special Cementing Operations Squeezing Plugs
1 - 4
The Course ManualThe Course Manual
Same sequence as course Casing Cementing
First printing contains typos Please help me find all the errors CD copy of manual with color illustrations
-
31 - 5
Course MaterialsCourse Materials One PC per two participants MS Excel spreadsheets Graph paper Calculator participant furnished You will be given a CD:
Excel Spreadsheet Manual (in color) Slides (in color) Extras (Schlumber & Halliburton Cementing & Data
Handbooks)
1 - 6
Calculations & FormulasCalculations & Formulas
Casing design & cementing require calculations & formulas
Calculations are only learned and understood if done manually
Computers will be used after we learn the manual process
-
41 - 7
Units of MeasureUnits of Measure Typical oilfield units
in., ft, gal., bbl, lb, ppg, psi, etc. Not a good system, but prevalent in most of the world
and SPE literature Conversion Factors
Chapter 12 of manual Formulas
Conversion factors confuse formulas Most formulas here do not contain conversion factors We will show where they are needed
1 - 8
Quick Review of CasingQuick Review of Casing
Primary Purpose: maintain borehole integrity Prevent collapse Prevent fracture Contain formation fluids
Secondary Purpose: Sometimes support wellhead, other strings of
pipe, and even platform, i.e., structural role
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51 - 9
API CasingAPI Casing Many Sizes: 4 in, 5 in, 5 in, 7 in, 7 5/8
in, 8 5/8 in, 9 5/8 in, 10 in, 13 3/8 in, 16 in, 20 in, 24 in, and more
Various weights: 26 lb/ft, 47 lb/ft, etc. Nominal weight includes couplings Nominal weight is calculated with 20 ft joints
and API couplings Nominal weight is never the actual weight of
the pipe
1 - 10
API CasingAPI Casing Grade (Yield Strength): H40, J55, K55,
M65, L80, N80, C90, C95, T95, P110, Q125
Connection: 8rd ST&C, 8rd LT&C, Buttress, Extreme Line (X-line)
Length: Range 1: 16 to 25 ft Range 2: 25 to 34 ft Range 3: 34 ft and longer
-
61 - 11
Proprietary CasingProprietary Casing Uses:
High pressures, high tensile and collapse loads Corrosive applications Special clearance problems
Proprietary Connections Usually API except for connections Special sizes Special purpose alloys Special wall thicknesses
1 - 12
Casing ApplicationsCasing Applications
Conductor Surface casing Intermediate casing Production casing Drilling liner Production liner Tie-back casing
-
71 - 13
Cementing ReviewCementing Review
Purpose: Seal the annular space between casing and wellbore wall Isolate formations Support casing
Types of Cement API Classes: A, B, C, G, H (D,E,F,J ?) Special Cements: Pozzolans, Lightweight,
foam cement, latex, fine particle, etc.
1 - 14
CementingCementing Tests:
Thickening time Compressive strengths Water loss Free Water Other
Cementing Equipment Float equipment Stage tools Centralizers Squeeze tools Mixing & pumping equipment
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81 - 15
Cementing ApplicationsCementing Applications
Primary Cementing Casing strings (conductor, surface,
intermediate, production, tie-back) Liners (drilling, production) Multistage cementing
Remedial Applications Squeezes Plugs
1 - 16
Basic CalculationsBasic Calculations
You should already understand: Basic hydrostatics Basic hydrostatic calculations in a wellbore
Hydrostatic pressure Uniform in all directions at a point Can only act perpendicular to a surface
-
91 - 17
Hydrostatic Pressure ExampleHydrostatic Pressure Example
Tube at 10,000 ft 2 inch diameter Seals on bottom free
to move in packer Air in annulus A 8.4 ppg water in B Which tube weighs
more at the surface? A? B? Same?
A B
1 - 18
Hydrostatic PressureHydrostatic Pressure Calculate pressure at
10500 ft Learn the 0.052
conversion factor
( ) ( )psi/ft12.5 ppg 0.052 10500 ftppg
6825 psi
p
p
= =
-
10
1 - 19
Hydrostatic Pressure 2Hydrostatic Pressure 2 Calculate hydrostatic
pressure at 10500 ft
( ) ( ) ( )psi/ft12.5 ppg 0.052 10500 ft 1100 psippg
7925 psi
p
p
= +=
1 - 20
Hydrostatic Differential PressureHydrostatic Differential Pressure
( ) ( ) ( )( ) ( )
psi/ft12.5 ppg 0.052 10500 ft 1100 psippg
10500 ft
3011 psi
psi/ft9.0 ppg 0.052ppg
p
p
= +
=
Calculate static surface tubing pressure
-
11
1 - 21
The U-Tube MethodThe U-Tube Method You can always use
a U-tube schematic to visualize and calculate hydrostatic pressures
The column on the left must balance the column on the right
1 - 22
Gas CalculationsGas Calculations
Gas density depends on Type of gas Pressure Temperature
Density varies with depth We will use methane
Molecular weight 16 Compressibility factor, z = 1 (approximately)
-
12
1 - 23
A Simple Gas FormulaA Simple Gas Formula
( )2 1
161544 460
g
LT
g
p p f
f e +
=
=
1 - 24
Beware of the VacuumBeware of the Vacuum
Cannot cause casing collapse Cannot suspend a column of liquid in an
annulus (maximum of 34 ft of water) A vacuum is about 15 psi less than
atmospheric pressure
15 psi15 psi
-
13
1 - 25
It looks easy.I am ready!
1 - 26
-
14
1 - 27
1 - 28
-
1Casing Depth SelectionCasing Depth Selection
Chapter 2
2 - 2
Casing StringDepths
Casing StringDepths
-
22 - 3
Casing Depth CriteriaCasing Depth Criteria
Formation pore pressures Formation fracture pressures Borehole stability problems Regulations Accepted practice for an area or field
based on successful experience
2 - 4
Conductor CasingConductor Casing
One or two conductor strings Provide borehole integrity for drilling
surface hole Support wellhead and more in some cases Typical Depths: 50 ft to 500 ft Criteria for Depth Selection:
Common practice in area Soil tests
-
32 - 5
Surface CasingSurface Casing
Provides initial pressure control Protects fresh water aquifers Depth Selection Criteria:
Regulations Pore pressures & fracture pressures Depth of next casing string
2 - 6
Intermediate CasingIntermediate Casing Provides borehole integrity and pressure control Used when mud densities must increase above
frac pressures of shallower zones Used when mud densities must decrease below
pore pressures of shallower zones Depth Selection Criteria:
Pore pressures & fracture pressures Borehole stability problems Depth of next casing
-
42 - 7
Production CasingProduction Casing
Provides full pressure protection for the entire wellbore
A backup for the tubing Depth Selection Criteria:
Depth of producing interval Possible future completions in wellbore
2 - 8
Liners & Tie-backsLiners & Tie-backs
Liners and tie-backs are extensions of other casing strings
Depth selection criteria: Same as the string they are extending Usually pore pressure and fracture pressure
are significant factors
-
52 - 9
Using Pore and Fracture Pressures
Using Pore and Fracture Pressures
Plot the pore pressure and fracture pressuresCasing Setting Depth Chart
0
2000
4000
6000
8000
10000
12000
14000
8 9 10 11 12 13 14 15 16 17 18 19 20
Equivalent Mud Density (ppg)
True
Ver
tical
Dep
th (f
t)
Pore PressureFrac Press
2 - 10
Add Safety MarginsAdd Safety MarginsCasing Setting Depth Chart
0
2000
4000
6000
8000
10000
12000
14000
8 9 10 11 12 13 14 15 16 17 18 19 20
Equivalent Mud Density (ppg)
True
Ver
tical
Dep
th (f
t)
Pore PressureMud DensityFrac PressKick Marg
-
62 - 11
Determine Casing DepthsDetermine Casing DepthsCasing Setting Depth Chart
0
2000
4000
6000
8000
10000
12000
14000
8 9 10 11 12 13 14 15 16 17 18 19 20
Equivalent Mud Density (ppg)
True
Ver
tical
Dep
th (f
t)
Pore PressureMud DensityFrac PressKick Marg
a
cb
2 - 12
Example Selecting DepthsExample Selecting Depths
Start at the bottom of the chart The maximum mud weight at bottom must
not exceed the fracture gradient at any point in the hole
At all points above about 1700 ft the maximum mud weight at bottom exceeds the fracture pressure (plus safety margin)
Select a casing point at 1700 ft
-
72 - 13
CommentsComments
That example was straight forward and easy
Most wells drilled in the world are exactly like that simple and easy
Many are not so simple
2 - 14
Another ExampleAnother ExampleCasing Setting Depth Chart
0
2000
4000
6000
8000
10000
12000
14000
16000
8 9 10 11 12 13 14 15 16 17 18 19 20
Equivalent Mud Density (ppg)
True
Ver
tical
Dep
th (f
t)
Pore PressureMud DensityFrac PressKick Marg
Fracture Pressure
Pore Pressure
-
82 - 15
ExampleExample
This well requires three strings of casing (plus conductor): Production casing: 14,000 ft ft Intermediate casing: 10,500 ft Surface casing: 3,000 ft
There are alternatives with a production liner or a production liner and tie-back
2 - 16
AlternativesAlternatives
-
92 - 17
DataData Pore pressures
Actual measurements Log data Known gradients in area
Fracture Pressures Actual measurements (leak-off tests, frac tests) Lost circulation problems Some log data Known gradients in area
2 - 18
Precautions About Frac PressurePrecautions About Frac Pressure
Fracture pressure often comes from a number of sources
They do not always measure the same thing Leak-off pressure is usually not the frac pressure Actual frac pressure depends on hole inclination Once fracture is initiated it will reopen at the
fracture closure pressure which is lower Fracture closure pressure is independent of
inclination Sands usually fracture at lower pressure than
nearby shales
-
10
2 - 19
Depth Selection from ExampleDepth Selection from Example
We will carry the last example forward into the following chapters to use for our design examples
Surface Casing: 3,000 ft Intermediate Casing: 10,500 ft Production Casing: 14,000 ft
2 - 20
-
1Casing Size SelectionCasing Size Selection
Chapter 3
3 - 2
Selecting Casing SizeSelecting Casing Size
Hole size determines casing size Hole size is determined from the previous
string of casing run
This means we determine the size of the bottom string and
work back to the top*
This means we determine the size of the bottom string and
work back to the top*
* The completions engineers normally specify the size of the production casing or liner
-
23 - 3
Initial Borehole SizeInitial Borehole Size Determine the borehole size that will allow the bottom
casing enough clearance There are no formulas for this It is strictly a matter of local experience Once the bottom borehole size and casing size are
determined it is a matter of working back to the surface The next bit size is selected to provide enough clearance
for the casing string run in the hole it drills The next casing size is determined by size of the
preceding bit.
3 - 4
Casing & Hole SizesCasing & Hole Sizes
For given areas and formation types there are typical hole sizes and casing sizes that have been successful
Hole size should have wide selection of bits unless some special case requires an uncommon size
Rule of thumb: Hard rock usually requires less clearance than soft rock
-
33 - 5
Typical Hard Rock Sizes
Typical Hard Rock Sizes
3 - 6
Typical Soft Rock Sizes
Typical Soft Rock Sizes
-
43 - 7
Many PossibilitiesMany Possibilities Charts are only guides; they are not standards Local experience always overrides such charts Special clearance couplings or special bits may
be necessary for heavier weights of pipe Never make the mistake of thinking a soft rock
area will be washed out enough to run a larger size casing than such charts for the area show
3 - 8
Our ExampleOur Example Our completion engineers specify 7 inch
production casing We are in an unconsolidated formation
area and use the soft rock chart We select:
7 in. production casing (14,000 ft) 9 5/8 in. intermediate casing (10,500 ft) 13 3/8 in. surface casing (3,000 ft) 20 in. conductor (150 ft)
-
53 - 9
AlternativeAlternative Although it does not appear on the chart
another common program in unconsolidated rock is: 7 in. production casing 10 in. intermediate casing 16 in. surface casing 24 in. conductor
This gives us more flexibility for hole problems at a higher cost
3 - 10
Precaution!Precaution!
After the final casing design has been completed make sure that the drift
diameter of all casing in the string is larger than the bit that will pass through it. If
not, determine if the bit is smaller than the nominal internal diameter. If so, the pipe
may be specially drifted for the bit. Otherwise, either the casing design or the
bit size must be changed.
-
63 - 11
Casing Size PhilosophyCasing Size Philosophy Smaller is cheaper Larger allows more options Rule of thumb:
Exploratory wells have unknown risks, allow for contingencies
Production wells have known risks, minimize costs
3 - 12
AlternativesAlternatives
Enlarged hole Under ream Bi-center bits
Expandable casing
-
73 - 13
Expandable Open Hole LinerExpandable Open Hole Liner
3 - 14
Some DrawbacksSome Drawbacks
Pipe or couplings can split Cement placed before expansion Expansion tolls can stick in pipe Expanded casing has low collapse rating Product not readily available on short
notice
-
83 - 15
An exploration well that does not produce a log of the
objective, is a total failure.
3 - 16
-
1Casing Load DeterminationCasing Load Determination
Chapter 4
4 - 2
Loads on CasingLoads on Casing Collapse Loads external pressure
Dependent on the well Burst Loads internal pressure
Dependent on the well Tension (axial) Loads gravitational
forces and borehole friction Dependent on the casing string (gravity and
friction) Dependent on the well (friction)
-
24 - 3
Design LoadsDesign Loads Surface Casing
Internal pressure External pressure Axial load
Intermediate Casing Internal pressure External pressure Axial load
Production Casing Internal pressure External pressure Axial load
4 - 4
Axial LoadingAxial Loading
Axial loading is dependent on the actual casing selection. The axial loads cannot be
determined until a preliminary casing selection is made.
Axial loading is dependent on the actual casing selection. The axial loads cannot be
determined until a preliminary casing selection is made.
-
34 - 5
Surface Casing CollapseSurface Casing Collapse Severe lost circulation loading
External pressure: mud pressure when run Internal pressure: atmospheric pressure
Lost circulation loading External pressure: mud pressure when run Internal pressure: partial mud column
Cementing loading External pressure: full cement column Internal pressure: fresh water or displacement fluid
4 - 6
Surface Casing CollapseSurface Casing Collapse Severe Lost
Circulation Load Air in casing Original mud on
outside
-
44 - 7
Surface Casing CollapseSurface Casing Collapse Lost Circulation Load
Original mud outside Current mud inside at
level determined by lost circulation down hole
4 - 8
Surface Casing CollapseSurface Casing Collapse Cement load
Fresh water inside Unset cement
outside
-
54 - 9
ExampleExample Surface casing depth: 3000 ft Mud density: 9.2 ppg Use severe lost circulation loading (air/mud)
( )( )0.052 9.2 3000 01440 psi
o ip p ppp
= = =
4 - 10
Surface Casing BurstSurface Casing Burst Pressure control loading, gas
External pressure: fresh water gradient Internal pressure: full gas column with injection at
casing shoe Pressure control loading, oil
External pressure: fresh water gradient Internal pressure: oil column with injection at the
casing shoe Alternate loading
External pressure: formation pore pressure Internal loading: either of the above
-
64 - 11
Surface Casing Burst LoadSurface Casing Burst Load Pressure Control
Gas inside Pressure
determined by injection into weak zone below shoe
Fresh water on outside
4 - 12
Example - BurstExample - Burst Surface casing depth: 3000 ft Gas inside, fresh water outside Fracture pressure at shoe: 12.3 ppg Assume 500 psi additional injection pressure Calculate differential pressure at shoe:
( )( ) ( )( )0.052 12.3 3000 500 0.052 8.3 30001120 psi
b f i e
b
b
p p p ppp
= + = + =
-
74 - 13
Example Gas CalculationsExample Gas Calculations Assume methane gas
inside Calculate gas
injection pressure at shoe
Average temperature is 101F
Calculate gas pressure at surface
( )( )22
0.052 12.3 3000 5002420 psi
pp
= +=
16(3000)1544(460 101)
1
1
24202290 psi
p ep
+==
4 - 14
Load CurveLoad CurveSurface Casing Load
0
500
1000
1500
2000
2500
3000
3500
0 500 1000 1500 2000 2500 3000
Pressure (psi)
Dep
th (f
t) Collapse LoadLine
Burst LoadLine
-
84 - 15
Intermediate Casing LoadsIntermediate Casing Loads
Collapse Load Essentially same as for surface casing Severe lost circulation with air inside entire
string is not likely for most Burst load
Full well pressure to surface Maximum load method
Surface equipment service pressure rating Fracture and injection below shoe
4 - 16
Example Intermediate CasingExample Intermediate Casing
Depth: 10,500 ft Pore pressure: 11.3 ppg Fracture pressure: 15.7 ppg Mud density: 11.8 Average borehole temperature: 200F Wellhead: 5000 psi maximum service
pressure (MSP)
-
94 - 17
Example: Intermediate CollapseExample: Intermediate Collapse
Assume: Fresh water inside Mud outside
Calculate net collapse pressure at shoe:
( )( )0.052 11.8 8.3 105001910 psi
c
c
pp
= =
4 - 18
Example Collapse LoadExample Collapse LoadIntermediate Casing Design
0
2000
4000
6000
8000
10000
12000
0 500 1000 1500 2000 2500 3000 3500 4000 4500 5000 5500 6000 6500 7000 7500 8000 8500 9000
Pressure (psi)
Dep
th (f
t)
Collapse LoadLine
-
10
4 - 19
Intermediate Casing BurstIntermediate Casing Burst
Several Different Methods Maximum Load Method (Prentice, 1969)
Fracture and injection occurs before BOP or casing failure
Surface pressure fixed by BOP MSP Bottom pressure fixed by formation fracture
pressure plus differential injection pressure Combination gas and mud column in casing
4 - 20
Maximum Burst LoadMaximum Burst LoadIntermediate Casing Design
Maximum Burst Determination
0
2000
4000
6000
8000
10000
12000
14000
0 500 1000 1500 2000 2500 3000 3500 4000 4500 5000 5500 6000 6500 7000 7500 8000 8500 9000 9500 10000
Pressure (psi)
Dep
th (f
t)
Mud
Formation Injection Pressure
(fixed)
BOP Max Pressure
(fixed)
Gas
Gas
Mud
After Prentice (1970)
Maximum Burst
Load Line
-
11
4 - 21
Example: Intermediate BurstExample: Intermediate Burst
Assume Wellhead MSP is maximum surface pressure Injection into formation at shoe Mud over gas column (maximum burst load)
Calculate mud and gas pressures:
4 - 22
Example: Intermediate BurstExample: Intermediate Burst
Formula to determine length of mud and gas columns
f i s gm
m g
f i s mg
g m
p p p g LL
g g
p p p g LLg g
+ = + =
-
12
4 - 23
Example: Intermediate BurstExample: Intermediate Burst
We need the gas gradient Assume the gas originates from the bottom,
14,000 ft (the worst case)
( )( )2 0.052 15.2 14000 11070 psip = =
4 - 24
16(14000)1544(660)
1
1
110708890 psi
p ep
==
11070 8890 0.16 psi/ft14000g
g = =
Full gas pressure at surface:
Average gas gradient:
(This is not good science; but it is close enough for casing design)
-
13
4 - 25
8570 500 5000 0.16(10500)0.79 0.16
3790 ft
m
m
L
L
+ = =
( )( )5000 0.052 15.2 37908000 psi
m
m
pp
= +=
Length of mud column on top:
Pressure of mud at 3790 ft:
4 - 26
8570 5009070 psi
d f i
d
d
p p ppp
= + = +=
( )( )( )( )
5000 0 5000 psi8000 0.052 8.3 3790 6360 psi
9070 0.052 8.3 10500 4540 psi
o
m
d
pp
p
= = = = = =
Pressure at shoe:
Net burst pressures at surface, bottom of mud, shoe:
-
14
4 - 27
Example: Intermediate LoadsExample: Intermediate LoadsIntermediate Casing Design
0
2000
4000
6000
8000
10000
12000
0 500 1000 1500 2000 2500 3000 3500 4000 4500 5000 5500 6000 6500 7000 7500 8000 8500 9000
Pressure (psi)
Dep
th (f
t)
Collapse LoadLine
Burst LoadLine
4 - 28
Example: Production Casing Loads
Example: Production Casing Loads
Casing Depth: 14,000 ft Pore pressure: 14.7 ppg Mud density: 15.2 Surface Temperature: 74F Bottom hole temperature: 336F
-
15
4 - 29
Example: Production Casing Collapse
Example: Production Casing Collapse
Assume: Mud on outside Inside empty (can happen with production
casing) Calculate net collapse pressure
( )( )0.052 15.2 14000 011070 psi
c
c
pp
= =
4 - 30
Example: Production Casing Burst
Example: Production Casing Burst
Assume Fresh water outside Gas inside
Calculate net burst at shoe
( )( )0.052 15.2 8.3 140005020 psi
d
d
pp
= =
-
16
4 - 31
Calculate net burst at top
( )( )
16 140001544 460 20011070 0
8890 psio
o
p ep
+ = =
4 - 32
Example: Production Casing Loads
Example: Production Casing Loads
Production Casing Load
0
2000
4000
6000
8000
10000
12000
14000
0 0.5 1 1.5 2 2.5 3 3.5 4 4.5 5 5.5 6 6.5 7 7.5 8 8.5 9 9.5 10 10.5 11 11.5 12
Pressure (1000 psi)
Dep
th (f
t)
Collapse LoadLine
Burst LoadLine
-
17
4 - 33
Another Burst SituationAnother Burst Situation
Weighted packer fluid (15.2 ppg) Gas in tubing (8890 psi at surface) Tubing leak at or near surface Gas on top of full mud column
5020 8890 13910 psidp = + =
4 - 34
Liners & Tie-backsLiners & Tie-backs Extensions of
attached strings Load is determined
for dual functions Most severe load
determines design
-
18
4 - 35
It is easier than it looks !
Time for us to start our class project.
4 - 36
-
1Preliminary Casing DesignPreliminary Casing Design
Chapter 5
5 - 2
Casing DesignCasing Design
We will use a manual procedure you cannot learn casing design from a casing design software package
We will use a two step procedure Preliminary design Final design
-
25 - 3
Design Safety FactorsDesign Safety Factors
No industry standards Typical range
Tension: 1.6 2.0 Collapse: 1.0 1.125 Burst: 1.0 1.25
Depends on load parameters May vary for different strings in same well Most companies have their own standards
5 - 4
Weights & GradesWeights & Grades Often presented a more than one weight
or grade that will satisfy design Example:
7 in. 26 lb/ft K-55Or 7 in. 23 lb/ft N-80Which is better?
Depends on: Cost? Wall thickness? Weight?
-
35 - 5
Design PitfallsDesign Pitfalls
Often the best design includes short sections of particular weights or grades
A short section can lead to problems, extra cross-over joints, and costs when running
Try to stay with sections 1000 ft + in length Absolute minimum should be 500 ft Keep your design simple it will save time
and money
5 - 6
ConnectionsConnections Many types to select from Opt for the simplest that will do the job
Less cost Standard crossovers No special float equipment or tools required
API ST&C, LT&C Industry standard, satisfactory for most wells Standard thread on most casing equipment May leak gas at high pressures
-
45 - 7
ConnectionsConnections API Buttress
Better joint strength Better pressure seal Easily to over-torque
API Extreme Line (integral joint connection) Best API joint strength Best API pressure seal More costly
5 - 8
Proprietary ConnectionsProprietary Connections Patented Connections Non-API, Standards set by manufacturer Usually higher joint strength and sealing
properties than API Higher torque ratings for some Special flush joint connections for liners Better corrosion performance with some Usually higher costs Not always better than API
-
55 - 9
Casing Performance PropertiesCasing Performance Properties
Most properties standardized by API Not all casing meets API standards Some proprietary tubes exceed API standards Typical performance properties for design
Collapse resistance, internal yield, joint strength Other properties
Corrosion resistance, leak resistance, torque resistance, bending performance, etc.
5 - 10
Table ValuesTable Values
Published values for Collapse resistance (collapse), psi Internal yield pressure (burst), psi Joint strength (tension), lb
API Bulletin 5C2 and other sources
-
65 - 11
API Bulletin 5C2API Bulletin 5C2
5 - 12
Design ProcedureDesign Procedure Select safety factors Use load curves (from previous chapter) Apply safety factor to load curves to get
design curves Use performance table values Select casing that will exceed design
curves Adjust design for combined loading (next
chapter)
-
75 - 13
ExampleExample
In all the examples in this course we will restrict our casing choices to API standard tubes with API ST&C and LT&C couplings
We do this to illustrate the design process by limiting the number of choices
We will do much of the process graphically to minimize the number of calculations
Example 5 - 14
Our Example So FarOur Example So Far Surface Casing: 13 3/8 in., 3,000 ft Intermediate Casing: 9 5/8 in., 10,500 ft Production Casing: 7 in., 14,000 ft Load curves: completed Next steps:
Select safety factors Add design line to load curves Select casing to satisfy design Do the axial load design
-
8Example - Surface Casing 5 - 15
Surface Casing Safety FactorsSurface Casing Safety Factors
Safety Factors:
1.6 or 100,000 lb
Tension
1.125Burst
1.125Collapse
Safety Factor for Example
Load Type
Example - Surface Casing 5 - 16
Available 13 3/8 CasingAvailable 13 3/8 Casing
10405380267012.347ST&CN-80729635020226012.415ST&CN-8068
K-55K-55K-55
Grade
ST&CST&CST&C
Conn.
7183450195012.415686333090154012.515615472730113012.61554.5
Joint Strength(1000 lb)
Burst(psi)
Collapse(psi)
ID(in.)
Wt(lb/ft)
-
95 - 17
Design LinesDesign LinesSurface Casing Load
0
500
1000
1500
2000
2500
3000
3500
0 500 1000 1500 2000 2500 3000
Pressure (psi)
Dep
th (f
t) Collapse LoadLine
Burst LoadLine
Collapse DesignLine
Burst DesignLine
5 - 18
Collapse Design MethodCollapse Design Method
Start with lowest weight and grade Plot its collapse value at the surface down
to the design line Shift to the next weight and grade Repeat until casing is at bottom
-
10
5 - 19
Collapse DesignCollapse DesignSurface Casing Design
0
500
1000
1500
2000
2500
3000
3500
0 500 1000 1500 2000 2500 3000 3500
Pressure (psi)
Dep
th (f
t) Collapse LoadLine
Collapse DesignLine
54.5 lbK55
68 lbK55
61 lbK55
5 - 20
ProblemProblem
The design shown will work It requires a 150 ft section of 68 lb/ft
casing on bottom This is not good practice Revise the design to eliminate the short
section on bottom
-
11
5 - 21
Collapse DesignCollapse DesignSurface Casing Design
0
500
1000
1500
2000
2500
3000
3500
0 500 1000 1500 2000 2500 3000 3500
Pressure (psi)
Dep
th (f
t) Collapse LoadLine
Collapse DesignLine
54.5 lbK55
68 lbK55
5 - 22
CommentComment
When a design like this calls for the heaviest pipe on bottom, it is
common practice to run one or two joints of the heavy pipe on top of the string also. This is to ensure that if any tools run in the hole will pass through the top of the casing they
should pass through all the casing. It can save time and money.
-
12
5 - 23
Surface Casing BurstSurface Casing Burst
Start by plotting the selected string on the burst design line to see how it works.
Adjust the design for burst if necessary
5 - 24
Burst DesignBurst DesignSurface Casing Design
0
500
1000
1500
2000
2500
3000
3500
0 500 1000 1500 2000 2500 3000 3500
Pressure (psi)
Dept
h (ft
) Collapse LoadLine
Burst LoadLine
Collapse DesignLine
Burst DesignLine
54.5 lbK55
68 lbK55
54.5 lbK55
68 lbK55
-
13
5 - 25
Comments on the Burst DesignComments on the Burst Design
The collapse selection needs no revision Selection is close to the burst design line
at the top If it had contacted the design line below
the top, we would have changed to a different weight or grade at the top
5 - 26
Axial Load TensionAxial Load Tension
Sources of axial load Gravitational forces (weight) Borehole friction (from pipe movement) Bending (in curved wellbores)
Design considerations Weight: in air, or buoyed weight ? Safety factor or over pull margin ? Borehole friction ?
-
14
5 - 27
Borehole FrictionBorehole Friction
Determining borehole friction requires Special software (or a lot of manual
calculations!) Directional surveys Friction load measurements while drilling Whether the pipe will be picked up off bottom
or not We will not consider it in this course
5 - 28
Safety Factor/Over PullSafety Factor/Over Pull Axial safety factor gives a percentage
margin above the load line more actual margin at the top than the bottom Typical safety factor for tension: 1.6 to 2.0
Over pull gives a set amount of margin above the load line it does not vary with depth Typical over pull margin: 100,000 lb
Often both are used in the same design
-
15
5 - 29
Axial LoadsAxial Loads
Unbuoyed axial load hanging in air Buoyed axial load hanging in mud
True axial load Effective axial load
5 - 30
Effective Axial LoadEffective Axial Load
Has valid uses (e.g. buckling) Calculated with buoyancy factor
effective axial load, lb length of casing, ft nominal weight of casing, lb/ft
1 buoyancy factor65.43
density of mud, ppg
e b
e
mb
m
P f w LwherePLw
f
=
==== ==
-
16
5 - 31
True Axial LoadTrue Axial Load Actual axial load in
pipe Calculated using
hydrostatics Requires more
calculations Formulas in manual
5 - 32
Comparison of Axial LoadsComparison of Axial LoadsAxial Load Curves
0
500
1000
1500
2000
2500
3000
3500
-50 0 50 100 150 200
Axial Load (1000 lb)
Dep
th (f
t)
Axial LoadUnbuoyed
Effective Axial Load
True Axial Load
-
17
5 - 33
Which to Use ?Which to Use ?
Un-buoyed axial load give larger safety margin
True axial load gives most accurate approximation of the actual loads in the casing
Effective axial load has no real use in casing design (but many still use it)
5 - 34
Surface Casing Tension DesignSurface Casing Tension Design
We will use the true axial load Safety factor of 1.6 or 100,000 lb over pull
whichever is a higher limit Start with the casing selection so far
2100 - 3000
0 - 2100
Interval(ft)
900
2100
Length(ft)
718K-55ST&C68
547K-55ST&C54.5
Jt Strength(1000 lb)
GradeCplgWeight(lb/ft)
-
18
5 - 35
Load Line and Design LineLoad Line and Design Line
See manual for actual calculations of load line
Apply a 1.6 safety factor (only works in tension loaded section)
Apply the 100,000 lb over pull line
5 - 36
Tension DesignTension DesignSurface Casing Axial Load
0
500
1000
1500
2000
2500
3000
3500
-150 -50 50 150 250 350 450 550 650 750
Axial Load (1000 lb)
Dep
th (f
t)
54.5 lb, K55ST&C
68 lb, K55ST&C
True Axial Load
Safety Factor = 1.6
100,000 lb over pull
-
19
5 - 37
Comments on Tension DesignComments on Tension Design
The over pull exceeded the safety factor at all points (for this case)
The collapse and burst design has ample strength in tension
Tension is seldom an issue for surface casing, but we go through the procedure to illustrate how it works
5 - 38
Summary of Surface Casing String
Summary of Surface Casing String
Casing Design Summary
13 3/8" Surface Casing
Collapse BurstJoint
Strength2 13.375 12.615 54.5 K-55 ST&C 2100 2100 114450 175650 1.125 1.128 3.61 13.375 12.415 68 K-55 ST&C 3000 900 61200 61200 1.359 1.916 26.135
0 0 00 0 00 0 00 0 00 0 00 0 0
Totals: 3000 175650
Minimum Safety Factors Mud Weight: 9.2Collapse: 1.125Burst: 1.125Tension: 1.6/100,000
Section Number OD ID Weight
Section Weight
Actual Design Factors
Cum. WeightGrade Connection Bottom Length
-
20
5 - 39
The Intermediate CasingThe Intermediate Casing
Proceed exactly as with the surface casing
We will use a different tension approach to illustrate a different method
1.8 in airTension
1.125Burst
1.125Collapse
Safety Factor for Example
Load Type
5 - 40
Design LinesDesign LinesIntermediate Casing Design
0
2000
4000
6000
8000
10000
12000
0 500 1000 1500 2000 2500 3000 3500 4000 4500 5000 5500 6000 6500 7000 7500 8000 8500 9000
Pressure (psi)
Dep
th (f
t)
Collapse LoadLine
Burst LoadLine
Collapse DesignLine
Burst DesignLine
-
21
5 - 41
9 5/8 in. Casing in Inventory9 5/8 in. Casing in Inventory
1062793066208.535*LT&CN-8053.5
N-80N-80N-80
Grade
LT&CLT&CLT&C
Conn.
905687047508.68147825633038108.75543.5737575030908.83540
Joint Strength(1000 lb)
Burst(psi)
Collapse(psi)
ID(in.)
Wt(lb/ft)
* Drift diameter is less than 8.5 in., will require special drift for bit
The example in the manual shows more casing types, but we limited the amount shown on the slide
5 - 42
Burst or CollapseBurst or Collapse
In the case of intermediate casing the burst is often more significant than the collapse loads
We will do the burst design first then check the collapse loads
It is possible to do these simultaneously on the same chart, but we keep them separate for simplicity
-
22
5 - 43
Burst DesignBurst DesignIntermediate Casing Design
0
2000
4000
6000
8000
10000
12000
0 500 1000 1500 2000 2500 3000 3500 4000 4500 5000 5500 6000 6500 7000 7500 8000 8500 9000 9500
Pressure (psi)
Dep
th (f
t)
Burst LoadLine
Burst DesignLine
40 lb, N-80
47 lb, N-80
43.5 lb, N-80
47 lb, N-80
43.5 lb, N-80
53.5 lb, N-80
5 - 44
Collapse DesignCollapse Design
A quick glance at the collapse strengths of the burst selection will show that all sections are well above the collapse load, so we will not plot it
-
23
5 - 45
Tension Load and DesignTension Load and Design
Safety factor 1.8 in air We might not use this method of design in
practice, but use it here to show how it works
It is simple and it works It has been used for many years It often results in an over-design
5 - 46
Axial Load CalculationsAxial Load Calculations
9 5/8" Intermediate CasingWeight in
AirSection Length
Bouyancy Factor
Section Weight
Cumm. Weight
Safety Factor
Design Weight
lb/ft ft f b lb lb f s lb43.5 1800 1.00 78300 477900 1.8 860220
47 1200 1.00 56400 399600 1.8 71928053.5 1800 1.00 96300 343200 1.8 617760
47 1700 1.00 79900 246900 1.8 44442043.5 2000 1.00 87000 167000 1.8 300600
40 2000 1.00 80000 80000 1.8 144000Total Length: 10500
Using our burst design selection
-
24
5 - 47
Tension Design ChartTension Design ChartIntermediate Casing - Tension
0
2000
4000
6000
8000
10000
12000
0 200000 400000 600000 800000 1000000
Tension (lb)
Dep
th (f
t)
Tension Load
Tension Design
40# N-80LT&C
43.5# N-80LT&C
43.5# N-80LT&C
47# N-80LT&C
47# N-80LT&C
53.5# N-80LT&C
5 - 48
Problem/AdjustmentProblem/Adjustment
The top section of casing that meets the burst design line does not meet the tension design line
We change the top section to 47 lb/ft N-80 That change of weight changes the
tension in the string We must calculate a new design line and
check the adjusted string
-
25
5 - 49
Revised Tension Design LineRevised Tension Design Line
9 5/8" Intermediate CasingWeight in
AirSection Length
Bouyancy Factor
Section Weight
Cumm. Weight
Safety Factor
Design Weight
lb/ft ft f b lb lb f s lb47 1800 1.00 84600 484200 1.8 87156047 1200 1.00 56400 399600 1.8 719280
53.5 1800 1.00 96300 343200 1.8 61776047 1700 1.00 79900 246900 1.8 444420
43.5 2000 1.00 87000 167000 1.8 30060040 2000 1.00 80000 80000 1.8 144000
Total Length: 10500
5 - 50
Adjusted Tension DesignAdjusted Tension DesignIntermediate Casing - Tension
0
2000
4000
6000
8000
10000
12000
0 200000 400000 600000 800000 1000000
Tension (lb)
Dept
h (ft
)
Tension Load
Tension Design
40# N-80LT&C
43.5# N-80LT&C
47# N-80LT&C
47# N-80LT&C
53.5# N-80LT&C
-
26
5 - 51
Summary of 9 5/8 Intermediate Casing Design
Summary of 9 5/8 Intermediate Casing Design
Casing Design Summary
9 5/8" Intermediate Casing
Collapse BurstJoint
Strength5 9.625 8.681 47 N-80 LT&C 3000 3000 141000 484200 high 1.13 1.874 9.625 8.535 53.5 N-80 LT&C 4800 1800 96300 343200 high 1.25 3.093 9.625 8.681 47 N-80 LT&C 6500 1700 79900 246900 high 1.13 high2 9.625 8.755 43.5 N-80 LT&C 8500 2000 87000 167000 2.54 1.126 high1 9.625 8.835 40 N-80 LT&C 10500 2000 80000 80000 1.66 1.127 high
0 0 00 0 00 0 0
Totals: 10500 484200
Minimum Safety Factors Mud Weight: 11.8Collapse: 1.125Burst: 1.125Tension: 1.8 in air
Section Number OD ID Weight
Section Weight
Actual Design Factors
Cum. WeightGrade Connection Bottom Length
5 - 52
Production CasingProduction Casing Safety factors We will use a higher
burst safety factor for the production casing since it may be critical later in the life of the well
1.6 or 100,000 lb
Tension
1.2Burst
1.125Collapse
Safety Factor for Example
Load Type
-
27
5 - 53
Production Casing Load LinesProduction Casing Load LinesProduction Casing Load
0
2000
4000
6000
8000
10000
12000
14000
0 0.5 1 1.5 2 2.5 3 3.5 4 4.5 5 5.5 6 6.5 7 7.5 8 8.5 9 9.5 10 10.5 11 11.5 12
Pressure (1000 psi)
Dep
th (f
t)
Collapse LoadLine
Burst LoadLine
5 - 54
Available 7 in. CasingAvailable 7 in. Casing
99612700130306.004LT&CP-11035
89712460107806.064LT&CP-11032
P-110N-80N-80
Grade
LT&CLT&CLT&C
Conn.
7971122085306.18429672906086006.09432597816070306.18429
Joint Strength
(1000 lb)
Burst(psi)
Collapse(psi)
ID(in.)
Wt(lb/ft)
More types are shown in manual, but the slide has been condensed for simplicity.
-
28
5 - 55
Production CollapseProduction Collapse7" Collapse Design
0
2000
4000
6000
8000
10000
12000
14000
16000
0 1 2 3 4 5 6 7 8 9 10 11 12 13 14
Collapse Pressure (1000 psi)
Dep
th (f
t)
35# P-110
29# N-80
32# N-80
32# P-110
5 - 56
Production Casing BurstProduction Casing Burst7" Burst Design
0
2000
4000
6000
8000
10000
12000
14000
16000
0 2 4 6 8 10 12
Burst Pressure (1000 psi)
Dep
th (f
t)
35# P-110
32# P-110
32# N-80
29# P-110
-
29
5 - 57
Surface Casing TensionSurface Casing Tension7" Casing True Axial Load Design
0
2000
4000
6000
8000
10000
12000
14000
16000
-200 0 200 400 600 800 1000
Axial Load (1000 lb)
Dep
th (f
t)
True Axial Load
Safety Factor = 1.6
Over Pull 100,000 lb
35# P-110
32# P-110
32# N-80
29# P-110
5 - 58
Preliminary 7 Production Casing Design
Preliminary 7 Production Casing Design
Casing Design Summary
7" Production Casing
Collapse BurstJoint
Strength4 7 29 P-110 LT&C 4800 4800 139200 439300 2.25 1.275 2.343 7 32 N-80 LT&C 9600 4800 153600 300100 1.33 1.2 3.362 7 32 P-110 LT&C 12100 2500 80000 146500 1.127 high high1 7 35 P-110 LT&C 14000 1900 66500 66500 1.177 high high
0 0 00 0 00 0 00 0 0
Totals: 14000 439300* includes biaxial effects
Minimum Safety Factors Mud Weight: 15.2Collapse: 1.125Burst: 1.2Tension: 1.6/100,000lb buoyed
Section Weight
Cum. Weight
Actual Design Factors
Grade Connection Bottom LengthSection Number OD ID Weight
-
30
5 - 59
Comments on Casing Selection for Design
Comments on Casing Selection for Design
Costs Availability Simplicity of design Minimum number of cross-over joints Corrosion considerations Wear considerations More . . .
5 - 60
Next we finalize our design !Next we finalize our design !
-
1Combined Loads DesignCombined Loads Design
Chapter 6
6 - 2
In This ChapterIn This Chapter
Yield Based Approach API Based Approach Final Design Refinement Example
-
26 - 3
Preliminary DesignPreliminary Design
Based on published values for Collapse Burst Tension
Successful in most cases with sufficient safety factor
But, published values are invalid for combined loads
6 - 4
General Structural DesignGeneral Structural Design
Deterministic Methods Used primarily for static structures
Probability-based Methods Used primarily for cyclic or dynamically
loaded structures Many methods use some of both
-
36 - 5
Deterministic Design MethodsDeterministic Design Methods
Hypothetical or realistic loads Known strengths and performance
characteristics of material Calculations to specify types and sizes of
structural components to safely sustain the loads
6 - 6
Probability-Based MethodsProbability-Based Methods
Test results for failure of actual structural components
Probabilistic nature of loading Risk weighted design
Human life Property values etc
-
46 - 7
Which Method?Which Method? Both are valid Deterministic methods are typically used
for casing design as well as most static structures
Probabilistic methods are generally used for moving machinery, airframes, etc.
A few companies are using probabilistic methods for casing design
We will use a deterministic method
6 - 8
Mistaken Notions !Mistaken Notions !
Deterministic designs for casing are 100% safe, but may cost more.
Probabilistic methods are more cost effective, but involve more risk.
NOT TRUE
-
56 - 9
Design LimitsDesign Limits
We are not attempting to predict failure We are calculating design limits We have no idea how to predict failure of a
casing string no one does !
6 - 10
Carbon Steel TestCarbon Steel Test A uniaxial test
specimen:
-
66 - 11
Yield StressYield Stress Results of uniaxial
stress-strain test Y is yield stress
P LA L
= =
6 - 12
We will use the yield stress of the metal as
our design limit
We will use the yield stress of the metal as
our design limit
-
76 - 13
Combined LoadsCombined Loads Tensile & compressive loads
Gravitational forces Hydrostatic forces Borehole friction Bending
Collapse and burst loads External and internal pressures
Torsion loads Borehole friction (while rotating)
6 - 14
Combined LoadingCombined Loading
Loads considered in last chapter Tensile Burst Collapse
We considered them separately How do we combine them?
-
86 - 15
The Yield Based ApproachThe Yield Based Approach
A yield criterion
Where Y is the yield strength of the material and is a yield indicator for the combined stresses
no yieldyield
YY
>
6 - 16
von Mises Yield Criterionvon Mises Yield Criterion Plotted in principal stress
space Central axis is pure
hydrostatic stress Extends to + and - Radius is yield strength of
material Any point inside the
surface does not yield Any point on or outside
the surface yields
-
96 - 17
ExampleExample The minimum
distance from the central axis to point ais the yield indicator,
Point a is outside yield surface so yield occurs
yieldY <
6 - 18
Formula for von Mises Yield Criterion in Terms of Principal
Stresses
Formula for von Mises Yield Criterion in Terms of Principal
Stresses
( ) ( ) ( )122 2 2
1 2 2 3 3 112
= + +
-
10
6 - 19
Sign ConventionSign Convention
Tensile stresses are positive Compressive stresses are negative
6 - 20
We Need a Coordinate System for a Tube
We Need a Coordinate System for a Tube
Polar cylindrical coordinate system Radius, r Angle, Axis, z
-
11
6 - 21
Stress Components in Polar Cylindrical Coordinates
Stress Components in Polar Cylindrical Coordinates
Radial stress, r Tangential stress, Axial stress, z
6 - 22
Loads to StressesLoads to Stresses
Loads: Axial load Pressure loads Torque
How do we get them to stresses?
-
12
6 - 23
Axial Stress ComponentAxial Stress Component
( )2 24
zt o i
P PA d d
= = Axial stress component (psi) equals the axial
load (lb) divided by the cross-sectional area of the tube (in2)
Axial stress component is the same value at any point within the wall of the tube
6 - 24
Radial & Tangential Stress Components
Radial & Tangential Stress Components
Long general formulas see manual
Yield always occurs at pipe wall
Which one? Does pipe yield at inner
wall or outer wall in each of these examples?
-
13
6 - 25
Yield due to pressure always occurs at the
inner wall first. It makes no difference
whether the maximum pressure is on the interior or exterior.
Yield due to pressure always occurs at the
inner wall first. It makes no difference
whether the maximum pressure is on the interior or exterior.
6 - 26
Internal Pressure
0
2000
4000
6000
8000
10000
12000
0 20000 40000 60000 80000 100000 120000 140000
Combined Stress (psi)
Inte
rnal
Pre
sure
(psi
)
Inner WallOuter Wall
80000 psi yield
-
14
6 - 27
External Pressure
0
2000
4000
6000
8000
10000
12000
0 20000 40000 60000 80000 100000 120000 140000
Combined Stress (psi)
Exte
rnal
Pre
ssur
e (p
si)
Inner WallOuter Wall
80000 psi yield
6 - 28
Formulas at Inner WallFormulas at Inner Wall
( )( )
2 2 2
2 2
2r i
i o i o o
o i
p
p r r p r
r r
= + =
The negative sign in the radial stress formula shows that it is always a compressive stress
Formulas for radial and tangential stress components at the outer wall are also in the manual
-
15
6 - 29
TorsionTorsion Torsion adds another stress component a shear stress The formula is in the manual When there are shear components then the radial,
tangential, and axial components are not principal stress components
We have to get them into principal stress components before using the von Mises formula the formula for that is also in the manual
Torsion is seldom considered when designing casing However, it must be considered if casing or liner is to be
rotated during cementing
6 - 30
Example of Combined LoadsExample of Combined Loads
See text for now: ~ page 6-14
-
16
6 - 31
Change in PressureChange in Pressure If the internal and/or external pressure
changes once the casing is in the hole it may change the axial stress
If the casing is free to move it changes the buoyancy effect
If it is not free to move it increases or reduces the axial stress similar to ballooning or contraction (formula in manual)
6 - 32
Bending StressesBending Stresses In curved wellbores
the tube bends Causes increase and
decrease in axial strains and stresses
ob
rER
= See manual for qualifying restrictions Use consistent units
-
17
6 - 33
Example of Bending StressExample of Bending Stress
See Manual: ~ page 6-18
6 - 34
Summary of Yield ApproachSummary of Yield Approach Calculate axial stress component from the
tension or compressive load Calculate radial stress component from
hydrostatic pressure Calculate tangential stress component
from the internal and external hydrostatic pressures
Calculate torsional stress component from the torque (if rotation is present)
-
18
6 - 35
Summary ContinuedSummary Continued
Calculate the bending stress component if there is wellbore curvature, add this to axial stress
Calculate the principal stress components if torsion is present otherwise these are the principal stress components
Plug these into the yield equation and calculate the yield indicator
6 - 36
Summary ContinuedSummary Continued
Compare yield indicator to the yield stress of the tube
Adjust the casing design if necessary Check the collapse and connections using
API methods Use a safety factor
No published standard Use at least 1.5
-
19
6 - 37
ExampleExample
See manual: ~ page 6-22
6 - 38
API Based ApproachAPI Based Approach
Collapse problem Biaxial stress for combined loads API collapse calculations API connections API burst
-
20
6 - 39
Collapse ProblemCollapse Problem
Some API tubes collapse before yield Yield criterion cannot be used by itself in
those cases API has method to account for collapse
with combined loads Not especially a good approach, but all
that is currently available
6 - 40
Yield Criterion in Two Dimensions
Yield Criterion in Two Dimensions
Yield equation can be rearranged and solved in terms that allow a two-dimensional plot
Biaxial Stress Chart
-1.4
-1.2
-1
-0.8
-0.6
-0.4
-0.2
0
0.2
0.4
0.6
0.8
1
1.2
1.4
-1.4 -1.2 -1 -0.8 -0.6 -0.4 -0.2 0 0.2 0.4 0.6 0.8 1 1.2 1.4
TensionCompression
Collapse
Burst
z r
Y
r
Y
-
21
6 - 41
Further ReductionFurther Reduction The chart is just the von Misses yield criterion in
two dimensions rather than three What the API method does is to set the radial
stress (usually small) to zero Then calculate the tangential stress Then assume the tangential stress is the new (or
reduced) yield stress The reduced collapse resistance is then
calculated using the appropriate API collapse formula and the reduced yield stress
6 - 42
API Biaxial YieldAPI Biaxial Yield
The reduced yield stress (or biaxial yield stress) is calculated from the nominal yield stress and the axial stress
We will use it in an example later
2314 2
z zcY Y Y
=
-
22
6 - 43
API Collapse CalculationsAPI Collapse Calculations
Four Formulas Yield Pressure Collapse Plastic Collapse Transition Collapse Elastic Collapse
Each valid for specific range depending on Y and do/t
Need five API constants based on Y
6 - 44
API Yield Pressure CollapseAPI Yield Pressure Collapse
( )( )2
12 oYP
o
d tp Y
d t
=
( ) ( ) ( )( )22 2 8
2oA A B C Y
d tB C Y
+ + + +
Valid range:
-
23
6 - 45
API Plastic CollapseAPI Plastic Collapse
( )p oAp Y B C
d t =
Valid range: (see manual)
6 - 46
API Transition CollapseAPI Transition Collapse
( )T oFp Y G
d t =
Valid range: (see manual)
-
24
6 - 47
API Elastic CollapseAPI Elastic Collapse
( ) ( )6
246.95 10
1E
o o
pd t d t
= Note: Independent of Y
Valid range: (see manual)
6 - 48
API ConstantsAPI Constants
A, B, C, G, F Dependent on Y Values in tables for standard yield values
(API Bulletin 5C3) Formulas for non-standard yield (API
Bulletin and also course manual)
-
25
6 - 49
ConnectionsConnections API connections have less tensile strength than
the pipe body Referred to as joint strength API formulas for joint strength
Based on thread depth API formulas for coupling tension/pressure
performance API formulas for coupling bending performance Formulas in manual & API Bulletin 5C3
6 - 50
API Internal Yield Stress (Burst)API Internal Yield Stress (Burst)
Formula based on very thin wall tube Conservative results Contains factor to allow for 12.5%
reduction in wall thickness
20.875bo
tYpd
=
-
26
6 - 51
API Biaxial Collapse Method Applied to Final Casing Design
API Biaxial Collapse Method Applied to Final Casing Design
Using yield and tensile stress, calculate reduced yield with biaxial yield equation
Using appropriate collapse formula, calculate reduced collapse pressure
Adjust casing design if necessary and recheck
6 - 52
Example Final Casing DesignExample Final Casing Design
Casing Design Summary
13 3/8" Surface Casing
Collapse BurstJoint
Strength2 13.375 12.615 54.5 K-55 ST&C 2100 2100 114450 175650 1.125 1.128 3.61 13.375 12.415 68 K-55 ST&C 3000 900 61200 61200 1.359 1.916 26.135
0 0 00 0 00 0 00 0 00 0 00 0 0
Totals: 3000 175650
Minimum Safety Factors Mud Weight: 9.2Collapse: 1.125Burst: 1.125Tension: 1.6/100,000
Section Weight
Actual Design Factors
Cum. WeightGrade Connection Bottom Length
Section Number OD ID Weight
-
27
6 - 53
Tension DesignTension DesignSurface Casing Axial Load
0
500
1000
1500
2000
2500
3000
3500
-150 -50 50 150 250 350 450 550 650 750
Axial Load (1000 lb)
Dep
th (f
t)
54.5 lb, K55ST&C
68 lb, K55ST&C
True Axial Load
Safety Factor = 1.6
100,000 lb over pull
6 - 54
Collapse CheckCollapse Check
No tension at the bottom Tension at bottom of 54.5 lb/ft section:
37,000 lb (from design line) Calculate axial stress Calculate reduced yield Calculate reduced collapse Calculate actual design factor & compare
it to specified safety factor
-
28
6 - 55
Axial StressAxial Stress
( )( )2 2
4 370002385 psi
13.375 12.615z = =
6 - 56
Reduced Collapse YieldReduced Collapse Yield
314 2
3 2385 238555000 14 55000 2
53769 psi
z zc
c
c
Y YY
Y
Y
= =
=
-
29
6 - 57
Calculate API ConstantsCalculate API Constants
For Yc = 53769 psiA = 2.98643B = 0.053445C = 1169.191F = 1.992004G = 0.035643
6 - 58
Calculate d/tCalculate d/t
( )
( )
12
13.3750.5 13.375 12.61535.2
oo
o i
o
o
dd td d
d t
d t
=
= =
-
30
6 - 59
Determine Appropriate API Collapse Formula
Determine Appropriate API Collapse Formula
Use the range formulas for each collapse formula to see which formula is appropriate (see manual for calculations)
We determine that the correct collapse formula is the Transition Collapse Formula
6 - 60
Calculate Reduced CollapseCalculate Reduced Collapse
( )1.99200453769 0.035643
35.21126 psi
To
T
T
Fp Y Gd t
p
p
= =
=
-
31
6 - 61
Adjust the Design ?Adjust the Design ?
The reduced collapse value is 1126 psi The API value is 1130 psi API rounds collapse pressures to nearest
10 psi If we round our result to nearest 10 psi
then they are the same value The difference is insignificant No adjustment of the surface casing
6 - 62
Intermediate CasingIntermediate Casing
Casing Design Summary
9 5/8" Intermediate Casing
Collapse BurstJoint
Strength5 9.625 8.681 47 N-80 LT&C 3000 3000 141000 484200 high 1.13 1.874 9.625 8.535 53.5 N-80 LT&C 4800 1800 96300 343200 high 1.25 3.093 9.625 8.681 47 N-80 LT&C 6500 1700 79900 246900 high 1.13 high2 9.625 8.755 43.5 N-80 LT&C 8500 2000 87000 167000 2.54 1.126 high1 9.625 8.835 40 N-80 LT&C 10500 2000 80000 80000 1.66 1.127 high
0 0 00 0 00 0 0
Totals: 10500 484200
Minimum Safety Factors Mud Weight: 11.8Collapse: 1.125Burst: 1.125Tension: 1.8 in air
Section Weight
Actual Design Factors
Cum. WeightGrade Connection Bottom Length
Section Number OD ID Weight
-
32
6 - 63
Intermediate Adjustment?Intermediate Adjustment?
There is no point in string in tension where the collapse is close to the 1.125 safety factor
No adjustment necessary
6 - 64
Production CasingProduction Casing
Casing Design Summary
7" Production Casing
Collapse BurstJoint
Strength4 7 29 P-110 LT&C 4800 4800 139200 439300 2.25 1.275 2.343 7 32 N-80 LT&C 9600 4800 153600 300100 1.33 1.2 3.362 7 32 P-110 LT&C 12100 2500 80000 146500 1.127 high high1 7 35 P-110 LT&C 14000 1900 66500 66500 1.177 high high
0 0 00 0 00 0 00 0 0
Totals: 14000 439300* includes biaxial effects
Minimum Safety Factors Mud Weight: 15.2Collapse: 1.125Burst: 1.2
Section Number OD ID Weight
Section Weight
Cum. Weight
Actual Design Factors
Grade Connection Bottom Length
-
33
6 - 65
Production CasingProduction Casing
We see two points that should be checked for reduced collapse Bottom of section 2 Bottom of section 3
6 - 66
Production Casing DesignProduction Casing Design7" Casing True Axial Load Design
0
2000
4000
6000
8000
10000
12000
14000
16000
-200 0 200 400 600 800 1000
Axial Load (1000 lb)
Dep
th (f
t)
True Axial Load
Safety Factor = 1.6
Over Pull 100,000 lb
35# P-110
32# P-110
32# N-80
29# P-110
-
34
6 - 67
AdjustmentsAdjustments
Examine the design line Bottom of section 2 is in compression no
adjustment necessary Bottom of section 3 at 9600 ft has 42,000 lb
tension Check bottom of section 3 for reduced
collapse
6 - 68
Calculate Reduced CollapseCalculate Reduced CollapseAPI Biaxial Collapse and Burst Calculations
Diameter, outside (inches) 7Diameter, inside (inches) 6.094Yield stress (psi) 80000Tension, (lb) 42000
Biaxial Yield for Burst (psi) 82158.56Biaxial Yield for Collapse (psi) 77650.82API Constants for Downrated Yield: A 3.062684 B 0.065531 C 1885.028 F 1.993731 G 0.042659API Collapse Formula: PlasticBiaxial Collapse Pressure: 8417Biaxial Burst Pressure: 9300
-
35
6 - 69
Calculate Reduced Safety FactorCalculate Reduced Safety Factor
( )( )8417 1.109
0.052 15.2 9600sf = =
6 - 70
Adjust Design ?Adjust Design ?
Design safety factor: 1.125 Actual design factor: 1.109 Is this acceptable? For practical purposes? Probably OK For defense against a lawsuit? NO! And besides that, we want to see how to
make the adjustment
-
36
6 - 71
Production Casing Design Adjustment
Production Casing Design Adjustment
How much adjustment is necessary Without experience we must guess Let us estimate that the bottom of section
3 must be raised 100 ft The new depth is 9500 ft The new tension is 45000 lb Note that when we raise the bottom to
lower the collapse pressure we also increase the tension
6 - 72
Calculate Adjusted CollapseCalculate Adjusted Collapse
API Biaxial Collapse and Burst Calculations
Diameter, outside (inches) 7Diameter, inside (inches) 6.094Yield stress (psi) 80000Tension, (lb) 45000
Biaxial Yield for Burst (psi) 82305.44Biaxial Yield for Collapse (psi) 77475.72API Constants for Downrated Yield: A 3.062086 B 0.065443 C 1879.791 F 1.993463 G 0.042604API Collapse Formula: PlasticBiaxial Collapse Pressure: 8403
-
37
6 - 73
Calculate New Design FactorCalculate New Design Factor
( )( )8403 1.119
0.052 15.2 9500sf = =
6 - 74
Further AdjustmentFurther Adjustment
We did not pick enough interval We could continue with a trial and error
procedure Or we could be smarter
-
38
6 - 75
Graphical MethodGraphical Method Assume we can lump all our design factor
calculations into some function of the depth we will call f(D) = 1.125
Rearrange it to f(D) 1.125 = 0 So if we guess the correct depth, D, we
get a zero If we have two or more points we can
graph them and interpolate what value of depth will give us zero
6 - 76
Interpolation Interpolation Two points already calculated
1 1
2 2
( ) 1.125 or ( ) 1.125 0Let ( ) 1.125 0then
9600 1.109 1.125 0.0169500 1.119 1.125 0.006
f D f Dy f D
D yD y
= == =
= = = = = =
-
39
6 - 77
InterpolationInterpolationCollapse/Depth Interpolation
-0.02
-0.015
-0.01
-0.005
0
0.005
0.01
0.015
9000 9050 9100 9150 9200 9250 9300 9350 9400 9450 9500 9550 9600 9650 9700
Depth
y
D2 = 9500 ft
D1 = 9600 ft
D = 9440 ft
6 - 78
Calculate Adjusted CollapseCalculate Adjusted Collapse Collapse at 9440 ft,
tension 47,000 lbAPI Biaxial Collapse and Burst Calculations
Diameter, outside (inches) 7Diameter, inside (inches) 6.094Yield stress (psi) 80000Tension, (lb) 47000
Biaxial Yield for Burst (psi) 82402.82Biaxial Yield for Collapse (psi) 77358.45API Constants for Downrated Yield: A 3.061686 B 0.065383 C 1876.283 F 1.993284 G 0.042567API Collapse Formula: PlasticBiaxial Collapse Pressure: 8393
-
40
6 - 79
Calculate Actual Design FactorCalculate Actual Design Factor
( )( )8393 1.125
0.052 15.2 9440sf = =
SUCCESS !SUCCESS !
6 - 80
Adjusted Production Casing Design
Adjusted Production Casing Design
Casing Design Summary
7" Production Casing
Collapse BurstJoint
Strength4 7 29 P-110 LT&C 4800 4800 139200 439300 2.25 1.275 2.343 7 32 N-80 LT&C 9440 4640 148480 300100 1.125* 1.2 3.362 7 32 P-110 LT&C 12100 2660 85120 151620 1.127 high high1 7 35 P-110 LT&C 14000 1900 66500 66500 1.177 high high
0 0 00 0 00 0 00 0 0
Totals: 14000 439300* includes biaxial effects
Minimum Safety Factors Mud Weight: 15.2Collapse: 1.125Burst: 1.2Tension: 1.6/100,000lb buoyed
Section Weight
Actual Design Factors
Cum. WeightGrade Connection Bottom Length
Section Number OD ID Weight
-
41
6 - 81
CommentsComments Section 2 and section 3 are both the same
weight pipe (32 lb/ft) If they were different, then it would have
been a little more complicated to determine the change in weight for each adjustment
The interpolation is not a straight line, and it may require more than two points if they are farther apart than our example
6 - 82
What about burst ?What about burst ?
Tension actually increases the burst resistance of the tube and the couplings (according to the API formulas)
We could adjust for burst, but it is seldom done
-
42
6 - 83
More ? No, but . . .More ? No, but . . .
In the manual is some additional discussion on yield criteria for those interested
And why we call a yield indicator rather than the von Mises stress (It is not a stress)
Good reading material for tonight
6 - 84
-
1Running & Landing CasingRunning & Landing Casing
Chapter 7
7 - 2
Transport to LocationTransport to Location
Prevent damage Thread protectors Stripping Secured with straps Protection from environment Unloading procedures Stripping on pipe racks
-
27 - 3
On LocationOn Location Minimum movement or relocation Drift for internal diameter & obstructions Remove thread protectors and clean threads
and protectors Visually inspect threads Lubricate threads with proper lubricant
(especially offshore) Reinstall protectors (depending on handling
facilities and methods) Do not set equipment on casing on pipe racks
7 - 4
Moving Casing to Rig FloorMoving Casing to Rig Floor
Use safe handling methods If thread protectors not reinstalled
Use rubber clamp-on protectors on pin Do not use hooks in pipe ends
Do not allow casing to slide out of V-door Pin must be protected at all times
-
37 - 5
Pipe MeasurementsPipe Measurements
Responsibility for accurate measurements Company representative ! Not the responsibility of the rig crew !
Joints should be numbered (paint marker) Talley book should be orderly, neat, and
systematic so errors are easily spotted Double check the addition !
7 - 6
Cross-over JointsCross-over Joints Check all cross-over joints
Correct threads Measure and mark with identification Proprietary threads cut by licensed machine
shop or manufacturer Isolate to separate area or place in string
in proper position Always have redundant cross-over joints
on location
-
47 - 7
ST&C to LT&CST&C to LT&C
ST&C pin will make up in LT&C coupling LT&C pin will not make up into an ST&C
coupling LT&C coupling as a cross-over
Avoid if possible ST&C coupling often difficult to remove May damage pin when removing ST&C
coupling
7 - 8
Stabbing CasingStabbing Casing Stabbing board
Required Stable Properly positioned
Guide on bottom of elevator to prevent damage Wind can cause stabbing problems Do not rush the stabbing procedure Some proprietary connections require stabbing
guides
-
57 - 9
Filling CasingFilling Casing
Fill casing as it is run Verify fill visually Large diameter pipe requires large
capacity fill line Self-fill and differential-fill float equipment
Avoid if possible Can get cuttings and other objects in casing
and plug float equipment
7 - 10
Make-up TorqueMake-up Torque
Determine proper makeup torque for all types of connections in string
Rig casing tong line at 90 to tong arm for proper torque reading
Use only approved thread lubricants on clean threads
Proper number of turns can also be measured
-
67 - 11
Thread LockingThread Locking Prevents back-off of lower joints during
drill-out of float equipment Polymer compound
Used on bottom joints & float equipment Inexpensive and easy to use
Lock mill end of connections? In the event casing has to be pulled before
reaching bottom? Welding? (never on N80 or higher grade!)
7 - 12
Casing Handling ToolsCasing Handling Tools
Spider Sets on rig floor Slip type (integral or manual removable) Wrap-around (must open for each joint)
Elevator Attached to traveling block bails Slip type (always integral) Wrap-around type (must open for each joint)
-
77 - 13
Manual Casing SlipsManual Casing Slips
For first few joints only !
7 - 14
Wrap-around SpiderWrap-around Spider
-
87 - 15
Wrap-around SpiderWrap-around Spider
7 - 16
500 Ton Elevator500 Ton Elevator
-
97 - 17
1000 Ton Elevator1000 Ton Elevator
7 - 18
1000 Ton Spider1000 Ton Spider
-
10
7 - 19
Compact SpiderCompact Spider
7 - 20
PrecautionsPrecautions High capacity tools open very easily even
with casing load Care must be taken to prevent accidental
opening Good practice often requires low capacity
tools to start string in hole and switch to high capacity once there is sufficient casing weight to prevent accidental opening of high capacity tools
-
11
7 - 21
Getting to BottomGetting to Bottom If casing stops before reaching bottom
Circulate? Will it cause differential sticking? Pull out and lay down casing? Thread damage when pulling out? Locked threads?
Must have contingency plan beforestarting in hole
If casing stops close to bottom check pipe measurements
7 - 22
Highly Deviated WellsHighly Deviated Wells All pipe below ~70
inclination must be pushed in hole
Friction software is essential before running pipe
Hook load decreases as casing nears bottom
-
12
7 - 23
Reducing Friction in Highly Deviated Wellbores
Reducing Friction in Highly Deviated Wellbores
Increase lubricity Oil muds Special additives
Plastic beads Calcium carbonate Graphite Etc.
Reduce Contact force Lighter casing below critical angle Good centralizers
7 - 24
Pressure ContainmentPressure Containment
Annular BOP OK for most surface casing Not sufficient for deeper strings
Install proper size rams Test rams
-
13
7 - 25
BOP Rams Must Fit Casing !BOP Rams Must Fit Casing !
7 - 26
Landing PracticesLanding Practices How much string weight should be applied
to casing hanger No standard practice Probably as many practices as there are
companies Prevent buckling above freeze point to
reduce casing wear Prevent buckling in uncemented areas that
can cause failure
-
14
7 - 27
Freeze Point ?Freeze Point ?
A point at which the pipe is fixed down hole
Usually taken to be the top of cement Actual freeze point is never known
7 - 28
Neutral Point ?Neutral Point ?
The point at which the effective axial load goes from tension to compression
Not known, can be estimated from calculations
This is not the same point as the neutral point as defined on the true axial loads which has no meaning for buckling
-
15
7 - 29
Common Landing PracticesCommon Landing Practices
Same load on hanger as hook load Some percentage of hook load on hanger
(e.g. 80%, 75% etc.) Tension in all casing above freeze point Neutral point at the freeze point
7 - 30
Slip Type HangersSlip Type Hangers
-
16
7 - 31
Maximum Hanging WeightMaximum Hanging Weight
Because the weight of the casing on slip type hangers cause a radial compressive stress on the casing it is imperative to verify that the hanging weight will not cause the casing to collapse.
tanh s
s
p f WA=
7 - 32
Maximum Hanging WeightMaximum Hanging Weight
Safety factor? 2.0? Taper of slip segment is measured from
horizontal Compare result to the biaxial collapse
rating of the casing See example in Chapter 7
-
17
7 - 33
Wellhead EquipmentWellhead Equipment
Casing Heads Slip-on Weld Threaded
Casing Spools Casing Hangers
Slip type Mandrel type
Precautions
7 - 34
Casing Head Slip-on WeldCasing Head Slip-on Weld Conductor is cut off,
surface casing is cut off and head welded to surface casing
Most popular Requires cutting &
welding May include a base plate
to weld to conductor instead of surface casing
-
18
7 - 35
Casing Head - ThreadedCasing Head - Threaded Landing joint & coupling
removed and head threaded onto pipe
Coupling spacing critical Coupling removal
problems Requires cement to
surface Possible slumping
problem with poor cement
7 - 36
Casing SpoolCasing Spool For additional strings of
casing Spool body pressure
rating and lower flange are compatible to the casing string below the spool
Upper flange is rated to be compatible with casing string that will hang in the spool
-
19
7 - 37
Casing Hanger Slip TypeCasing Hanger Slip Type Installed on casing
above head and slipped into bowl
Often requires BOP removal
Allows adjustment of hanging tension
Requires cutting casing
7 - 38
Casing Hanger Mandrel TypeCasing Hanger Mandrel Type
Threads onto casing and landing joint and lowered into head prior to cementing
Simple, no moving parts Cannot adjust landing tension Cannot reciprocate pipe during cementing Circulation returns for cementing through
head side outlet Only choice in sub-sea applications
-
20
7 - 39
PrecautionsPrecautions
Valves required on side outlets Pressure gage required on each head or
spool Maximum service pressure (MSP) and test
pressure Never use the test pressure for selection Use only MSP in selection
7 - 40
-
1CementingThe API Contribution
CementingCementingThe API ContributionThe API Contribution
Chapter 8
8a - 2
Cementing Design & Diagnostics ProcessesCementing Design & Cementing Design &
Diagnostics ProcessesDiagnostics Processes
-
28a - 3
Zonal Isolation Operations Primary CasingPrimary Casing
Conductor, Surface, Intermediate, ProductionConductor, Surface, Intermediate, Production
Liner CasingLiner Casing Drilling, ProductionDrilling, Production
Plug CementingPlug Cementing Horizontal and Vertical Horizontal and Vertical
Remedial CementingRemedial Cementing BradenheadBradenhead, Through, Through--tubing, Coiled Tubingtubing, Coiled Tubing
8a - 4
A critical Well Construction process used worldwide
How do we measure success? Define Zonal Isolation Ramifications of Poor Zonal Isolation:
improper reservoir evaluation cross flow of unwanted fluids corrosion of pipe and scale production annular pressure and environmental hazards more than $45 Billion/year$45 Billion/year spent on unwanted
produced water management
Primary Cementing
-
38a - 5
API Presentation Outline Cement Manufacturing Oilfield Cementing Processes API Standards for Oilfield Cementing
Specifications for Cement -- API Spec 10AAPI Spec 10A API Recommended Practices -- API RP 10BAPI RP 10B Bulletins Technical Reports ISO/API Documents
8a - 6
Cement ManufacturingCement ManufacturingCement Manufacturing
-
48a - 7
Significant Developments inthe History of Cement
Significant Developments inSignificant Developments inthe History of Cementthe History of Cement
EgyptEgyptPlaster of Paris (CaSOPlaster of Paris (CaSO4 4 + Heat)+ Heat)
GreeceGreeceLime (CaCOLime (CaCO3 3 + Heat)+ Heat)
RomeRomePozzolan (Lime Revisions)Pozzolan (Lime Revisions)
EuropeEuropeStone Cutting (Middle Ages)Stone Cutting (Middle Ages)
EnglandEnglandNatural Cement (1756, John Smeaton)Natural Cement (1756, John Smeaton)Portland Cement (1824, Joseph Aspdin)Portland Cement (1824, Joseph Aspdin)
U.S.U.S.Portland Cement (1872)Portland Cement (1872)
Cement Manufacturing Cement Manufacturing ProcessProcess
-
58a - 9
Oil and Gas Wells (1859 - 1997)3,404,951
Oil and Gas Wells (1859 Oil and Gas Wells (1859 -- 1997)1997)3,404,9513,404,951
OverOver
3.4 Billion Sacks
3.4 Billion SacksServed!!!
Served!!!
8a - 10
Wells Wells -- WorldwideWorldwide19901990--19971997
WellsWells\\YearYear Avg. DepthAvg. Depth(ft)(ft)
EstimatedEstimatedCement/YearCement/Year(million sacks)(million sacks)
WorldWorld 60,05560,055 5,7495,749 6868North AmericaNorth America 36,73436,734 4,6514,651 3434South AmericaSouth America 2,5962,596 5,5785,578 33W. EuropeW. Europe 780780 9,5379,537 1.51.5AfricaAfrica 659659 8,7958,795 1.11.1Middle EastMiddle East 1,0041,004 6,7276,727 1.41.4
-
68a - 11
The API Monogram
8a - 12
API Standardization of Cement
1937 First committee established1947 Mid-Continent Group established1948 First testing Code 32 published 1956 National Committee 10 formed
testing Code 10 published 1997 22nd Edition of Code 10 published
19371937 First committee establishedFirst committee established19471947 MidMid--Continent Group establishedContinent Group established19481948 First testing Code 32 published First testing Code 32 published 19561956 National Committee 10 formed National Committee 10 formed
testing Code 10 published testing Code 10 published 19971997 2222ndnd Edition of Code 10 published Edition of Code 10 published
-
78a - 13
Laboratory MixingAPI Spec 10A
Standards for CementsStandards for Cements SamplingSampling FinenessFineness Slurry PreparationSlurry Preparation Free Fluid TestFree Fluid Test Compressive Strength TestsCompressive Strength Tests Thickening Time TestsThickening Time Tests
8a - 14
API Spec 10A - page 3API Spec 10A API Spec 10A -- page 3page 3
-
88a - 15
Fineness Fineness Fineness Free Fluid Free Fluid Free Fluid
24 hr Compressive Strength24 hr Compressive Strength24 hr Compressive Strength
8 hr Compressive Strength8 hr Compressive Strength8 hr Compressive Strength
Thickening TimeThickening TimeThickening Time
8a - 16
API Classification of Cements
APIAPIClassificationClassification
MixingMixingWaterWater
Gals/SKGals/SK
SlurrySlurryWeightWeightLb/galLb/gal
WellWellDepthDepthFeetFeet
StaticStaticTempTemp
FFA (Portland)A (Portland)B (Portland)B (Portland)C (High EarlyC (High EarlyD (Retarded)D (Retarded)E (Retarded)E (Retarded)F (Retarded)F (Retarded)G (Basic)*G (Basic)*H (Basic)*H (Basic)*JJ
5.25.25.25.26.36.34.34.34.34.34.54.55.05.04.34.34.94.9
15.615.615.615.614.814.816.416.416.416.416.216.215.815.816.416.415.415.4
00--6,0006,00000--6.0006.00000--6,0006,00066--12,00012,00066--14,00014,0001010--16,00016,00000--8,0008,00000--8,0008,000
1212--16,00016,000
8080--1701708080--1701708080--170170170170--260260170170--260260230230--3203208080--2002008080--200200260260--230230
00--6,0006,000
* * Can be Accelerated or Retarded for most Well ConditionsCan be Accelerated or Retarded for most Well Conditions
-
98a - 17
Cement StandardsCement StandardsCement Standards
API - A-C-G-HASTM - I - III - VAPI API -- AA--CC--GG--HH
ASTM ASTM -- I I -- III III -- VV
8a - 18
Cement ManufacturesHolding API Monogram
HoldersHolders WellsWells\\YearYearUnited StatesUnited States 77 28,00028,000CanadaCanada 22 9,9509,950South AmericaSouth America 77 2,6002,600EuropeEurope 99 800800Middle EastMiddle East 99 1,0041,004AustraliaAustraliaChinaChinaJapanJapan
221122
2182189,6009,600
--
-
10
8a - 19
WaringWaring BlenderBlender
Slurry Slurry PreparationPreparation
8a - 20
Free Fluid TestFree Fluid TestFree Fluid Test% FF = (ml FF) x (sg) x (100/Sm)% FF for Class G and H cement
shall not exceed 5.9%*
(other cement classes have no free water requirements)
% FF = (ml FF) x (sg) x (100/S% FF = (ml FF) x (sg) x (100/Smm))% FF for Class G and H cement % FF for Class G and H cement
shall not exceed 5.9%*shall not exceed 5.9%*
(other cement classes have no (other cement classes have no free water requirements)free water requirements)
* This reflects a changeas approved by API letter ballot - Oct 5, 2000
-
11
8a - 21
Cement StrengthMeasurements
8a - 22
Mechanical Crush TestMechanical Crush Test
-
12
8a - 23
NonNon--API Crush TestAPI Crush Test
8a - 24
Slurry Viscosity andThickening Time
-
13
8a - 25
Thickening Time
Time requiredTime required -- type of job & volume of type of job & volume of cementcement
CasingCasing Job Job -- 3 to 3 1/2 hours (less surface)3 to 3 1/2 hours (less surface) SqueezeSqueeze JobJob -- variablevariable Balanced PlugBalanced Plug JobJob -- 1 to 2 hours1 to 2 hours LinerLiner JobJob -- 3 to 3 1/2 hours3 to 3 1/2 hours
8a - 26
Atmospheric ConsistometerAtmospheric ConsistometerAtmospheric Consistometer
-
14
8a - 27
API RP 10B API RP 10B -- 19971997 Slurry DensitySlurry Density Well Simulation Compressive StrengthWell Simulation Compressive Strength Well Simulation Thickening TimeWell Simulation Thickening Time Static Fluid Loss TestStatic Fluid Loss Test Permeability TestsPermeability Tests Rheology, Gel Strength & Flow CalculationsRheology, Gel Strength & Flow Calculations Arctic Cementing TestsArctic Cementing Tests Slurry Stability TestsSlurry Stability Tests Slurry Slurry CompatabilityCompatability TestsTests
8a - 28Pressure Balance Scales
Slurry DensitySlurry Density
-
15
8a - 29
HTHP ConsistometerHTHP ConsistometerHTHP Consistometer
8a - 30
Ultrasonic Cement AnalyzerNon-Destructive Sonic Test
-
16
8a - 31
Fann Model 35ViscometerFann Model 35Fann Model 35ViscometerViscometer
Rheology andRheology andFlow CalculationsFlow Calculations
8a - 32
-
17
8a - 33
Fluid loss Test cellsFluid loss Test cells
Fluid Loss Measurements
8a - 34
-
18
8a - 35
API Specification 10 DCasing Centralizers
API Specification 10 DAPI Specification 10 DCasing CentralizersCasing Centralizers
8a - 36
API SPECIFICATION 10DDESCRIBES CENTRALIZER PERFORMANCE REQUIREMENTS
RUNNING FORCE
RESTORING FORCE
-
19
8a - 37
Manufacturing HavingManufacturing HavingAPI Monogram on Casing API Monogram on Casing
CentralizersCentralizersUnited StatesUnited States 33CanadaCanada 22IndiaIndia 22IndonesiaIndonesia 11GermanyGermany 11ItalyItaly 11
8a - 38
API Recommended Practices 10 F Cementing Float
Equipment
API Recommended Practices API Recommended Practices 10 F Cementing Float 10 F Cementing Float
EquipmentEquipment
-
20
8a - 39
FLOAT VALVESFLOAT VALVES
Insert FloatValve
Ball Valve
Poppet Valve
Insert PoppetValve
8a - 40
API RP 10 F TEST PARAMETERS
Flow Durability