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

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

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


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


True

Ver

tical

Dep

th (f

t)


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


True

Ver

tical

Dep

th (f

t)


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


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


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


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



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


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


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


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


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


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


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



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


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


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


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


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 =


24

6 - 47

API Elastic CollapseAPI Elastic Collapse

( ) ( )6

246.95 10

1E

o o

pd t d t

= Note: Independent of Y


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


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




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


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


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




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




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


Minimum Safety Factors Mud Weight: 15.2Collapse: 1.125Burst: 1.2


Section Weight

Cum. Weight


Grade Connection Bottom Length

33

6 - 65


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


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


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


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



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


Minimum Safety Factors Mud Weight: 15.2Collapse: 1.125Burst: 1.2Tension: 1.6/100,000lb buoyed

Section 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