drilling casing design

8/18/2019 Drilling Casing Design

1/95

JAMES A CRAIG


2/95

Table of ontents

Functions of Casing

Types of Casing Strings

Classification of Casing

Mechanical Properties of Casing

Casing Design Criteria

Corrosion Design Considerations


3/95


4/95

Serve as a high-strength flow conduit to

surface for both drilling and production fluids.

Prevent near-surface fresh water zones from

contamination with drilling mud. Provide a connection and support of the

wellhead equipment and blowout preventers.

Provide exact dimensions for running testing,completion, and production subsurface

equipment.


5/95

Types of asing Strings

There are different types of casing for differentfunctions and drilling conditions.

They are run to different depths and one or

two of them may be omitted depending on thedrilling conditions. They are: Cassion pipe

Conductor pipe

Surface casing Intermediate casing

Production casing

Liners


6/95

Cassion pipe (26 to 42 in. OD)

For offshore drilling only.

Driven into the sea bed.

It is tied back to the conductor or surface

casing and usually does not carry any load.

Prevents washouts of near-surface unconsolidated

formations.

Ensures the stability of the ground surface uponwhich the rig is seated.

Serves as a flow conduit for the drilling mud to the

surface


7/95

Conductor pipe (7 to 20 in. OD)

The outermost casing string.

It is 40 to 500 ft in length for onshore and upto 1,000 ft for offshore.

Generally, for shallow wells OD is 16 in. and20 in. for deep wells.

Isolates very weak formations.

Prevents erosion of ground below rig.

Provides a mud return path.

Supports the weight of subsequent casingstrings.


8/95

Surface casing (17-1/2 to 20 in. OD)

The setting depths vary from 300 to 5,000 ft

10-3/4 in. and 13-3/8 in. being the mostcommon sizes.

Setting depth is often determined bygovernment or company policy and notselected due to technical reasoning.

Provides a means of nippling up BOP.

Provides a casing seat strong enough to safelyclose in a well after a kick.

Provides protection of fresh water sands.

Provides wellbore stabilization.


9/95

Intermediate casing (17-1/2 to 9-5/8 in.

OD)

Also called a protective casing, it is purely a

technical casing.

The length varies from 7,000 to 15,000 ft.

Provides isolation of potentially troublesome zones

(abnormal pressure formations, unstable shales,

lost circulation zones and salt sections).

Provides integrity to withstand the high mudweights necessary to reach TD or next casing seat


10/95

Production casing (9-5/8 to 5 in. OD)

It is set through the protective productive

zone(s).

It is designed to hold the maximal shut-in

pressure of the producing formations.

It is designed to withstand stimulating

pressures during completion and workover

operations. A 7-in. OD production casing is often used


11/95

Provides zonal isolation (prevents migration ofwater to producing zones, isolates different

production zones).

Confines production to wellbore.

Provides the environment to install subsurfacecompletion equipment.

Provides protection for the environment in the

event of tubing failure during production

operations and allows for the tubing to berepaired and replaced.


12/95


13/95

Liners

They are casings that do not reach the surface.

They are mounted on liner hangers to theprevious casing string.

Usually, they are set to seal off troublesomesections of the well or through the producingzones for economic reasons (i.e. to save costs). Drilling liner

Production liner

Tie-back liner

Scab liner

Scab tie-back liner


14/95

Drilling Liner – Same as intermediate/protective casing. It

overlaps the existing casing by 200 to 400 ft. It is used to

isolate troublesome zones and to permit drilling below these

zones without having well problems. Production Liner – Same as production casing. It is run to

provide isolation across the production or injection zones.

Tie-back Liner – it is connected to the top of the liner with a

specially designed connector and extends to the surface, i.e.converts liner to full string of casing.

Scab Liner – A section of casing used to repair existing

damaged casing. It may be cemented or sealed with packers

at the top and bottom. Scab Tie-back Liner – A section of casing extending upwards

from the existing liner, but which does not reach the surface

and normally cemented in place. They are commonly used

with cemented heavy-wall casing to isolate salt sectons in

deeper portions of the well.


15/95


16/95

lassification of asing

There are two types of casing standardization: the API

non-API

Some particular engineering problems areovercome by specialist solutions which are not

addressed by API specifications:

drilling extremely deep wells

using ‘premium’ connections in high pressure high

GOR conditions.

Nevertheless, we will stick to the API methods


17/95

Classifications to be considered are:

Outside diameter (OD).

Inside diameter (ID), wall thickness, drift

diameter.

Length (range)

Connections

Weight Grade


18/95

Outside diameter (OD)

Casing manufacturers generally try to

prevent the pipe from being undersized to

ensure adequate thread run-out when

machining a connection. Most casing pipes are found to be within ±

0.75% of the tolerance and are slightly

oversized.


19/95

Inside Diameter (ID), Wall Thickness,

Drift Diameter

The ID is specified in terms of wall thickness

and drift diameter.

The maximal ID is controlled by the

combined tolerances for the OD and thewall thickness.

The minimal permissible pipe wall thickness

is 87.5% of the nominal wall thickness,which in turn has a tolerance of -12.5%.


20/95

The minimal ID is controlled by thespecified drift diameter.

The drift diamater refers to the diameter ofa cylindrical drift mandrel that can passfreely through the casing with a reasonableexerted force equivalent to the weight of themandrel being used for the test.

A bit of a size smaller than the driftdiameter will pass through the pipe.

Casing & Liner OD (in.) Length (in.) Drift Diameter (in.)

≤ 8-5/8 6 ID – 1/8

9-5/8 – 13-3/8 12 ID – 5/32

≥ 16 12 ID – 3/16

API recommended

dimensions for drift

mandrels


21/95

Length (range)

The lengths of pipe sections are specified in

three major ranges:

R1, R2 and R3.

Range Length (ft) Average Length (ft)

1 16 – 25 22

2 25 – 34 31

3 > 34 42


22/95

Connections

API provides specifications for four types of

casing connectors:

CSG – Short round threads and couplings – offer

no pressure seal at internal pressure, threadedsurfaces get further separated.

LCSG – Long round threads and couplings –

same basic thread design as CSG but offers

greater strength and also greater joint efficiency(though less than 100%). Often used because it is

reliable, easy and cheap.


23/95

BCSG – Buttress threads and couplings – offers a

nearly 100% joint efficiency. Not 100% leakproof.

XCSG – Extreme line threads – design is an

integral joint, i.e. the coupling has both box and pinends. Much more expensive.

CSG and LCSG are also called API 8-Round

threads because they have eight threads per

inch


24/95

API

Round Thread

Connector


25/95

API

Buttress Thread

Connector


26/95

API

Extreme-Line

Connector


27/95

Weight

Pipe weight is usually expressed as weight

per unit length in lb/ft. The three types are:

Nominal Weight

Plain-end Weight

Threaded and Coupled Weight or Average Weight


28/95

Nominal weight

Based on theoretical weight per foot for a 20-ft

length of threaded and coupled casing joint.

○ OD = outside diameter (in.)

○ t = wall thickness (in.)

The nominal weight is not the exact weight of the

pipe, but rather it is used for the purpose

identification of casing types.

( )( ) ( )210.68 0.0722nW OD t t OD= − + ×


29/95

Plain-end weight

The weight of the joint of casing without the

threads and couplings.

Threaded and Coupled Weight or Average Weight The weight of a casing joint with threads on both

ends and coupling at one end when in the power

tight position.

The variation between nominal weight andaverage weight is generally small, and most

design calculations are performed with the nominal

weight.

( )10.68 peW OD t = −


30/95

○ Lc = length of coupling (in.)

○ J = distance between the end of the pipe and center

of the coupling (in.)

2120

20 24

Weight of coupling 20

Weight removed in threading two pipe ends

20

ctc pe

L J W W

+ = −

+

−


31/95

Grade

The steel grade of the casing relates to the

tensile strength of the steel from which the

casing is made.

The steel grade is expressed as a codenumber which consists of a letter and a

number.

The letter is arbitrary selected to provide a uniquedesignation for each grade of casing.

The number deisgnates the minimal yield strength

of the steel in thousands of psi. For example, K-55

has a yield strength of 55,000 psi


32/95

Mechanical Properties of asing

Casing is subjected to different loads during

landing, cementing, drilling, and production

operations.

The most important loads which it mustwithstand are tensile, burst and collapse

loads.

Other important loads include wear,corrosion, vibration and pounding by drillpipe,

the effects of gun perforating and erosion


33/95

Tension

Under axial tension, pipe body may

suffer 3 possible deformations:

Elastic – the metallurgical properties of the

steel in the pipe body suffer no permanentdamage and it regains its original form if the

load is withdrawn

Elasto-plastic – the pipe body suffers a

permanent deformation which often resultsin the loss of strength)

Plastic


34/95

The strength of the casing string is expressed

as pipe body yield strength and joint strength.


35/95

Pipe body strength is the minimal force required

to cause permanent deformation of the pipe.

a y sF Aσ = ( )2 2

4s o i

A d d π

= − ( )2 24

a y o iF d d

π

σ = −

Fa = axial force to pull apart the

pipe, lbf

As = cross-sectional area of the

pipe, in.2σ y = minimum yield strength, psi

do = pipe outer diameter, in

di = pipe inner diameter, in


36/95

Joint strength is the minimal tensile force

required to cause the joint to fail.

For API round threads, joint strength is definedas the smaller of minimal joint fracture force and

minimal joint pullout force.

0.95aj up jp

F Aσ =For fracture force,

joint strength:

For pullout force,

joint strength:

0.590.740.95

0.5 0.14 0.14

o up y

aj jp et

et o et o

d F A L

L d L d

σ σ −

= + + +

( )2 20.14254

jp o i A d d π = − −

σ up = ultimate strength, psi

A jp = area under last perfect

thread, in.2

Let = length of engaged thread, in.


37/95

Bending force – Casing is subjected to bending

forces when run in a deviated wells. The lower

surface of the pipe stretches and is in tension.The upper surface shortens and is in

compression.


38/95

Other tensional forces include:○ Shock load (the vibrational load when running

casing and the slips are suddenly set at the

surface)

○

Drag force (frictional force between the casingand the borehole walls)

63b o n

F d W = Θ

Wn = nominal weight, lb/ft

ϴ = dogleg severity, degrees (o)/100 ft


39/95

Burst pressure

Minimum expected internal pressure at

which permanent pipe deformation could

take place, if the pipe is subjected to no

external pressure or axial loads. The API burst rating is given as:

20.875

y

br

o

t P

d

σ

=


40/95


41/95

Collapse pressure

Minimum expected external pressure atwhich the pipe would collapse if the pipe

were subjected to no internal pressure or

axial loads.


42/95

There are different types of collapse

pressure rating depending on the do/t ratio:

Yield strength Plastic

Transition

Elastic

Grade

Yield

strength

collapse

Plastic

collapse

Transition

collapse

Elastic

collapse

F1 F2 F3 F4 F5

H-40 16.40 27.01 42.64 2.950 0.0465 754 2.063 0.0325

J-, K-55 14.81 25.01 37.21 2.991 0.0541 1,206 1.989 0.0360

C-75 13.60 22.91 32.05 3.054 0.0642 1,806 1.990 0.0418

L-, N-80 13.38 22.47 31.02 3.071 0.0667 1,955 1.998 0.0434

C-90 13.01 21.69 29.18 3.106 0.0718 2,254 2.017 0.0466

P-110 12.44 20.41 26.22 3.181 0.0819 2,852 2.066 0.0532

Ranges

of do/twhen

axial

stress is

zero


43/95

Yield Strength Collapse Pressure

Plastic Collapse Pressure

2

1

2

o

cr y

o

d

t P

d

t

σ

− =

12 3cr y

o

F P F F

d

t

σ

= − −


44/95

Transition Collapse Pressure

Elastic Collapse Pressure

45cr y

o

F P F

d

t

σ

= −

6

2

46.95 10

1

cr

o oP d d

t t

×

= −


45/95

Combined stresses

The performance of casing is examined

in the presence of other forces.

axial load z

s Aσ =

2

,

1 0.75 0.5 y eff i

z z

y y y

Pσ σ σ

σ σ σ

+

= − −


46/95

2

, 1 0.75 0.5 z z

y eff y i

y y

Pσ σ σ σ σ σ

= − − × −

σ z = axial stress, psi (+ve for tension, -

ve for compression)

Pi = internal pressure, psi

σ y,eff

= effective yield strength, psi


47/95

asing Design riteria

Casing costs is one of the largest cost

items of a drilling project.

It is imperative to plan for proper

selection of casing strings and theirsetting depths to realise an optimal and

safe well at minimal costs.


48/95

Casing points selection

Initial selection of casing setting depths is

based on the pore pressure and fracture

pressure gradients for the well.

Information on pore pressure and fracturepressure gradients is usually available from

offset well data.

This information should be contained in thegeotechnical information provided for

planning the well.


49/95


50/95


51/95

Other factors affecting casing points

selection include:

Shallow gas zones Lost circulation zones, which limit mud weights

Well control

Formation stability , which is sensitive to

exposure time or mud weight

Directional well profile

Sidetracking requirements

Isolation of fresh water sands (drinking water) Hole cleaning

Salt sections


52/95

High pressured zones

Casing shoes should where practicable be set in

competent formations

Casing program compatibility with existing

wellhead systems

Casing program compatibility with plannedcompletion program

Multiple producing intervals

Casing availability

Economy


53/95

Design factors

API design factors are essentially “safety

factors” that allow us to design safe, reliable

casing strings.

Each operator may have his own set of designfactors, based on his experience and the

condition of the pipe.


54/95

The design factors are necessary to cater for:

Uncertainties in the determination of actual loads

that the casing needs to withstand.

Reliability of listed properties of the various steelsused in the industry and the uncertainty in thedetermination of the spread between ultimate

strength and yield strength. Uncertainties regarding the collapse pressure

formulas.

Possible damage to casing during transport and

storage. Damage to the pipe body from slips, wrenches or

inner defects due to cracks, pitting, etc.

Rotational wear by the drill string while drilling.


55/95


56/95

The API design factors are:

Tension and Joint Strength: DFT = 1.8

Collapse: DFC = 1.125

Burst: DFB = 1.1

Example

Required Design factor Design

Tension: 100,000 lbf 1.8 180,000 lbf

Collapse: 10,000 psi 1.125 11,250 psi

Burst: 10,000 psi 1.1 11,000 psi


57/95

Worst possible conditions

Tension Design Assume there is no buoyancy effect.

Design is based on the weight of the entirecasing string.

Collapse Design Assume that the casing is empty on the inside,

that is, no pressure inside the casing and no

buoyancy effect. Design is based on the maximum mud weight at

the casing depth


58/95

Burst Design Assume no backup fluid on the outside of the

casing. Design is based on maximum pressure on the

inside of the casing.

The pressure is to design for is the estimated

formation pressure at TD for production casing, orestimated formation pressure at the next casingdepth.

The casing string must be designed towithstand the expected conditions in tension,burst and collapse.


59/95

Graphical design method

Casing design itself is an optimizationprocess to find the cheapest casing stringthat is strong enough to withstand theoccuring loads over time.

The design is therefore depended on: Loading conditions during life of well (drilling

operations, completion procedures, production,and workover operations)

Strength of the formation at the casing shoe(assumed fracture pressure during planning andverified by the formation integrity test.

Availabilty and real price of individual casing

strings


60/95

○ Burst: Assume full reservoir pressure all along thewellbore.

○ Collapse: Hydrostatic pressure increases with depth.

○ Tension: Tensile stress due to weight of string is highestat the top


61/95

Analytical design method

Burst requirements

Casing must withstand the maximum anticipated

formation pressure that the casing string could

possibly be exposed to.


62/95

Collapse requirements

We start at the bottom of the string and work

our way up.

Our design criteria will be based on

hydrostatic pressure resulting from the mud

weight that will be in the hole when the

casing string is run, prior to cementing.


63/95

Worst possible conditions

Burst design: assume no “backup” fluid on the

outside of the casing

Collapse design: assume that the casing isempty on the inside.

Tension design: assume no buoyancy effect.


64/95

orrosion Design onsiderations

Corrosion “eats” through casing string

This reduces the wall thickness

It then affects the collapse resistance, burst

resistance and the yield strength, among others. Forecasting the presence and concentration of

corrosion is essential for a choice of a proper

casing grade and wall thickness and for

operational safety purposes.

Casing can also be subjected to corrosive attack

opposite formations containing corrosive fluids


65/95

Factors causing corrosion

Most corrosion problems in oilfield

operations are due to the presence of water.

Corrosive fluids can be found in water-rich

formations and aquifers as well as in thereservoir itself.

Factors initiating and perpetuating corrosion

can either act alone or in combination.


66/95

Oxygen (O2)

Oxygen dissolved in water drastically increases itscorrosivity potential.

It can cause severe corrosion at very low

concentrations of less than 1.0 ppm.

The solubility of oxygen in water is a function ofpressure, temperature and chloride content.

Oxygen is less soluble in salt water than in fresh

water.

Oxygen usually causes pitting in steels.


67/95

Hydrogen Sulphide (H2S)

H2S is very soluble in water and when

dissolved, behaves as a weak acid and

usually causes pitting.

This type of attack is called sour corrosion. Other problems from H2S corrosion include

hydrogen blistering and sulphide stress

cracking.

The combination of H2S and CO2 is moreaggressive than H2S alone.


68/95

Carbon Dioxide (CO2)

CO2 is soluble in water and forms carbonic acid,

decreases the pH of the water and increase its

corrosivity.

It is not as corrosive as oxygen, but usually also

results in pitting.

Corrosion by CO2 is referred to as sweet corrosion.

Partial pressure of CO2 is used as a yardstick to

predict corrosion.

○ Partial pressure < 3 psi: generally non corrosive.

○ Partial pressure 3 – 30 psi: may indicate high corrosion

risk.

○ Partial pressure > 30 psi: indicates high corrosion risk.


69/95

Temperature

Like most chemical reactions, corrosion ratesgenerally increase with increasing temperature.

Pressure

The primary effect of pressure is its effect ondissolved gases.

More gas goes into solution as the pressure isincreased, this may in turn increase the corrosivityof the solution.


70/95

Velocity of Fluids

Stagnant or low velocity fluids usually give low

corrosion rates, but pitting is more likely.

Corrosion rates usually increase with velocity as

the corrosion scale is removed from the casingexposing fresh metal for further corrosion.

High velocities and/or the presnce of suspended

solids or gas bubbles can lead to erosion,

corrosion, impingement or cavitation.


71/95

Corrosion control measures

Corrosion control measures may involve

the use of one or more of the following:

Cathodic protection

Chemical inhibition Chemical control

Oxygen scavengers

Chemical sulphide scavengers

pH adjustment

Deposit control


72/95

Determine the collapse strength for a 5 1/2” O.D.,

14.00 #/ft, J-55 casing under axial load of 100,000 lbf

The axial tension will reduce the collapse pressure as

follows:

( )2 2axial load 100,000

24,820 psi

5.5 5.012

4

z

s Aσ

π

= = =−

2

, 1 0.75 0.5 z z

y eff y

y y

σ σ

σ σ

σ σ

= × − −

72


73/95

Here the axial load decreased the J-55

rating to an equivalent “ J-38.2” rating.

, 38 216 psi y eff ,σ =

2

,

24,820 24,82055,000 1 0.75 0.5

55,000 55,000

y eff σ

= × − −

73


74/95

Design a 9-5/8-in., 8,000-ft combinationcasing string for a well where the mud weightwill be 12.5 ppg and the formation porepressure is expected to be 6,000 psi.

Only the grades and weights shown areavailable (N-80, all weights).

Use API design factors.

Design for “worst possible conditions.”

74


75/95

Burst requirement

D e p t h

Pressure

BP Pore pressure Design Factor = ×

BP 6,000 1.1= ×

BP 6,600 psi=

The whole casing string must be

capable of withstanding this internal

pressure without failing in burst.


76/95

Collapse requirement

For collapse design, we start at the bottom of thestring and work our way up.

Our design criteria will be based on hydrostatic

pressure resulting from the 12.5 ppg mud thatwill be in the hole when the casing string is run,

prior to cementing.


77/95

CP 0.052 Mud weight Depth Design Factor = × × ×

CP 0.052 12.5 8,000 1.125= × × ×

CP 5,850 psi=

Further up the hole the collapse

requirement are less severe.

D e p t h

Pressure


78/95

Req’d: Burst: 6,600 psi Collapse: 5,850 psi


79/95

Note that two of the weights of N-80 casing

meet the burst requirements But only the 53.5 #/ft pipe can handle the

collapse requirement at the bottom of the

hole (5,850 psi).

The 53.5 #/ft pipe could probably run all the

way to the surface (would still have to

check tension), but there may be a lower

cost alternative


80/95

To what depth might we be able to run N-80,

47 #/ft? The maximum annular pressure that this

pipe may be exposed to, is:

c

Collapse pressure of pipe 4,760P = = =4,231 psi

design factor 1.125

First Iteration


81/95

First Iteration

At what depth do we see this pressure

(4,231 psig) in a column of 12.5 #/galmud?

c 1 P =0.052×12.5×h

c1

P 4,231h = = = 6,509 ft

0.052×12.5 0.052×12.5


82/95

This is the depth to which the pipe

could be run if there were

no axial stress in the pipe…

But at 6,509’ we have (8,000 - 6,509) =

1,491’ of 53.5 #/ft pipe below us.

The weight of this pipe will reduce the

collapse resistance of the 47.0 #/ft pipe!

8,000’

6,509’

Weight W 53 5 #/ ft 1 491 ft= ×


83/95

This weight results in an axial stress

in the 47 #/ft pipe.

The API tables show that the above stress will reducethe collapse resistance from 4,760 to somewherebetween:

4,680 psi (with 5,000 psi stress)

and 4,600 psi (with 10,000 psi stress)

1 Weight, W 53.5 #/ ft 1,491 ft= ×

1W 79,769 lbf =

1 2weight 79,769 lbf 5,877 psi

end area 13.572 inσ = = =

Interpolation between these values shows


84/95

Interpolation between these values shows

that the collapse resistance at 5,877 psi axial

stress is:

With the design factor:

( )1c1 1 1 22 1

σ σP P P P

σ σ

−= − −

−

( )c15,877 5,000

P 4,680 4,680 4,600 4,666 psi10,000 5,000

− = − × − = −

c1

4,666P 4,148 psi

1.125= =


85/95

This (4,148 psig) is the pressure at a depth:

Which differs considerably from the initial

depth of 6,509 ft, so a second iteration is

required.

2

4,148h 6,382 ft

0.052 12.5= =

×


86/95

86


87/95

87


88/95

Second Iteration

Now consider running the 47 #/ft pipe to thenew depth of 6,382 ft.

( )2 Weight, W 53.5 #/ ft 8,000 6,382 ft= × −

2W 86,563 lbf =

2 2

weight 86,563 lbf 6,378 psi

end area 13.572 inσ = = =

Interpolation again:


89/95

p g


( )1c1 1 1 22 1

σ σP P P P

σ σ

−= − −

−

( )c26,378 5,000

P 4,680 4,680 4,600 4,658 psi10,000 5,000

− = − × − = −

c2

4,658P 4,140 psi

1.125

= =

3

4,140h 6,369 psi

0.052 12.5= =

×

Thi i i hi 13 f f h d l If


90/95

This is within 13 ft of the assumed value. If

more accuracy is desired (generally not

needed), proceed with the:

Third Iteration

3

3

3

h 6,369 ft

W (8,000 6,369) 53.5 87,259 lbf

87,259σ 6, 429 psi13.572

=

= − × =

= =

Interpolation again:


91/95

p g


( )1c1 1 1 22 1

σ σP P P P

σ σ

−= − −

−

( )c36,429 5,000

P 4,680 4,680 4,600 4,658 psi10,000 5,000

− = − × − = −

c3

4,658P 4,140 psi

1.125

= =

c3 c2P P≅


92/95

This is the answer we are looking for:

Run 47 #/ft N-80 pipe to a depth of 6,369 ft Run 53.5 #/ft N-80 pipe between 6,369 and

8,000 ft.

Perhaps this string will run all the way to thesurface (check tension).


93/95

Tension requirement

The weight on the top joint of casing would

be:

With the design factor, the pipe strength

required is:

(6,369 ft 47.0 #/ft) (1,631 ft 53.5 #/ft)

386,602 lbf

= × + ×

=

386,602 1.8 695,080 lbf× =


94/95

The Halliburton cementing tables give a

yield strength of 1,086,000 lbf for the pipe

body and a joint strength of 905,000 lbf for

LT & C.

Then 47 #/ft can be run to the surface.


95/95

N-80

47.0 #/ft

N-80

53.5 #/ft

6,369 ft

1,631 ft

Surface

drilling casing design

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