Casing Strings

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15.0 Casing Strings

Drilling for oil and gas involves boring a hole to the petroleum accumulation and installingpipe from the reservoir to the surface. The pipe, which extends from the target zone to the

surface, is called casing. It acts as a protective lining to the wellbore. A string of casing is run

after each section of hole has been drilled to line the inside of the wellbore(Fig. 15.1). The

main reasons for casing off the open hole are:

i) to prevent unstable formations from caving in

ii) to protect weak formations from mud weights that may cause these zones to break

down

iii) to isolate abnormal pressure zones

iv) to seal off any lost circulation zones

v) to complete and produce the well efficiently

vi) to provide structural support for BOPs and wellheads.

15.1 Types of Casing:In order to carry out these important functions the casing must be securely bonded to

the formation by cement. The cemented casing string then becomes an integral part of the

pressure control system. Depending on the type of formations encountered during the drilling

of the well several casing strings may have to be run. As the well is drilled, deeper, smaller

diameter casing is run through the outer casing, which is already in place. Each string of casing

extends from the setting depth back to the wellhead at surface. The various casing strings can

be described as follows:

a) Conductor Casing: This is the first casing string to be run, and consequently has the

largest diameter. Its function is to seal off unconsolidated formations at shallow depths.

With continuous mud circulation, these formations would be eroded away leaving large

washouts. The surface formations may also have low fracture strengths, which could easily

be exceeded by the hydrostatic pressure exerted by the drilling fluid when drilling a deeper

section of the hole. In areas, where the surface formations are stronger and less likely to be

eroded the conductor pipe may not be necessary. The conductor also provides a conduit for

the mud returns. Where conditions are favourable the conductor may be driven into the

formation and is referred to as stove pipe.

b) Surface Casing: The main functions of surface casing are to seal off any fresh water sands,and support BOP equipment. The setting depth of this casing string is important in an area

where abnormal pressures are expected. If the casing is set too high, there may not be

sufficient formation strength at the shoe to handle a kick when drilling the next section.

c) Intermediate Casing: Intermediate (or protection) casing is used to isolate any

troublesome formations, which would cause drilling problems (e.g. sloughing shale, lost

circulation, high-pressure zones etc.). Depending on the number of such problems

encountered several strings of intermediate casing may be required. The setting depth of

intermediate casing depends on knowledge of pore pressures and fracture gradients. During

drilling the mud, weight controls the pore pressures, but must not exceed the fracturestrength of shallower zones.


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d) Production Casing: This is usually the last string of casing to be run and is either run

through the pay zone, or set just above the pay zone (for an open hole completion). The

main purpose of this casing is to isolate the production interval from other formations (e.g.water bearing sands) and protect the tubing. It also forms the basis for the well completion,

and as such should be thoroughly pressure tested before running the completion.


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e) Liner: A liner is a short of casing, which

does not extend back to surface. It is run

back inside the previous casing toprovide some overlap. Liners may be

used as an either intermediate or

production casing (Fig. 15.2). It either

may be suspended from inside the

previous casing, or can be set standing

on bottom. The liner offers the obvious

advantage of being much cheaper than a

full length of casing. If required a

tieback string can be run to extend the

liner back to the wellhead (Fig. 15.3). A

liner is usually less than 5000 ft long. Theoverlap with the previous casing (liner

lap) is usually 200 400. The liner lap

may be increased if there is a poor

cement bond on the previous casing or if

a high-pressure zone is to be cased off.

The liner hanger should be set above any

weak joints in the existing casing. The

advantages of running a liner as opposed

to a full string casing are:

i) smaller length required, therefore reduced costii) liner is run on drillpipe, therefore less rig time is required

iii) in deep wells liners can be run inside previous liners to seal off

difficult formations and allow the well to reach TD

iv) If necessary, a tieback sleeve can be run to extend the liner back to

surface.

There are three main types of liner installation:

a) Drilling liner: to case off high-pressure zones encountered before Td.

b) Production liner: for use as a production casing, set either above or through the pay

zone.

c) Stub liner: set inside the top of one liner and extends back inside the previousstring. This is used for repairing damaged casing or for extra protection against

corrosion or high formation pressures.

The liner is run on drillpipe with special tools, which allow the liner to be run, set and

cemented all in one trip. A liner hanger is installed at the top of the liner. The hanger has

wedge slips, which can be set against the inside of the previous string. The slips can be set

mechanically (rotating the drillpipe) or hydraulically (differential pressure). The presence of

slips between the liner and the casing reduces the by-pass area for circulation, which is

important for cementing operations. A liner packer is used at the top of the liner to seal off the

annulus after the liner has been cemented. The basic running procedure is as follows:

i) run liner on drillpipe to required depthii) set hanger

iii) circulate to clean out liner


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iv) back off the setting tool

v) pump down cement, and displace

vi) set liner packervii) Pick up setting tool, reverse circulate to clean out cement

and pull out of hole.

15.2. Casing ProgrammesCasing makes up a considerable part of the overall well cost (up to about 20%), and so

great care is taken to decide on a casing programme, which will meet the requirements of each

well. Each string of casing must be carefully designed to withstand the expected loading. The

designer must also bear in mind the costs involved the availability of different casing types and

the operational problems in running the casing string. The casing design relies heavily on

expected formation pressures and formation fracture gradient at various depths involved.

Normal fracture gradient may vary according to the geological formations. When drilling adevelopment well this information will be available from previous well records, and so the

casing programme can be accurately designed. In an exploration well, however, the formation

pressures can only be estimated. Troublesome formations may also be encountered which

were not expected. The casing design must therefore be more approximate, and the

programme should be flexible enough to allow an extra string of casing to be run if necessary.

In practice a number of other factors affect the shoe depth design. They are:

Regulatory requirements Hole stability Differential sticking

Zonal isolation Differential drilling concerns Uncertainty in predicted formation pressures

A well drilled in an area of high pressures will usually require additional casing strings

or liners. A general method of determining casing setting depths is to plot formation and

fracturing pressures vs hole depth (as shown in Fig. 15.4). This procedure, however, is very

conservative, typically yielding many strings. A chart used to select casing and hole sizes (The

dotted lines represent less commonly used sizes) and the table showing the API recommended

bit size are given in Figure 15.5


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15.3. Properties Of CasingCasing is manufactured in a variety of sizes, lengths, grades and weights. Casing can be

specially made for difficult environments (e.g. highly corrosive zones). A number of differentcoupling types are also available. The various types of casing and their properties are shown in

manufacturers catalogues. The API has produced tables, which specify the minimum

standards, which must be met for each type of casing. (API Standard 5A, API Bulletin 5C2).

Extracts from these specifications are given in the figure 15.6.


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Casing can be classified in terms of:

a) Outside Diameter (OD): Casing diameters vary from 4.5 to 36. These can be found in

manufacturers catalogues or field book tables. The choice of OD may be limited by theavailability of certain sizes.

b)Length of Joint: Casing is available in three ranges as follows:

Range Length (ft) Average Length (ft)

1 16-25 22

2 25-34 31

3 34+ 42

When the casing is delivered to the rig the length of each joint should be measured and

recorded on the tally sheet. The length is measured from the top of the collar to the uppermostthread. Lengths are recorded to the nearest 100th of a foot. Range 2 is most common,

although shorter lengths are useful as pup joints when spacing out the hanger.

c) Grade: The casing grade refers to the physical properties of the steel used in the

manufacturing process. The API specifications contain various grades of steel as listed in Table

below. Each grade is designated by a letter, and a number. The number refers to the minimum

yield strength (i.e. N80 casing has a minimum yield strength of 80000 psi). Apart from the API

grades, certain manufacturers produce their own grades.

Casing is manufactured in both seamless and welded types. (Only H and J grades are welded).

The minimum yield strength for the grades recognised by the API are as follows:Casing Grade Yield Stress,

psi

Minimum

Yield Stress,

psi

Maximum

Minimum Ult.

Tensile, psi

Minimum

Elongation(%)

H-40 40,000 80,000 60,000 29.5

J-55 55,000 80,000 75,000 24.0

K-55 55,000 80,000 95,000 19.5

N-80 80,000 110,000 100,000 18.5

L-80 80,000 95,000 95,000 19.5C-90 90,000 105,000 100,000 18.5

C-95 95,000 110,000 105,000 18.5

T-95 95,000 110,000 105,000 18.0

P-110 110,000 140,000 125,000 15.0

Q-125 125,000 150,000 135,000 18.0

The min imum Yield Strengthis defined as the tensile stress required to produce a total

elongation of 0.5% of the length (0.6% of the length for P-110)

d) Weight: In discussing casing weights, we must know which weight is being discussed. We

must differentiate between plain-end weight, average weight with threads and couplings, and


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normal weight of casing. The following discussion applies only to on-upset casing. (Upset

tubular goods are those, which have an increased wall thickness at the ends to compensate for

the reduced strength which, could otherwise result from the presence of threads.)The plain-end weight of casing is the weight of the casing without threads and

couplings. It is easily calculated by assuming the casing to be a cylindrical tube of uniform wall

thickness. Plain-end weights are given in API Standard 5A.

The average casing weight is the average weight (per foot) of a joint of casing with

threads on both ends and a power-tight coupling on one end. The average weight is more

accurate than is the Nominal weight. The nominal weight is an approximate average weight

per foot and is accurate enough for most calculations. The nominal weight is also useful for

identification purposes.

Within each grade casing various wall thickness are available for a given OD. The wall

thickness is indicated by the weight per foot, which can be obtained from field book tables e.g.

consider four different weights of 9 5/8 casing as follows: (all dimensions in inches)

Weight OD ID Wall Thickness Drift Diameter

53.5 Lb/ft 9.625 8.535 0.545 8.379

47 Lb/ft 9.625 8.681 0.472 8.525

43.5 Lb/ft 9.625 8.755 0.435 8.599

40 Lb/ft 9.625 8.835 0.395 8.679

The actual ID may vary slightly in the manufacturing process. For this reason the drift

diameter is given, which refers to the guaranteed minimum diameter. This may be important

when deciding whether certain drilling tools will be able to pass through the casing. (E.g.,

Note that 53.5 LB/ft drift is less than an 8 1/2 bit). Some companies place one joint of the

smallest ID casing used on top of the string as a drift gauge. For calculating the volume of the

casing, however, the given ID is taken as being correct.

e)Connections: Each joint of casing is threaded externally at either end and is connected to the

next joint by a coupling, which is threaded internally. Couplings must posses sufficient strength

to withstand axial loads and at the same time be leak resistant. Couplings are graded in the

same manner as the casings and the physical properties of the couplings must be at least equal

to those of the casing sections it joins. Couplings are classified according to the OD and thewall thickness of the casing on which used and according to the lengths of the threads of the

casing and the coupling as either ST&C (short thread and couplings) or LT&C (long threads

and couplings). API Standard 5A gives dimensions of long and short threads and couplings.

i) short thread (STC)

ii) long thread (LTC)

iii) buttress thread (BTC)

iv) extreme line(EL)

These are shown in Figures 15.7.

The length of a joint of casing is taken to be the overall length of the pipe; in addition,

attached coupling made up power-tight. When joints of casing are made up to form a sectionor string, the overall length will be less than the sum of the individual lengths by the amount of


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makeup of the threads. There have been some embarrassing goof-ups where casing strings

were set high because the threads were not subtracted.

The axial tension, which can be supported at a casing joint, is called the joint strength.Joint strength depends on the effective length and type of threads. Joint strengths for standard

API round thread, buttress, and X-line are given in API Bulletin 5C2 ( given in Appendix)

The STC thread profile is rounded with eight threads per inch. The LTC is similar but

with a longer coupling which provides better strength and sealing properties than the STC.

The buttress thread profile has flat crests, with the front and back cut at different angles.

Extreme line connections also have flat crests and have five or six threads per inch. A metal to

metal seal is provided at the pin end and an external shoulder. Various other types of

connection are available from certain manufacturers (e.g. Hydril, Vam). These may be used for

special applications e.g. providing a gas tight seal for gas lift operations. Surveys have shown

that over 80% of casing failures can be attributed to poor connections. This may be due to a

variety of reasons, including:i) excessive torque used in making connections

ii) dirty threads

iii) cross-threading

iv) Fusing the wrong thread compound.

To ensure that the connections do not leak the casing string should be pressure tested

before drilling the next section. Most of the causes for connection failures can be eliminated by

good handling and running procedures on the rig. The recommended make-up torque (as

given in API RP 5C1) is calculated from:

Torque (ft/lbs) = 0.01 x minimum joint strength

(lbs)

This is an empirical result obtained from tests

using API modified thread compound on API

connections. The recommended make up torque

for other connections are available from

manufacturers.


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15.4. WellheadsThe most important function the wellhead is to suspend the weight of the casing strings

and to withstand the maximum surface pressure expected during drilling and production. On aland well or offshore platform the casing strings are hung off at the surface just below the rig

floor. When drilling from a floating rig the wellhead is installed at the seabed. Subsea

wellheads will be discussed later.

Each casing string is suspended from a casing hanger, which rests on the landing

shoulder of the previous casing head housing, or spool. Hangers must be designed to take the

full weight of the casing, and provide a seal between the casing and the housing. To allow the

various drilling tools to pass through the wellhead the drift diameter of the casing spools must

not be less than the drift diameter of the casing string. To protect the inside of the wellhead

when the drillstring is run through, a wear bushing is installed. This is a protective sleeve,

which must be removed before the next casing string is run. There are two types of casing

hanger in common use:i) Slip type: Where the hanger is latched around the casing and then

lowered to sit inside the casing head. The slips are automatically set by the

applied weight when the casing is landed

ii) Mandrel type: (boll weevil), where the hanger is made up on top of

the casing string and spaced out so that it lands in the casing housing when the

shoe reaches the correct depth. This type cannot be used if there is a risk of the

casing failing to reach bottom

Wellheads can be designed to accept both types of hanger. A sealing element (pack off) must

provide a pressure tight seal.

Either wellheads can be built up using a series of spools, or a compact spool may be installed.

15.4.1 Separate Spool Type Wellhead: The procedure for installing a separate spool system

can be outlined as follows:

The conductor (30) is run and cemented in place. It is then cut off just above the wellhead deck.

The 20 casing is run through the conductor and cemented. Sometimes a landing base iswelded on to transfer some weight to the 30 casing. The 20 casing is cut off just above

the 30casing and a 20 casing spool (lowermost casing head) is installed. This casing

spool has a casing bowl designed to receive the next casing hanger, and side outlets to give

access to the annulus. The casing head must also support the BOP stack used in drilling

the next section.

The 13 3/8 casing is run with the hanger landing in the 29 casing bowl. The casing iscut as before and another spool (13 5/8) is flanged up on top of the 20 spool. The

BOPs are nippled up and 12 hole is drilled.

The process continues, with a separate spool being installed for each casing string.Eventually a tubing head spool is connected which allows the completion tubing to be

suspended from the wellhead. Finally, the Christmas tree is installed on top of the

wellhead. Sealing between each set of flanges is obtained by using ring gaskets approved by

the API. The gaskets have pressure energised seals, rated up to 15000 psi.

The disadvantages of this type of wellhead are:i) a lot of time is spend flanging up the various spools

ii) the greater the number of seals, the more chance of a pressure leak


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iii) BOPs must be removed to install the next casing spool

iv) A lot of headroom is required, which may not be available in the

wellhead area of an offshore platform.To overcome these problems compact spools can be used.

15.4.2. Compact Spool (Speedhead): A compact spool enables several casings strings or

tubing to be suspended from a single unitised spool. The procedure is as follows:

The first stage is to install the 20 lowermost casing head as before. After the 13 3/8 casing is run and cemented, the casing is cut off and the Speedhead is

connected to the casing head. The BOPs can then be nippled up, and the next section

drilled.

The 9 5/8 casing is then run, with the hanger resting on a landing shoulder inside theSpeedhead. A 7 casing string can be run, without changing the wellhead, and

suspended in a similar manner to the 9 5/8 casing.

The tubing string may also be run and landed in the Speedhead. The Christmas tree canthen be installed as before.

The disadvantages or the compact spool is that the casing programme cannot be easily altered,

and so is less flexible than the separate spool system.

15.5. Rig-Site OperationMany casing failures are not caused by inferior design but by damaging the threads while

handling and running the casing on the rig. It has also been known for a joint of different grade

or weight to be run in the wrong place and thus creating a weak spot in the string. Suchmistakes are usually very expensive to repair in terms of both rig time and materials. It is

important, therefore, to take precautions in the way the casing is handled on the rig.

15.5.1. Handling Procedure:

i) When the casing arrives at the rig the length, grade, weight and coupling for each

joint should be checked and recorded on a tally sheet.

ii) The casing should be carefully stacked in the correct running order. This is

especially important when the string contains sections of different casing grades and

weights. On offshore rigs where deck space is limited, do not stack the casing too high

or else, excessive lateral loads will be imposed on the lowermost row. Casing is off

loaded from the supply boat in reverse order, so that it is stacked in the correct running

order

iii) Before running the casing, each joint should be clearly numbered and run in

sequence. If any joint has to be laid down due to damaged threads it can be crossed off

the tally sheet. A correct tally sheet is vital when spacing out the hanger or stage

cementing collar.

iv) While the casing is on the racks the threads and couplings should be thoroughly

checked and cleaned. Any loose couplings should be tightened.

v) Casing should always be handled with thread protectors in place. These need not

be removed until the joint is ready to be stabbed into the string.

15.5.2. Running Procedures:


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i) Before the casing is run, a check trip should be made to ensure that there are no

tight spots or ledges, which may obstruct the casing and prevent it reaching bottom.

ii) Each joint should be drifted before it is run.iii) Joints are picked up from the catwalk and temporarily rested on the ramp. A

single joint elevator is used to lift the joint up through the V door into the derrick

iv) A service company (casing crew) is usually hired to provide a stabber and one or

two floormen to operate the power tongs. The stabbing board is positioned at the

correct height to allow the stabber to centralise the joint directly above the box of the

joint suspended in the rotary table. The pin is then carefully stabbed into the box and

the power tongs make up the connection slowly to ensure no cross threads. Care

should be taken to use the correct thread compound to give a good seal. The correct

torque is also important and can be monitored from a torque gauge on the power tongs.

On buttress casing there is a triangle stamped on the pin end as a reference mark. The

coupling should be made up to the base of the triangle to indicate the correct make-up.v) As more joints are added to the string, the increased weight may require the use of

heavy-duty slips (spider) and elevators

vi) If the casing is run too quickly into the hole, surge pressures may be generated,

increasing the risk of breaking down the formation. (A speed of 100 ft per hour is

often used in open hole sections). If the casing is run with a float shoe, it should be

filled up regularly as it is run.

The casing shoe is usually set 10-30 ft off bottom.

15.5.3. Landing Procedures

After the casing is run to the required depth, it is cemented in place while suspended inthe slips. Once the cement has reached its initial set, the casing is landed. The method used for

landing the casing will vary from area to area depending on the forces exerted on the casing

string after the well is completed. These forces may be due to changes in formation pressure,

temperature, fluid density and earth movements (compaction). These will cause the casing to

either shrink or expand, and the landing procedure must take account of this. Basically there

are 3 different approaches:

i) landing the casing under tension

ii) landing the casing under compression

iii) landing the casing as cemented.

The third option is recommended, since compression may cause buckling and tension that

reduce the casings collapse resistance. For this method, the casing should be landed with thesame hook load as used during cementing (i.e. no picking up or slacking off weight).

15.6. Casing DesignCasing string designers usually take up several weights or grades of casing to make up a given

string. They must be concerned with the string of the casing relative to its position in the

wellbore, overall depth of the wellbore, expected pressures, and weight of the fluids. These

expected loads are explained below:

15.6.1 Anticipated Loading on Casing: The following loads should be considered in the

approach to casing design:


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a) Collapse Loading: This is the resultant external pressure imposed on the casing, tending

to crush the pipe inwards. Since the external forces are greatest at the base of the casing

due to hydrostatic pressure, this implies that the strongest casing should be at the bottom.Any internal fluid within the casing will reduce the collapse loading.

b) Burst Loading: This is the resultant internal pressure imposed on the casing tending to

rupture the pipe outwards. The burst pressure will be greatest where the external load is

least, i.e. at the surface. The worst condition is where gas enters the casing from a high-

pressure zone and completely fills the casing. In designing the casing to resist burst loading

the pressure rating of the BOP stack should be considered since the casing is part of the

well control system

c) Tensile Loading: This is the load imposed by the weight of casing itself. Each joint must

be capable of supporting the weight of the string below that point. As with burst loadingthe tension criterion implies that the strongest casing be installed at the top of the string.

d) Compression: The effect of compressive forces need only be considered for surface

casing, due to the weight transferred from later casing strings. It is not usually a critical

factor.

e) Biaxial Loading Considerations: It has been established that an axial tensile load

imposed on a joint will reduce that joints resistance to collapse, while increasing its burst

resistance. An axial compressive load on a casing joint has the opposite effect (see Figure

15.8).


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The heavier the axial tensile load, the greater the reduction in collapse resistance. This must be

taken into account in the design, especially for deep wells where the collapse resistance may be

considerably reduced. From experimental results, the effect of axial loading is given by the

equation of an ellipse.

Y2 +XY+X2=1

Where,Y= fractional collapse resistance

X= fractional tensile yield stress

i.e. Y= Collapse resistance under tension

Collapse resistance with no tension

and X= suspended weight

body yield strength

This relationship is usually given in graphical form and is contained in manufacturers

catalogues (see Figure 15.9). This allows the designer to de-rate the collapse resistance for the

tensile effect caused by the suspended weight of the casing string.


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f) Effect of Bending: When designing a casing string in a deviated well the bending stress

must be considered. The bending effect will reduce the collapse resistance and tensile load

strength. In sections of the hole where there are severe dogleg (sharp bends), the bendingstresses should be checked. The most critical sections are where dog-leg severity exceeds 100

per 100. Experience has shown that a casing failure due to bending can occur from 200

below to 300 above a dog-leg. A minimum of 500 of heavier weight or higher-grade casing

should therefore be used to strengthen such an interval.

15.6.2. Approach of Casing Design:

The designer must consider all the anticipated loading on the casing string at the time when

the casing is run and throughout the life of the well. The design must meet the conflicting

requirements of collapse and burst, while ensuring the tensile properties of the casing are never

exceeded. The most economical design should be selected, consistent with good engineering

practice. This usually results in a combination string (or tapered string), where the ODremains the same throughout but certain sections of differing grade and weight of casing are

included to reduce costs. In this course, the"Maximum Load Concept will be used.

15.6.3. Design Safety Factors

Certain safety factors are already included in the casing properties published in

catalogues to account for variations in manufacturing process. The designer must also apply

safety factors to allow for unexpected loading and unknown variables. These factors are

applied to increase the actual loading figures to obtain the design loading. Design factors are

determined largely through experience, and are influenced by the consequences of a casing

failure. The degree of uncertainty must also be considered (e.g., an exploration well mayrequire higher design factors than a development well). The following ranges of factors are

commonly used:

a) Burst design factors 1.0-1.33

b) Collapse design factors 1.0-1.125

c) Tension design factors 1.0-2.0

(Note: An overpull of 100,000 lbs may also be included to determine the tension design

loading).

All the above figures depend on the type of casing string being designed, the

loading criteria, amount of back-up and economic considerations.

15.6.4. Loading Considerations on each casing stringFor each case of design, the worst case is chosen. The same basic principles are applied to each

string but with different loading criteria.

I) Surface Casing:

a)Burst conditions: The maximum internal pressure at the bottom of the casing is determined

from the fracture strength of the formation at the casing shoe; in addition, an additional safety

margin (usually 1ppg equivalent mud weight). This is referred to as the injection pressure.

The worst case is where a column of gas fills the casing, and so the internal pressure at surface

can be calculated from the gas density (i.e. surface pressure = injection pressure gas

hydrostatic). The back up fluid in the annulus is usually taken to be formation water since thishas the lowest density and therefore gives the highest resultant burst loading.


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b) Collapse Conditions: The maximum external pressure on the casing is due to the hydrostatic

head of the mud or cement in the annulus when the casing was set. Generally no fluid is

considered to be acting on the inside of the casing as a back-up (i.e. casing is empty).

c) Tension conditions: Once the preliminary choice of casing has been made on burst and

collapse criteria the tensile loading can be determined from the weight of the casing itself and

buoyancy forces. Biaxial effects, such as the reduction in collapse resistance due to tension,

must also be considered.

Example:

A 13 3/8 surface casing is to be set at 3500 ft.

Use the following data to design the casing:

Formation fluid density = 9 ppg

Fraction gradient at 3500 ft = 0.78 psi/ftMud weight when casing run = 9.5 ppg

Cement density (back to surface) = 12 ppg

Gas gradient expected = 0.115 psi/ft

Design factors: DF (burst) = 1.1

DF (collapse) = 1.1

DF (tension) = 1.6 plus 100000 lbs pull

Casing available

Grade Wt ID Burst Collapse Tension (1000

lbs)

Pipe Body

YieldLb/ft Inches Psi Psi STC BTC 1000 lbs

K 55 54.5 12.615 2730 1130 547 11038 853

K 55 68 12.415 3450 1950 718 1300 1069

N 80 72 12.347 5380 2670 1040 1693 1661

1. Burst design:

Injection pressure = ( 0.78 + 1 ppg) x 3500 x 0.052

0.052

= 2912 psi

Surface pressure = 2912 ( 3500 x 0.115)

= 2510 psi

Back-up fluid pressure at 3500 = 0.052 x 9 x 3500

= 1638 psi

The following table summarises these loads:

Depth Internal Loading Back-up Loading Resultant Design Loading( x1.1)

0 2510 0 2510 2761


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3500 2912 1638 1272 1399

The design loading can now be plotted on a pressure-depth graph Fig. 15.9.

2. Col lapse design:

Maximum hydrostatic load (cement) = 0.052 x 12 x 3500 = 2184 psi

Depth External loading Back-up loading Resultant Design Loading

(x 1.1)

0 0 0 0 0

3500 2184 0 2184 2402

These design loads can also be plotted (Fig. 15.10)

3. Choice of Casing:

Based on the design loading lines for both burst and collapse the following string can be chosen

a preliminary design:

0 2500 ft K55 68 lb/ft

2500 3500 ft N80 72 lb/ft

Notice that a short length of K55, 54.5 lb/ft casing could be used between the K55, 68 lb/ft at

the top and the N80, 72 lb/ft at the bottom. However, the design should be kept as simple as

possible (minimum length of section is 1000 ft).

4. Check Tension L oading:

W1 = 1000 x 72 = 72000 lbs

W2 = 2500 x 68 = 17000 lbs

F1 = (P x A)

WhereP = 0.052 x 9.5 x 3500 = 1729 psi

A = / 4 ( 13.3752 12.3472) = 20.77 inch2

F1 = 1729 x 20.77 = 35911 lbs

F2 = (P x A)

Where

P = 0.052 x 9. 5 x 2500 = 1235 psi

A = / 4 (12.4152 12.3472) = 1.32 inch2.F2 = 1235 x 1.32 = 1630 lbs

The tensile loading at each depth can now be calculated as in DE/33 for drillstring design.

Section Depth Tension lbs Overpull

100,000 lbs

Apply DF = 1.6


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N 80 3500

2500

-35911

36089

64089

136089

--

57742

K 55 25000 37719207719 137719307719 60350332350


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This information can be plotted (Fig. 15.11). From the graph it can be seen that the pipe body

yield strength of the chosen casings exceeds the tension design lines. STC couplings will allow

sufficient joint strength.

5. Check Biaxial Ef fects:

Using the actual tension figures the reduction in collapse resistance should be calculated.

Section Depth Tension Pipe Yield X Y De-rated

collapse

N 80 3500

2500

-35911

36089

1661000 -

0.022

1.0

0.99

2670

2643

K 55 2500

0

37719

207719

1069000 0.035

0.194

0.99

0.93

1930

1813

The de-rated collapse resistance can now be plotted.

Notice that at 3500 ft the string is actually in compression, which means that the collapse

resistance is in fact, increased (Figure 15.7). This has little effect on the design and is usually

ignored (factor Y is taken as 1.0).

Compression reduces burst resistance but at the bottom of the string, this has little effect

since burst loading is usually at a minimum. However, if the subsequent casing strings have

their loads transferred to the surface casing this compression may significantly reduce burst

resistance at top of the surface casing failure.


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II) Intermediate Casing:

a) Burst Conditions: The worst case is where a kick occurs while drilling below the

intermediate casing shoe, filling the string with both gas and mud. There are three conditionsto be considered for burst loading.

a) Kick pressures from gas and mud

b) Injection pressure at casing shoe

c) Maximum surface pressure at top of casing

These three pressures can be expressed mathematically in this relationship (Fig. 15.12)

Ps + X (Gm) + Y (Gg) = IP

Where:

Ps = maximum surface pressure (usually BOP rating)

X = length of mud column

Gm = mud gradient (heaviest mud used below shoe)Y = length of gas column

Gg = gas gradient

IP = injection pressure (calculated before for surface casing)

Since ps, Gm, Ggand IP can be obtained there are only two unknowns, x and y. Since

x + y = tpta; length of casing x and y can be determined by solving the two equations

simultaneously.

Example 15.2

Determine the burst loading of a 9 5/8 intermediate casing string under the following

conditions:

Casing setting depth = 100000ft

Max. Surface pressure = 5000 psi

Fracture gradient at shoe = 0.75 psi/ft

Heaviest mud wt. below shoe = 14 ppg (0.728 psi/ft)

Gas gradient = 0.115 psi/ft

Equation 1

5000 + 0.728 + 0.115y = IP

where

IP = psippg 3020100000052.01052.0

75.0 =

+

0.0728x + 0.115y = 3020

Equation 2

x + y = 100000

Combining these two equations gives

0.728x + 0.115(100000 x) = 3020

0.613 x = 1870

x = 3050 ft (mud column)y = 6950 ft (gas column)


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The hydrostatic pressure due to gas = 6950 x 0.115

= 799 psi

The hydrostatic pressure due to mud = 3050 x 0.728

= 2220 psi

The worst case is when the mud coulumn overlies the gas.

At surface, burst pressure = 5000 psi (surface pressure)

At 3050 ft, burst = 5000 + hydrostatic (2220 psi) = 7220 psi

At 10000 ft, burst = 7220 + gas hydrostatic (799 psi) = 8091 psi

As before a back-up pressure equivalent to formation water density is used to calculate the

resultant burst load, which is then multiplied by a design factor to produce the design.

2. Coll apse condit ions:The maximum external loads on the casing are due to the mud weight

in which the casing was run or the cement density in the annulus if this extends back to surface.

It is unlikely that intermediate casing will ever be empty, so some back-up fluid (formation

water) is allowed in the design.

3. Tension loading: Intermediate casing is treated in exactly the same way as surface casing

for tension requirements. With longer casing strings, the reduction in collapse resistance due

to biaxial effects becomes more critical.

III) Production Casing1. Burst conditions: The worst case in the production string is when a leak occurs in the

tubing hanger, exposing the top of the casing to high internal pressure.

The internal pressure = bhp gas hydrostatic (at the top).

To find internal pressure at the bottom, add the hydrostatic pressure of the completion fluid in

the annulus. Again, a back-up pressure equivalent to formation water density can be used to

calculate the actual burst loading.

2. Coll apse conditions:Similar to intermediate casing, but consider the back-up fluid. If the

well is to be gas lifted at some later stage then the casing should be designed as for an emptystring (i.e. no back up). If no lift operations are likely then some back up may b taken into

account in the design.

3. Tension Conditi ons:It is the same as surface casing

15.7. General design procedureMaximum load design can be summarised as follows:

i) Determine the burst loading on the casing by if the worst case applies. Use

back-up fluids and design factors where appropriate to obtain the design loadingline, which can be plotted.


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ii) Determine the collapse loading, again assuming the worst case. Plot the

collapse design loading line on the same diagram as the burst conditions.

iii) Find the relevant physical properties for the casings, which are availablefrom the tables or casing catalogues. Match the properties to the design lines

for collapse and burst, and select the best combination to suit these conditions.

Collapse loading will dictate the selection of casing near the bottom, while burst

will generally be critical near the surface. Do not go too close to the design

lines on the first attempt, and do not choose casing sections less than 1000 ft.

iv) For the combination string chosen in (iii), determine the actual tensile

loading, considering buoyancy. Plot this loading versus depth, and apply

overpull and a design factor to obtain the design line. Check that the pipe body

yield strength of the selected casing exceeds the design loading. Choose a

coupling whose joint strength is greater than the design loading. Select the same

type of coupling throughout the entire string.v) Taking the actual tensile loading from (iv) determine the reduction in

collapse resistance at the top and bottom of each section. Modify the pressure-

depth diagram accordingly, and re-design any section, which fails.

Several attempts may have to be made before all these loading criteria are satisfied and a final

design is produced. When deciding on a final design these points should be considered:

a) Include only those types of casing, which are available. In practice only a few

weights and grades will be kept in stock.

b) Use a maximum of three different weights and grades of pipe to avoid confusion at

a rig site and to make running procedures simpler.c) Check that the final design meets all requirements and state clearly all design

assumptions.

d) If several different designs are possible, choose the most economical scheme to

meet requirements.

15.8. Other Design Consideration: In the previous sections, the general approach to casing

design has been explained. However, there are special circumstances, which cannot be

satisfied by this general procedure. When dealing with these cases a careful evaluation must be

made and the design procedure modified accordingly. These special circumstances include:

a) Temperature effects: high temperatures will tend to expand the pipe, causing buckling.

This must be considered in geothermal wells.

b) Casing through salt zones: massive salt formations can flow under temperature at

pressure. This will exert extra collapse pressure on the casing and cause it to shear. A

collapse load of around one psi/ft (overburden stress) should be used for design purposes

where such a formation is present.

c) Casing through H2S zones: ifhydrogen sulphide is present in the formation, it may cause

casing failures due to hydrogen embrittlement. C75 grade casing is specially manufactured

for use in H2 zones.


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