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There are five principal types of casing string:

- Stove Pipe, Marine Conductor or Foundation Pile

- Conductor Casing

- Surface Casing

- Intermediate Casing/ iner

- Production Casing/ iner

1 Stove pipe

Stove pipe, marine conductor or foundation pile

The purpose of Stove pipe, marine conductor or foundation pile is to:

- protect the incompetent surface soils from erosion by the drilling fluid.

- reduce the wave and current loads imposed on the inner strings.

- may be used to install a full mud circulation system.

- guide the drillstring and subsequent casing into the hole.

Various names can be given:

Stove ipe: !nshore drilling.

"arine #onductor: !ffshore drilling with surface $!s.

%oundation ile: !ffshore drilling with subsea $!s.

Stove pipe

Stove pipes and marine conductors are either driven, drilled&driven or cemented in a pre-drilled hole to provide

a circulation system for the drilling fluid.

The stove pipe often carries the subsequent conductor casing. !nce the conductor string is cemented the

stove pipe is released from this a'ial load and therefore, subsequent casing strings will hang on the conductor

casing string.

"arine #onductor

"arine conductors are used offshore when the $! is above the water. They provide structural strength, to

cover soft formations below the sea bed, to serve as a mud circulation system and to guide the strings into the

hole. The marine conductor is driven, drilled and driven or cemented in a pre-drilled hole.

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"arine conductors are sometimes part of the piling system for a wellhead (ac)et or piled platform and are

therefore often designed by the structural engineers. They provide centralisation for the inner casing strings

against column buc)ling, but do not carry direct a'ial loads e'cept during initial installation of the conductor

string.

The marine conductors reduce the wave and current loads on the inner casing and provide sacrificial protection

against o'ygen corrosion in the splash *one. !n gravity structures, they are also required to minimise the

transfer to the inner casings of stresses resulting from platform settlement and rotational movement of the

platform.

%oundation pile

%oundation piles are used offshore when the $! stac) is on the sea floor. They provide a mud circulation

system and a guidefor the subsequent strings into the hole.

%oundation piles are usually either (etted into place or cemented in a pre-drilled hole. +f no Temporary uide

$ase is used, they support the "ain uide $ase which carries and aligns all future wellhead components,

$!s, mas tree and casing&tubing strings for both the drilling and production phases. +f a Temporary $ase

uide is used, the foundation pile is landed in tension. The foundation pile directly carries both the a'ial and

bending loads imposed on the wellhead by the environment via marine riser and $!.

2 . #onductor string

#onductor string is a string which is installed to cover unconsolidated formations, to seal off shallow water

sands and to provide protection against shallow gas flows. The string is cemented to the surface or sea bed if

possible, and is always the first string onto which one or more $!s are installed.

prevent poorly unconsolidated formations from sloughing into the hole.

provide a full mud-circulation system.

protect fresh water *ones from contamination by the drilling mud.

provide protection against shallow hydrocarbons.

This string is usually cemented to surface or seabed and is always the first casing on which one or more $!s

are mounted.

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%or onshore wells the conductor string usually supports the wellhead, the $!, the mas tree and subsequent

casing strings.

%or offshore wells with a surface $!, the conductor string also usually supports the wellhead, the $!, the

mas tree and subsequent casing strings. #ompressional loads are therefore often the most critical design

parameters for this casing. bove the top cement, the conductor must be centralised to prevent column

buc)ling. The annulus between the marine conductor and conductor string is usually left uncemented above the

mudline, in order to minimise load transfer from the environment and hence bending stresses in the conductor

string.

%or offshore wells with a subsea $!, the conductor string is landed on the foundation pile, and stays in

tension

3. Surface string

The purpose of the surface string is to provides !lo"out protection during drilling# Setting depth is often chosen to isolate

trou!lesome formations, loss $ones, shallo" hydrocar!ons, "ater sands, or%

4. +ntermediate string

The intermediate string is a string which is used to isolate wea) formations, to case off loss

*ones, sloughing, caving and reservoir formations. Such strings are also set in transition *ones to abnormal

formation pressure to provide blowout protection by upgrading the strength of the well.

#ement fill is required to shut off hydrocarbon *ones and flowing salt sections but not necessarily into the

surface string.

ensure adequate blowout protection for drilling

isolate formations or deeper hole profile changes that can cause drilling problems.

recommended whenever there is a chance of encountering an influ' that could cause brea)down at

the previous casing shoe, and&or severe losses in the open hole section.

nearly always set in the transition *one above or below significant overpressures, and in any potential

cap roc) below a severe loss *one.

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it is good practice when appraising untested, deeper hori*ons, to case off the )nown hydrocarbon

intervals as a contingency against the possibility of encountering a loss circulation *one. This advice applies

primarily to massive reservoir sections rather than sand-shale sequences with numerous small reservoirs and

sub-reservoirs.

may also be set to shut off a swelling shale, a brittle caving shale, a creeping salt, an over-pressured

permeable stringer, a build-up or drop-off section, a high-permeability sand or partly depleted reservoir that

causes differential stic)ing.

design the well to combine many of these ob(ectives in a single casing point.

a liner may be used instead of a full intermediate casing

difficult wells may contain several intermediate casing strings and&or liners.

5. roduction string

The roduction string is a string which is installed to separate productive *ones from other

reservoir formations or for testing purposes.

The string through which the well will be completed, produced and controlled

/sed with or without a pac)er or flow tubing and inside which product flows.

+n most cases, the production casing will serve to isolate the productive intervals, to facilitate proper

reservoir control and to prevent the influ' of undesired fluids.

+n some conditions the well can be left with an open-hole completion below the production string.

The casing itself can be used as a conduit for ma'imising well deliverability, for minimising pressure

losses during a frac (ob, for in(ecting inhibitor or for lift gas. This may require nnular Safety Valves, which

impose severe loads on the uncemented casing.

0emember that production operations will affect the temperature of the production casing and impose

additional thermal stresses.

The production loads are quite different from those imposed during drilling.

Special care to be ta)en in the selection of the steel type and the connections

Special consideration is required where drilling below the production casing since it may suffer some

damage, e.g. in barefoot completions, open-hole gravel pac)s, liner completions and deep-*one appraisal.

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+n a liner completion both the liner and casing form the production string and must be designed

accordingly.

uality of the primary cement (ob is of paramount importance for the production casing, especially

where *onal isolation is critical. +t is recommended that the production casing should be rotated and&or

reciprocated during cementing. This imposes additional design requirements.

6. Liner

& liner 'other than slotted liners( is a string of casing "hich does not e)tend all the "ay to the surface# iners are installed

to permit deeper drilling, to separate the productive $ones from the other reservoir formations or for testing purposes#

*sually cemented up to the top of the liner#

*sually cemented over its entire length to ensure a seal "ith the previous casing string#

It is important to ensure that the liner overlap has a good seal#

In cases of suspected cement seal +uality a mechanical seal 'liner pacer(, should !e installed#

&dditional distinction !et"een drilling and production liners

rilling liners are set:

to provide a deeper and hence a stronger shoe.

to eep the hole open from unsta!le formations.

to achieve a drilling casing at lo" cost.

!ecause of rig limitations on tensional loads.

to minimise the effect of a reduced internal diameter on drilling hydraulics#

Production liners are set:

to achieve a production casing at lo" cost.

!ecause of rig limitations on tensional loads.

to allo" the installation of a larger flo" conduit#

ither type of liner may su!se+uently !e tied !ac to surface "ith a string of casing sta!!ed into the top of the liner

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Casing design factors

#asing design factors

This article describes the unia'ial collapse, burst, a'ial and compression design factors, and the tria'ial design

factor, recommended for use, together with a brief overview of the considerations which led to the choice of the

generally accepted values.

2ach unia'ial design factor is defined as the minimum ratio required between the corresponding casing

strength tabulated in + 3#4, on the basis of the formulae of + 3#5 6corrected to ta)e into account the

effects of corrosion, wear and fatigue7 and the estimated design load. The tria'ial design factor is defined as

the minimum ratio required between the yield strength 6similarly corrected for the effects of corrosion, wear and

fatigue7 and the Von "ises equivalent stress.

These design factors are 8combined8 design factors, ta)ing into account both the uncertainties in the

manufacturing process leading to variations in casing strength, and those in the design-load estimation

process.

Such a combined design factor should not be confused with a safety factor, which is a multiplier to be applied to

the ma'imum design load. The former is based on scientific considerations, while the latter is usually arbitrarily

chosen to give a certain resiliency to the design. %or casing design, this safety factor should be set equal to

unity.

The values used in the drilling industry vary quite widely between operators, because of variations in the design

method used. Some include wear or wall-thic)ness tolerances in the design factors for casing strength. Some

operators assume full evacuation to calculate the design load for collapse, while others apply a partial

evacuation rule.

Tighter controls in the pipe-manufacturing process have led to an improvement in metallurgical and

dimensional properties and hence to more accurately defined casing strengths. This might suggest that the

design factors could be reduced. 9owever, there are very few data available to rely on. probabilistic

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evaluation of the e'isting design code would be required to ma)e technically (ustified changes in the value of

the relevant design factors. uantitative 0is) ssessment 607 can also assist the selection of design factors.

summary of the applicable design factors is given below:

/nia'ial collapse design factor1.

/nia'ial burst design factor1.1

/nia'ial tension design factor1.5

/nia'ial compression design factor1.

Tria'ial design factor1.43

#ollapse design factor

/sing a partial evacuation ;esign

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=hile a collapse failure would normally be e'pected deeper down the wellbore, the rupture of a casing will

most li)ely be a near-surface event. 9ence, the consequences are more severe for such a failure. $ased on

this consideration, although the probability of the failure mode is low, it is recommended that an unia'ial $urst

;esign %actor of 1.1 is )ept for burst design.

Tension design factor

Software applications can assist in the tension load prediction during the installation phase as well as during

the service life time, ta)ing into consideraton the pressure 6buoyancy7 load, the bending load, the dynamic

loads li)e drag and shoc) loads, and the changes in a'ial load by changes in temperature and pressurese.

9owever, it should be highlighted that the static drag loads are more difficult to quantify.

The uncorrected value for the tension capacity of a casing string is presented in + 3#4. 9owever, when

evaluating the tension capacity of a casing a down rating because of wear, corrosion and temperature is

required before the Tension ;esign %actor is applied.

$ased on these considerations, it is recommended that an unia'ial Tension ;esign %actor of 1.5 is )ept in

casing design.

#ompression design factor

+t has been demonstrated that casing failure due to compressive loading will be mainly a result of elastic or

plastic instability, i.e. helical buc)ling. pure compression failure, i.e. casing squashing, is unli)ely in most

cases.

The casing resistance against buc)ling can be significantly increased by the placement of centralisers. +f the

relevant casing is rigidly supported by centralisers, very high compression loads can be carried before buc)ling

occurs.

+t can be seen that two ;esign %actors result:

>+f buc)ling is not possible because of the placement of centralisers between the casing string under

consideration and the previous casing string it is recommended that a unia'ial #ompression ;esign %actor of

1. is used. This can be (ustif ied because the calculated centraliser spacing inherently covers a buc)ling

;esign %actor of 1.3.

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>+f buc)ling is acceptable a post-buc)ling analysis should be carried out to establish the relevant tria'ial stress

state. +n analogy with the discussion on the tria'ial ;esign %actor below, the same Tria'ial ;esign %actor of

1.43 is recommended for these situations.

Tria'ial design factorTranslation of the load conditions into a three-dimensional stress state is possible with design softwares. The

refinement of the ;esign

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#asing design considerations

The ob(ective of the casing design is to define a set of casing strings 6casing scheme7, capable of withstanding

a variety of e'ternal and internal pressures, thermal loads and loads related to the self-weight of the casing.

These casing strings are sub(ected to time-dependent corrosion, wear and possibly fatigue, which down rate

their resistance to these loads during their service life.

!b(ectives of casing design

- protect from sloughing shales or moving salt formations?

- isolate the reservoirs from unwanted fluids

- protect fresh-water hori*ons?

- provide a means to handle )ic)s?

- channel for produced fluid?

- medium for drilling, logging and completion tools?

- provide a smooth medium for future casing and tubing strings?

- support wellhead equipment and subsequent casing strings?

- provide a means of anchoring the blowout preventers and mas tree.

#asing strings are sub(ected to corrosion, wear and fatigue, which down rate their resistance to these loads

during their service life. The interaction between the casing strings - which may lead to annular pressure build-

up or wellhead movement also merits attention.

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#asing design information should be available at the wellsite, to ensure that the operating envelope remains

within the design criteria.

#asing design steps

- collection of all the relevant data by a multi-disciplinary team

- selection of the casing scheme which is most cost-effective over the entire life cycle of the well 6#asing&tubing

represents @13A of the drilling e'penditure7.

- definition of the various load cases to which each casing string is li)ely to be sub(ected.

- evaluation of the casing string to withstand the applied loads.

The interaction between the casing strings - which may lead e.g. to annular pressure build-up or wellhead

movement - also merits attention.

Sequence of design criteria considerations

$urst

#ollapse

Tension

#ouplings

"ulti-a'ial corrections

#ost

%or pressure less than B psi, bia'ial corrections should always be applied. +f pressure is greater than B-

1 psi, tri-a'ial analysis should be performed.

Sequence for graphical design

"a'imise the load

"inimise the bac)up

#alculate the resultant

Select the design factor

#alculate the Cdesign lineD

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#asing catalogue specifications

Nominal diameter

%or steel casing, drill pipe and tubing it is the !; of the tube.

%or line pipe and fiberglass casing it is the +; of the tube

Grade:

2'ample: %43, 9E, F or G3,

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lastic collapse: empirical

Transition collapse: made up by the +

2lastic collapse: theoretical calculation

Burst

4 equations available:

$arlow: thin wall cylinder

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#asing ;esign parameters

2arly collection of all the relevant data is essential and it should be done by a multidisciplinary team.

#onsiderable effort is required from the etroleum 2ngineering and !perations departments when planning,

designing and drilling&completing a well. $ecause of the high costs, the data set used for casing design must be

as complete as possible right from the start. Some of these data are laid down in the development plan, well

proposal or well ob(ectives.

9owever, casing design demands more detailed information on all strata to be penetrated.

The parameters involved will be called the design parameters. These are:

lithological column,

formation-strength,

pore-pressure

temperature profiles,

hydrocarbon composition

94S!4 concentrations.

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1

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t the %ormation $rea)down ressure 6%$7 the borehole fails and a ma(or fracture is initiated. The stress

concentrations around an intact borehole provide the strength of a borehole. !nce formation brea)down has

occurred, these stress concentrations disappear, and the strength of the borehole is reduced to the minimum

in-situ stress of the formation.

+f pumping is continued, the fracture propagates in a controlled manner, and stabilises at the %racture

ropagation ressure 6%7. ;ue to the frictional pressure losses in the fracture, the % will increase if the

flowrate increases.

=hen pumping is stopped, flow into the well and into the fracture stops almost immediately? frictional pressure

losses disappear, and the pressure drops to a value called the +nstantaneous Shut-+n ressure 6+S+7. The

fracture is open, but does not propagate any more.

The fluid in the fracture then lea)s away, through the faces of the fracture into the formation, and the pressure

decreases. The pressure at which the fracture closes is the %racture #losure ressure 6%#7. +t can be shown

that this pressure is equal to the minimum in-situ stress.

fter the fracture has closed the fluid lea)s away very slowly, through the mud ca)e into the formation. The

pressure will, given enough time, reduce to the hydrostatic pressure of the mud column. There is no clear

transition between these last two situations on the pressure decay curve. Techniques have been developed to

derive the %#, by determining the intersection between the two 8trend8 lines in the pressure - time plot.

+f the fractured borehole is pressured up again, the fracture opens up at the %racture 0eopening ressure

6%07, which in most cases is equal to the %#. The fracture continues to propagate at the %. The original

%$ will not be reached anymore? the strength of the borehole is reduced compared to the original unfractured

situation. +n some situations the strength of the borehole may be restored. This process is called 8clay-healing8.

9owever, the mechanism is not understood, and should not be relied upon.

further reading:$asics of 0oc) "echanics

4.5 %ormation-strength gradient and equivalent mud

weight

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%ormation strength is often e'pressed as a gradient by dividing the pressure by the true vertical depth relative

to a reference level.

+n geophysics and roc) mechanics, the %ormation $rea)down radient 6%$7 is calculated by dividing the %$

by the true vertical thic)ness of the overburden. This way formation strength and overburden gradient can be

compared. The conversion is different for land and offshore wells

%or ;rilling 2ngineering, the %ormation $rea)down ressure is e'pressed as an equivalent mud gradient. This

is the mud gradient of a mud that will give a hydrostatic pressure equal to the %ormation $rea)down ressure

at the formation of interest.

4.E "easuring the formation strength

%ormation strength measurements are performed to determine the strength of the wellbore.;ifferent methods

e'ist for determining the strength of a formation:

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the requirement to avoid the ris) of reduced formation strength, caused by formation brea)down.

+n the design stage a trade-off has to be made between the ris) of formation strength reduction and the need

for realistic formation strength data. These two aspects are discussed below.

a. Accuracy of formation strength testing method

$rea)down can occur without indications of

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b. Operational considerations

The main consideration is the ris) that a reduction in formation strength will occur and that it may (eopardises

the success of the well.

The magnitude of the reduction in strength after formation brea)down is un)nown, and it is not certain that

8clay healing8 will restore the strength of the wellbore.

%or an optimum well design, the predictions of the formation strength at the scheduled casing shoes must be

as accurate as possible. The accuracy of the prediction depends on the validity of the formation strength model

and the accuracy, significance and amount of available formation strength data.

+f no data are available, assumptions have to be made about the state of stress and only a rough estimate can

be made of formation strength. This will usually result in a sub-optimal well design, 6either conservative or over-

optimistic7.

+f data from one or more offset wells are available, the basic assumptions on the state of stress can be

confirmed, and the accuracy of the prediction increases. +f enough high quality data 6e.g. micro frac, mini frac or

formation brea)down data7 are available, a regional strength model can be derived, which will allow a more

optimal well design. %or some areas in the world formation strength data have been used to determine the

relationship between minimum hori*ontal stress, depth and pore pressure.

+n areas where formation strength determines well design, it is recommended to develop correlations. To

enable this, it is recommended that formation brea)down tests or microfrac tests are carried out, to determine

%$ and %#, 6and the state of stress7. +f operational considerations do not allow these tests to be performed

during drilling, it should be considered to do these tests on abandonment of wells, or in e'isting wells.

+n view of the importance of stress and strength data, not only for subsequent wells, but also for the production

phase 6e.g. sand failure, compaction, stimulation, etc.7 no opportunities should be missed to perform these

tests which are relatively cheap in the drilling phase.

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2 Porepressure profile

The pore pressure profile is an important design parameter for casing design, in terms of both setting depth

selection, and required casing capacity for burst as well as collapse loading.

The pore pressure is the pressure of the fluid in the pore spaces of the formation. ore pressures are often

e'pressed as gradients relative to a reference level. +n geophysics and roc) mechanics, this is the 8%ree =ater

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#harging - ressures may be transmitted through permeable layers. %ormations at a considerable

distance from the origin of the over-pressures may be charged. This mechanism may also be man-induced

6e.g. internal blowouts, loss of formation fluids, bullheading7.

ressure depletion due to formation fluid production - The production of hydrocarbons normally leads

to a reduction in the pore pressure below its original value.

+nformation on pore pressures may be derived from offset wells and from regional geological models.

;uring the drilling of a well, pore pressures can be inferred from an analysis of the drilling operation during a

reservoir fluid influ' 6e.g. drilling )ic) or swabbed )ic)7.

+n reservoirs of sufficient porosity and permeability, pore pressures can be measured with wireline tools after

the well has been drilled. 2valuation of petrophysical 6wireline and "=;7 data allows the determination of the

behaviour of pore pressures in shales.

=hile drilling an e'ploration well there is virtually no pore pressure information available. The only indication for

pressure anomalies then consists of velocity anomalies on seismic profiles.

E Temperature profile

Temperature changes from the static geothermal gradient will induce thermal loads on casing strings.

The forces&displacements caused by these changes in temperature can be of considerable importance for:

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Steam soa) operations, in which the wells are cycled over a large temperature range.

+n(ection wells, where during prolonged in(ection the temperature at bottom will approach the

temperature of the liquids at surface.

Temperature predictions are also important for sour service casing design, as the grade selection is a

function of the temperature.

3 9ydrocarbon properties

The e'act hydrocarbons properties are dependent on the type of buried organic matter, time of burial and

pressure and temperature after this burial 6metagenesis7. 9ydrocarbons encountered may consist of fluid or

gas only or a mi'ture. /nder reservoir conditions the hydrocarbons will have other properties than under

surface conditions.

The casing designer uses the hydrocarbon properties to calculate the burst design loads 6complete

displacement of the casing to gas or influ' circulation during well control7.

+mportant design parameter:

average density of the hydrocarbons when completely filling the wellbore.

compressibility factor 6-factor7, a term by which the pressure must be corrected to account for the

departure from the ideal gas equation.

Q 94S, #!4 and non-hydrocarbon formation fluid composition

94S and #!4 are gases which have a strong corrosive effect on tubulars. %orecasting their presence and

concentration is essential for a choice of a proper casing grade and wall thic)ness and for operational safety

purposes

The presence of 94S is of particular concern because of the rapid occurrence and potentially disastrous

consequences of sulphide stress corrosion crac)ing in casing. The I#2 definition for these 8sour8 conditions

is an 94S partial pressure over .3 psia 6.5E )a7. %or a well with a bottomhole pressure of 1, psi

6QB,J3 )a7, this represents an 94S concentration of 3 ppm.

#!4 is a potential threat if it is dissolved in water.

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#ombined information of 94S and #!4 concentration, bottom hole pressure and temperature will provide all

information necessary for future sour service and corrosion design. These data usually becomes available after

analysis for samples from production tests of offset wells.

#asing can also be sub(ected to corrosive fluids found in water rich formations and aquifers as well as in the

reservoir itself.

;etailed ;esign and nalysis

+n the detailed design phase, the casing designer determines the material grade and casing wall thic)ness for

each section of the casing scheme selected, which will allow it to withstand all realistically e'pected loads

throughout the life of the well.

Selection of relevant load cases

$efore design calculations can be performed for a given casing section, the casing designer must decide which

load cases can realistically be e'pected to occur.

/nia'ial design

The design loads for the load cases selected are determined and compared with the resistances to burst or

collapse tabulated in + 3#4 on the basis of the formulae published in + 3#5, after these values have been

corrected to ta)e the influence of corrosion, wear and fatigue into account and divided by the relevant design

factor. The casing design obtained in this way is then chec)ed to see whether the casing selected can

withstand the loads occurring during installation 6in particular the a'ial forces due to the total weight of the

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casing string down to the depth considered, and the shoc) and torsional loads e'perienced during setting the

casing7.

/nia'ial design generally leads to a conservative choice of tubular grade and wall thic)ness.

Tria'ial design

Tria'ial analysis is used to optimise casing design. s with the unia'ial approach, the influence of corrosion,

wear and fatigue should be ta)en into account before the tria'ial design factor is applied. ;esigns that did not

meet the unia'ial design rules may )now be acceptable following a detailed tria'ial stress analysis.

/nia'ial design consists in comparing a unia'ial load 6such as a pressure, an a'ial force or a torque7 with a

unia'ial load-bearing capacity. Tria'ial design methods compare the combined effect of radial, tangential and

a'ial stresses in the casing wall with the material yield strength and represent a more realistic assessment of

the ability of the casing to withstand a given load. The stresses can be analysed by using a combination of

9oo)eUs law, the

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#asing scheme selection

The output of this process is a preliminary well configuration specifying the minimum casing diameter and the

minimum casing-shoe setting depth for all strings. This serves as input for the detailed design phase.

The casing diameter is mainly determined by the availability of downhole drilling equipment, logging

tools and production requirements. The casing-shoe setting depth is usually a function of the strength of the

formation to be drilled through and the wellbore loading during the drilling operation.

Selection of the optimum 6most cost-effective7 casing scheme for the anticipated development plan

can play a ma(or role in cutting overall well costs, and guaranteeing formation integrity during drilling under all

realistic loading conditions.

#asing diameters should be the minimum feasible given the formation evaluation requirements and

drilling and production equipment si*es. 0ecent developments in drilling, evaluation and completion techniques

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have increased the application of slimhole drilling and monobore completions to allow for slimmer casing-

scheme selection.

The casing-shoe setting depth is a function of the strength of the formation to be drilled and the loads

on the wellbore during drilling or lithological&geological related considerations. #asing setting depths are

determined by comparing formation strength with the loads to which the formation may be sub(ected.

The primary method of estimating formation strength is still the use of lea)-off and limit tests, although

pore pressure prediction and wellbore stability models are available to assist

The preliminary casing scheme selection should be considering the casing diameters from the inner

strings towards the outer strings and by evaluating the casing setting depths from the total depth upwards to

surface.

1 "inimum casing diameter

reliminary casing si*ing is the most important phase of casing design in terms of well costs.

;esign criterion

"a'imum monetary value, without compromising safety and environment, for the total field development.

$y considering the well ob(ective in detail this requirement can be achieved for e'ploration and

appraisal wells by ta)ing the latest evaluation techniques into account

%or development wells alternative completion systems should be considered. #onsequently, by

determining the well configuration from the inside wor)ing outwards, the most cost effective casing scheme

should be selected.

The final hole si*e or production tubing determine the well configuration.

#ontingencies should be (ustified on the basis of an e'plicit probability analysis. Too much contingency is

frequently included in designs, at unnecessary cost.

Slimming down requires a more widespread use of drilling and production liners. The improved integrity of liner

hangers and reduction of casing wear due to the use of mud motors support a careful re-consideration of

established principles.

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2'ploration and appraisal wells

The ability to test the well at adequate flow rates represents perhaps the most critical factor with respect to the

conduit si*e and well configuration.

lso the minimum diameter of core material may play a role in selecting the hole si*e across coring intervals.

#oring fter ;rilling 6#;7 is emerging as a valuable option. This technology allows full mud log and electric

log evaluation before pic)ing core intervals.

;evelopment wells

roduction wells can be visualised as an inflow& outflow system.

a. !nflo" system

Technological advances allow boosting of the well inflow to a considerable e'tent, all be it at a cost. +n many

cases, it will be profitable to ma'imise well inflow.

The =ell +nflow uality +ndicator 6=++7 is a measure of impairment. %or oil wells, this factor equates to the

ratio + 6actual7&+6theoretical, e'cluding any avoidable inflow damage7. The roductivity +nde' 6+7 is the

production rate per unit applied drawdown. 9ence, the =++ can be interpreted as the actual stabilised

production rate divided by the ideal production rate at the same drawdown. The ideal rate is derived by

e'cluding any avoidable inflow damage. The determination of the =++ is not always unambiguous, but a

consistent method of calculation will provide valuable trend information.

nother factor is the roduction +mprovement %actor 6+%7. The +% is the ratio + 6hori*ontal7&+ 6vertical7, or

more generally + 6new inflow system configuration7&+ 6conventional vertical7.

b. Outflo" system

The outflow system is essentially a conduit with flow controls and, where necessary - artificial lift or pressure

boosting facilities.

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The smallest suitable conduit diameter should normally be selected to handle current and future well flow to

permit the design of the most economic well configuration around the conduit.

+t is essential that future artificial lift be addressed up front, as this may have a ma(or impact on well design

6minimum acceptable casing diameter, conduit si*e, sand control policy7. rtificial lift systems include screw

pumps, intermittent gas lift, plunger lift, beam pumping, hydraulic (et pumping, through to higher horse power

advanced multiphase 2Ss and gas lift.

+n some instances it may be more advantageous to drill a larger number of lower capacity, low cost

development wells rather than a small number high cost high capacity wells.

The monobore completion 6"$7 is a completion with fullbore access across the pay*one, without diameter

restrictions, but not necessarily with a constant diameter from top to bottom. The "$ concept optimises the

opportunity for well intervention through the mas tree, i.e. rig-less, and is applicable to any completion

diameter. $y wor)ing through the mas tree, many operations can be conducted without )illing the well, which

mitigates impairment.

The "$ concept in con(unction with 9igh +ntegrity #orrosion 0esistant 69+#07 tubing may offer very profitable

characteristics in situations with high rig re-entry costs.

4 "inimum casing-shoe setting depth

The minimum setting depth is usually driven by several considerations:

to isolate instable formations?

to isolate shallow hydrocarbons?

to isolate lost circulation *ones?

to isolate fresh water hori*ons?

to prevent failure of formations by induced circulating pressures during drilling operations li)e

circulating, drilling and tripping?

to prevent failure of formations by induced circulating pressures during well control operations when

closing in and circulating out an influ'.

4.1 ;esign criterion

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The estimated %ormation $rea)down ressure 6%$7 of any formation below the casing shoe should

not be e'ceeded during normal operating conditions, including well control, drilling, circulating and tripping.

The mud weight gradient, required to balance the anticipated pore pressures in the open hole section,

should never be higher than the estimated equivalent mud gradient of the %racture #losure ressure 6%#7 in

any of the formations in the open hole section.

+f these requirements are met, the well bore will not fracture, and the well will not e'perience uncontrolled

losses under design conditions. These design conditions relate to the ma'imum influ' that can be closed in and

circulated out, and to the ma'imum circulating rate and trip speed to be e'perienced. +n addition, if the

formation accidentally fractures and a loss- or )ic)&loss-situation develops, it will be possible to return the

damaged well to a stable situation, without significant gains or losses, once the well has been circulated to

mud.

4.4 ;etermination of wellbore pressure load

The wellbore will be sub(ected to the following pressure loads during drilling operations.

Pressure loading during drilling# circulating and tripping operations.

+t is established that transient pressures induced by pipe accelerations can be much higher than the pressures

created by constant tripping speeds. The pressures induced at the bit due to tripping will propagate through the

whole well to bottom. elling does not seem to have a significant effect on the swab and surge pressures

induced. $oth swab and surge pressures are induced in either of the pipe movement directions.

Pressure loading during "ell control operations.

The determination of the pressure loading on the wellbore when circulating out an influ' can be divided into two

aspects: influ' volume determination and wellbore pressure calculation. +t is possible to calculate the design

influ' under a given set of circumstances and the )ic) pressure profile can be calculated using the )ic) volume

calculated.

4.5 ;etermination of wellbore strength

%ormation strength is the other critical design parameter for casing shoe setting depth.

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+n the well design phase, the preparation of the best estimate of the lithological model, formation strength

profile and pore pressure profile is addressed. This will determine the number and setting depths of casings.

best possible estimate can be done using a regional formation strength model, offset well data, or a simple

empirical relationship for those wells, where no other data is available. +n the absence of a more accurate

formation strength model, the lea) off-pressure 6

appro'imation for the formation brea)down pressure 6%$7.

;uring the drilling phase, the assumptions of the %$ made during the casing design phase must be chec)ed

by carrying out

This way, useful data on formation brea)down, fracture closure and in-situ stress can be obtained. The

advantage of a good theoretical&empirical formation strength model, may well offset the ris) associated with a

small reduction in formation strength caused by a fractured casing shoe. #onsider doing these tests on

abandonment of wells.

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$asic aspects of roc) mechanics

$orehole pressure required to reach tensile failure depends on:

tensile strength of the roc)?

state of stress in the formation?

orientation of the wellbore with respect to the state of stress?

shape of the wellbore cross-section?

wellbore fluid penetration into the roc)?

chemical interaction between the wellbore fluids and the roc).

1. State of stress - ;efinitions, conventions

$tate of stress:

The state of stress is a description of the internal loads in a solid 6for e'ample a roc)7, generated by e'ternal

loads acting on the solid. %or an elementary volume element with perpendicular planes and a given orientation,

the state of stress is described by the normal stresses and shear stresses on each of its planes.

%ffecti&e stress:

Schematically, e'ternal forces applied on a roc) will be 8carried8 partly by the grains of roc) and partly by the

pore fluid. The stress induced in the roc) grains is called the effective stress.

!n situstress rate:

The in-situ stresses are the stresses present in an undisturbed virgin formation. They are a result of the

combination of the weight of the overburden, the elastic behaviour of the roc) and the effect of the tectonic

regime. eological *ones can be classified as normally stressed or tectonically stressed. +n a normally stressed

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formation, the ma(or principal stress is usually vertical, and equal to the overburden. The two other principal

stresses are then hori*ontal, and their magnitudes are 6slightly7 different.

Pore pressure:

The pore pressure is the pressure of the fluid in the pore spaces of the formation. ore pressures are often

e'pressed as gradients relative to a reference level. +n most disciplines in the industry, this is the 8%ree =ater

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'oc( tensile strength

$orehole failure is usually governed by tensile failure. Tensile failure is defined to occur when the wellbore fluid

pressure is such that the minimum effective stress at the borehole wall reaches a negative value, equal to the

roc) tensile strength 6T7.

lthough intact roc)s do have a tensile strength 6tensile stress needed to fail a roc) sample7, this strength is

generally small. +n addition, any small defect in the roc) structure 6e.g. a natural fracture7 considerably lowers

this value.

Theoretical relationship: wellbore strength - state of stress

+f a perfectly cylindrical borehole is drilled in a normally stressed formation without fractures, and a perfect mud

ca)e prevents flow of fluids into the formation, it is possible to calculate the %$ for a few simple cases.

+t should be realised that the %$ is strongly dependent of the condition of the borehole and the mud ca)e.

$orehole rugosity or the presence of natural or drilling induced fractures will significantly lower the %$.

)racture propagation

+f the wellbore pressure e'ceeds the %$, a fracture is initiated from the borehole wall, in a direction

determined by the orientation of the in-situ stresses in the near wellbore region. fter the fracture propagates

away from the wellbore, it will always be oriented in a plane perpendicular to the minimum stress.

*ellbore strength in fractured formation

fracture in the borehole wall usually reduces the strength of the wellbore. +f the fracture is in communication

with the wellbore, it will reopen when the wellbore pressure e'ceeds the stress normal to the fracture which is

often the minimum in-situ principal stress: s5. +t will not start propagating until the pressure e'ceeds the +S+.

%or practical purposes, to avoid opening the fracture at all, it is recommended to limit the ma'imum pressure in

a fractured borehole to the %#.

Theoretically, for a vertical well in a tectonically rela'ed area, the difference between the %$ and the %# is

equal to the minimum effective principal stress. %or a deviated well, or a well in a tectonically stressed area, the

difference will be even less.

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5. !ther effects

+ealing

+t has been observed that, with time, the strength of some formations returns after the initial reduction in

strength caused by formation brea)down. +n some cases the strength of the formation returns completely, in

others only partially. This process has been called 8clay healing8, because it only occurs in shales and not in

carbonates.

There are indications that it only occurs with water-based muds, and not with oil-based muds. The

phenomenon can not be relied on, but (ustifies a repeat

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Borehole shape

%ormulas for calculating wellbore strength are available for circular boreholes. +f the borehole is not round, the

borehole possibly will fail at a lower pressure. Io equations e'ist for out-of-shape boreholes 6e'cept for an

elliptical shape7. %or such cases, the use of numerical programs is required.

Chemical interaction

#hemical interaction between formation roc) and the wellbore fluid 6e.g. a sensitive shale and a water based

mud7 will also alter the conditions under which brea)down occurs. 9owever, the mechanisms and parameters

affecting those mechanisms are still under investigation.

Procedures for leak-o and limit tests

(LO! L! "#$

Procedures for lea-off and limit tests# ea-off and imit tests are carried out during the drilling phase of the

"ell# The 01P is closed around the drillpipe, and the "ell is slo"ly pressured up, using mud# &t the first sign of fluid lea-

off into the formation the pumping is stopped# ea-off tests are carried out until lea-off is o!served. limit tests are

carried out until a pre-determined test pressure is reached#

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% #ntroduction to leak-o test &rocedure

ea-off and imit tests are carried out to:

con'rm te strengt of te cement )ond around te casing soe and to ensure tat no

*o+ &at is esta)lised to formations a)o,e te casing soe or to te &re,ious annulus

in,estigate te ca&a)ilit of te +ell)ore to +itstand additional &ressure )elo+ te

casing soe (to andle an in*u/! and to allo+ safe drilling de&t of te ne/t ole section

collect regional data on formation strengt for te o&timisation of future +ell design.

These tests are sometimes called: casing seat, formation intae, formation strength or formation integrity tests#

Proper planning, e)ecution, interpretation and reporting of these tests is essential for "ell safety and in order to gain

ma)imum !enefit from the e)periment#

2 Leak-o test &rocedure

2.% Planning te test

0stimate te surface leak-o &ressure 1

Calculate surface limit &ressure. "or a Limit test te Limit radient (L$ ma )e gi,en inte +ell &rogram. "or a Leak-o test it is recommended to limit te test &ressures to a ma/imum

of te o,er )urden gradient or to anoter realistic limit. is is done to reduce te cance of

unto+ard formation )reakdo+n.

Con'rm te accurac of te &ressure gauges tat +ill )e used for te e/&eriment. e

a)solute accurac of te gauges sould )e .5 of te e/&ected do+nole test &ressure. e

resolution (relati,e accurac$ of te gauges sould )e 2 of te e/&ected surface test &ressure.

Cali)rate te mud )alance to con'rm its accurac (.5 for a &ressurised mud)alance$. suall

te &ressure is measured and recorded at surface! )ut for ig mud +eigts te a&&lication of

do+nole gauges +it surface read-out sould )e considered.

e &ressure e/erted during a Limit or Leak-o test sould ne,er e/ceed te ma/imum

)urst &ressure of te casing (using te recommended design factor (7")urst$ for casing )urst$

and te associated surface e8ui&ment. o calculate te &ressure at te outside of te casing!

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assume a *uid gradient e8ual to te mud gradient tat te casing +as run into. 9dd te test

&ressure to te static mud column on te inside! to calculate te &ressure at te inside of te

casing.

0stimate te ,olume of mud to )e &um&ed! and determine te increment ,olume. o )e

a)le to esta)lis a clear trend in te test results! a minimum of a)out : e8ual increments sould

)e &um&ed )efore te (e/&ected$ test &ressure is reaced.

Com&lete te &re-test &art of te test re&ort. Pre&are a large scale gra& (e.g. 93$ to &lot

te results during te test. 7ra+ te e/&ected ,olume;&ressure line and te surface limit

&ressure and te casing )urst &ressure in te same &lot.

Typical values for mud compressi!ility are given !elo"# 1!served values may !e higher due to the additional e)pansion of

the casing and lines# The com!ined compressi!ility of "ell and mud can !e calculated "ith the results of a previous lea-

off test or casing pressure test after the cementation# If the actual volume2pressure relationship during the test is radically

different from the plan, this might indicate that the pump unit is not lined up properly, the 01P stac not properly closed, a

lea in the surface lines or a very porous formation#

Fluid Compressi!ility '3/Pa( / '3/psi(

"ater, and 40M 5#67)35-85 / 93)35-7

!ase oil 5#8)35-85 / 6;)35-7

10M 5#

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+ile circulating te ole clean of cuttings! circulate< treat te mud to acie,e as lo+ as

&ossi)le gel strengt (e/cessi,e gels ma reduce te &ressure transmitted do+n te +ell to te

formation$. Consider &ulling te )it into te casing soe to &re,ent +as out.

accuratel measure te mud +eigt +it a recentl cali)rated &ressurised mud )alance

con'rm tat mud +eigt-in is e8ual to mud +eigt-out

do not cange te mud +eigt until after te test.

9: Pull the !it !ac into the casing shoe# If high lea-off pressures are e)pected consider the use of a do"nhole pacer to

isolate the cement sheath to prevent micro-annuli development during the test#

6: Mae sure the hole is filled up and close the 01P around the drillpipe# 4here practica!le, open and top up the annulus

!et"een the last and previous casing string, and chec for returns during the test#

7: *se a high pressure, lo" volume pump 'usually the cement unit. rig pumps are unsuita!le(# ine up to esta!lish a clear

flo" path from the pump to the open hole annulus# Consider the ris associated "ith testing through a mudmotor or a non

return valve#

8: ine up cali!rated pressure gauges, covering various pressure ranges and prefera!ly mounted on a special manifold# The

standard gauges on the drilling console or the cement unit are not accurate enough for these measurements# *sually the

pressure is measured and recorded at surface, !ut for high mud "eights the application of do"nhole gauges "ith surface

read-out should !e considered#

;: Pump mud slo"ly 'less than > 0PM,

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=ee& te +aiting &eriod and te ,olume increments constant.

Leak-o is de'ned as te 'rst &oint on te ,olume

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For non-consolidated, plastic, loose or highly permea!le formations "here even lo" test pressures cause loss of mud, the

e)act determination of the lea-off point is difficult# The initial static pressure "ill al"ays !e considera!ly higher than the

final static pressure, and the graph "ill !e curved considera!ly# ea-off can only !e esta!lished appro)imately from the

lea-off graph# 'In many cases the information that no !reado"n is o!served "ill suffice, since it is o!vious that the

formation is "ea and the main purpose of the test is to esta!lish the a!sence of communication around the casing#(

2.4 "ormation )reakdo+n! fracture re-o&ening

(leak-o test &rocedure$

Formation !reado"n during a imit or ea-off test should !e prevented, !ecause a fracture may permanently impair the

capa!ility of the "ell!ore to "ithstand pressure# Bo"ever, if !reado"n occurs, it should !e treated as an opportunity to

derive real formation strength parameters# AFormation !reado"nA is indicated !y a sharp pressure drop on surface# The

highest pressure recorded immediately !efore the pressure drop, is the Asurface !reado"n pressureA#

If formation !reado"n occurs, pumping should !e stopped, !ut the "ell should !e ept closed-in, and the pressure decay

curve should !e recorded# AFracture closureA is indicated !y the sta!ilisation of the pressure decay curve to a constant

pressure value# The FCP can !e determined from the Asurface fracture closure pressureA# The results may !e used to

determine the in-situ stress, "hich may !e very useful for future operations#

To confirm these o!servations, the test may !e continued "ith a fracture re-opening cycle# &fter the pressure is released,

and the "ell is flo"ed !ac, the "ell is pressured up in steps# 4hen the fracture re-opens, the pressure volume graph

deviates from the trend 'similar to lea-off(, and the Asurface fracture re-opening pressureA can !e determined# &fter re-

opening, the "ell is shut-in and the FCP is again determined from the pressure decline# Theoretically the F?P and the FCP

are e+ual, !ut differences may occur#

If the first and second FCP and the F?P are not consistent enough another cycle should !e considered#

2.5 >e&orting (leak-o test &rocedure$

Formation strength tests should !e reported in a consistent manner#

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&ctual measurements of pressures and volumes and an interpretation of the results should !e reported# &n accurate graph

on a large scale of volume pumped versus surface pressure should !e included in this report# It should !e indicated

"hether lea-off or formation !reado"n "as o!served#

If the measurement relates to a formation some distance !elo" the casing shoe, the conversion may !e slightly inaccurate#

In practice this difference is not taen into account, e)cept "hen a lea-off test is repeated at a different depth#

2.6 >e&eating a test (leak-o test &rocedure$

& lea-off or limit test may !e repeated some distance !elo" the previous measurement# This may !e done to confirm that

the strength of a ne" formation still satisfies the re+uirements for safe drilling, or to gain some additional formation

strength data#

It is recommended not to e)ceed the previous do"nhole test pressures unless there are reasons to assume that the

formation strength has increased 'for e)ample after a change in mud system(#

If lea-off or formation !reado"n is o!served during a su!se+uent test, it is difficult to identify the formation and the

e)act depth that the measurement relates to# The test can !e used to define a AsafeA area on a depth pressure plot# There is

no clear cut method to generate such a chart# Common sense should !e used to interpret the measurements to determine

the safe drilling envelop in "hich no formation !reado"n "ill occur#

,OAD CA$%

To carry out design calculations, the designer has to decide which load cases to use. This decision is based on

the li)elihood of occurrence and the ris)s involved if the load case does occur.

Burst loads

1. $urst during drilling

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$urst loads can occur during the drilling phase due to displacement of the borehole to hydrocarbons. There

are, however, a number of special cases to be considered. The base case and the special cases will be

addressed in this section.

1.1 +nternal pressure profile

The worst-case internal pressure loading is that following a complete loss of primary control corresponding to

full displacement of the casing to gas and the well closed-in at surface. The internal pressure profile is based

on a gas gradient ta)en from the pore pressure at T;. +f the gas-water contact 6=#7 in the structure is )nown,

the chosen gradient should be assumed to originate from this depth.

=here more information is available about the behaviour of the hydrocarbon phase, e.g. via VT data from

offset wells, a field-specific gas gradient should be used. =hen hydrocarbons with a very low gas&oil ratio are

encountered, the relevant oil gradient may be used. lthough hydrocarbons with a medium gas&oil ratio will

separate out once the well is shut in, it is very difficult to quantify a realistic internal pressure profile for this

case. 9ence, the approach for the worst-case internal pressure loading described above should be used.

The resultant pressure at the casing shoe should be compared with the formation brea)down pressure 6%$7 at

that depth. +f the pressure is in e'cess of the highest anticipated %$ the internal pressure profile should be

reduced accordingly. The hydrocarbon gradient will then e'tend upwards from this highest anticipated %$ at

the casing shoe.

1.4 2'ternal pressure profile

See article #ollapse

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The resultant pressure at the casing shoe should be compared with the formation brea)down pressure 6%$7 at

that depth. +f the pressure is in e'cess of the highest anticipated %$ the internal pressure profile should be

reduced accordingly. The pressure line with water gradient will then e'tend upwards from this highest

anticipated %$ at the casing shoe.

-..2. $alt loading

Salt loading is a time-dependent phenomenon and since its onset cannot be accurately predicted, it should be

assumed absent when calculating the e'ternal pressure profile for a burst scenario. This is (ust the opposite of

the rule given in Section 5.4.4.4 for collapse scenarios.

The internal pressure profile is that resulting from displacement of the casing to hydrocarbons or to water as

described for the case of the overpressured acquifer above.

4. $urst during production

$urst loading during the production phase will generally depend on whether the load is above or below the

production pac)er. $urst loads above the production pac)er are usually a result of tubing failure. There are,

however, a number of special cases to be considered. The base case and the special cases will be addressed

in this section.

4.1 +nternal pressure profile

2.-.- Abo&e the production pac(er

The ma'imum internal pressure profile e'perienced by the production casing will be that resulting from a lea) in

the production&in(ection tubing or test string at or near the surface. The appropriate surface pressure will then

be imposed on the pac)er fluid. The gradient of the pressure line is determined by the density of the fluid

between the tubing and the casing at the time.

%or production wells, the ma'imum surface pressure will be the closed-in tubing-head pressure 6#+T97, which

should be based in the worst case on a column of gas e'tending from the pressure at T;. +f the gas-water

contact 6=#7 in the structure is )nown, the pressure line with the chosen gradient should be assumed to

originate from this depth.

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=here more information is available about the behaviour of the hydrocarbon phase, e.g. via VT data from

offset wells, a reservoir-specific gas gradient should be used. =hen hydrocarbons with a very low gas&oil ratio

are encountered, the relevant oil gradient may be used. lthough hydrocarbons with a medium gas&oil ratio will

separate out once the well is shut in, it isvery difficult to quantify a realistic internal pressure profile for this

case. 9ence, the ma'imum #+T9 based on a gas column e'tending from the pressure at T; should be

assumed. suitable margin should be included in the #+T9 if squee*e )ill operations are to be considered.

%or in(ection wells, or wells where stimulation treatment may be performed, the ma'imum surface pressure will

be the in(ection-tubing-head pressure 6+T97 during the respective operations. The +T9 resulting from

stimulation treatment need only be considered when annuli cannot be monitored.

2.-.2. Belo" the production pac(er

The internal pressure profile below the pac)er for a production well is that corresponding to full displacement of

this section of the casing to hydrocarbons. =orst-case pressure calculations should be based on a pressure

line with gas gradient e'tending from the pressure at T;. +f the =# in the structure is )nown, the chosen

pressure line should be assumed to originate from this depth.

=here more information is available about the hydrocarbon phase behaviour, e.g. via VT data from offset

wells, a reservoir-specific gas gradient should be used. =hen hydrocarbons with a very low gas&oil ratio are

encountered, the relevant oil gradient may be used. lthough hydrocarbons with a medium gas&oil ratio will

separate out once the well is shut in, it is very difficult to quantify a realistic internal pressure profile for this

case. 9ence, the ma'imum loading based on a gas column e'tending from the pressure at T; should be

assumed. suitable margin should be included if squee*e )ill operations are to be considered.

%or an in(ection well, or wells where stimulation treatment may be performed, the internal pressure profile

below the pac)er should be that resulting from in(ection operations.

4.4 2'ternal pressure profile

See article #ollapse

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2..- Gaslift "ells

%or gas lift completions, the most severe internal pressure loading above the pac)er is that generated during

the )ic)-off process, when the )ic)-off pressure is applied to the top of the pac)er fluid.

2..2 $alt loading

Salt loading is a time-dependent phenomenon and since its onset cannot be accurately predicted, it should be

assumed absent when calculating the e'ternal pressure profile for a burst scenario.

+n gas-lift wells, a lea) in the production casing may impose the lift-gas in(ection pressure on the annulus fluid

column between the production casing and the intermediate casing. Special attention should be paid to the

internal pressure profile for this latter casing in subsea well design where control of this pressure is not

possible.

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#ollapse loads

1 2vacuation during drilling

#ollapse loads occurring during drilling are usually the result of borehole evacuation due to natural or induced

losses. There are however other cases to be considered.

1.1. +nternal pressure profile

+n a losses situation, the mud column will drop until the pore pressure at section T; is (ust balanced by the

pressure due to the mud column.

The evacuation level should always be the deepest that can occur and which gives the lowest evacuation level.

1.4. 2'ternal pressure profile

The e'ternal pressure profile for collapse during drilling should be constructed in two sections:

cement column

annulus fluid column.

-.2.-. Cement column

Set cement behaves as a porous matri' of low permeability 6micro to milli;arcy7 containing a pore fluid at a

certain pressure. The permeability of the cement around the casing is usually intermediate between those of a

high-permeability and of a low-permeability formation. =here the cement column is set across a high-

permeability formation 6milli;arcy and above7, the pressure in the cement will be equal to the pore pressure in

the formation. =here the cement column is set across a low-permeability formation 6micro;arcy and below7,

the pressure will depend on its quality.

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+t is assumed below for the sa)e of simplicity that the cement column only passes through one high-

permeability formation. +f it passes through more than one, the procedure described for e'ternal pressure

profiles should be followed.

Good cement column

9ere the cement column acts as an effective seal between the high-permeability formation and the top of

cement. The cement pore-pressure profile in the segment of cement column across the low-permeability

interval will then be such as to connect the pore pressure at the top of the high-permeability formation with the

pressure at the top of cement due to the hydrostatic pressure of the annulus fluid. The cement pore-pressure

profile across the low-permeability interval is thus semi-static.

Poor cement column

+n this case, the cement column no longer acts as an effective seal between the high-permeability formation

and the top of cement. The pressure gradient in the cement across the low-permeability interval will then be

equal to the cement mi'water gradient. The pressure at the top of cement is therefore determined by drawing a

pressure line with this gradient upwards from the pressure at the top of the high-permeability formation. s a

result, the annulus pressure line will be shifted to lower pressures in low-pressure reservoirs and to higher

pressures in high-pressure reservoirs. This leads to an annulus level drop or an annulus pressure build-up.

General cement column

Io matter whether the cement column is good or bad, the cement pore-pressure profile below the high-

permeability formation is given by a line of slope equal to the cement mi'water gradient e'tending downwards

from the pressure at the bottom of the high-permeability formation to the casing shoe.

%or the determination of the cement pore-pressure profile in the cement column opposite a previous casing,

this previous casing should be treated as a low-permeability formation.

+n the event that the cement column does not pass through a high-permeability formation anywhere, the

cement mi'water gradient may be assumed to e'tend downwards from the top of cement to the casing shoe,

no matter whether the quality of the cement is high or low. The pressure at the top of cement will be equal to

the hydrostatic pressure of the annulus fluid.

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-.2.2. Annulus fluid column

+n view of the relatively short duration of the drilling phase, deterioration of the annulus fluid during drilling

should not be ta)en into account, either for e'ploration or for development wells. The pressure gradient in the

annulus fluid will therefore be determined by the density of the fluid used at the time of the cement (ob.

+n the case of a high-quality cement column over a high-permeability formation, the annulus-fluid pressure line

e'tends downwards with the above-mentioned gradient from *ero pressure at the wellhead to the top of

cement. %or a low-quality cement column across a high-permeability formation, the annulus-fluid pressure line

e'tends upwards with the same gradient from the pressure at the top of cement towards the wellhead. This can

lead to annulus pressure in a high-pressure reservoir, or to annulus fluid drop in a low-pressure reservoir.

+f the cement column does not pass through any high-permeability formations, the annulus-fluid pressure line

e'tends downwards from *ero pressure at the wellhead to the top of cement, no matter what the quality of the

cement

1.5. Special cases

-..-. Air# foam or aerated drilling

=hen air drilling is applied, the wellbore pressure could become atmospheric in the event of system failure.

Similarly, foam drilling is sub(ect to the ha*ard that the foam can lose stability and the liquid phase can drop

out. +f these scenarios are considered li)ely, the casing should therefore be designed to withstand full internal

evacuation - unli)e the base case, where evacuation is li)ely to be only partial.

%or aerated drilling, the designer should consider the internal evacuation level that can be e'pected based on

the pore-pressure profile in the event of a system failure preventing fluid supply.

-..2. $alt loading

Salt loading is modelled as if it were an e'ternal fluid pressure equal to the overburden pressure at the depth of

the salt formation. The e'ternal pressure profile with the salt loading gives rise to a step change in the e'ternal

pressure profile at the top and bottom of the salt formation.

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Salt loading is a time-dependent phenomenon but since its onset cannot be accurately predicted, the loading

should always be assumed when designing for collapse in the drilling phase.

-... )ormation compaction

2'ternal loading due to formation compaction should replace, where applicable, that resulting from annulus-

fluid and cement-column pressures.

-..0. Blo"out

+f the casing design is to cater for a blowout scenario, full evacuation of the string to atmospheric pressure must

be assumed for the internal pressure profile. This condition represents a blowout where the open hole

formation bridges and the gas pressure at surface is allowed to bleed to *ero.

+t should be noted, however, that during the actual blow-out preceding the full evacuation, the casing integrity

might be reduced. To ma)e the design for this scenario fit for purpose, a realistic wear margin should be ta)en

into account when selecting the casing.

4 2vacuation during production

#ollapse loads during the production phase generally occur as a result of evacuation resulting from natural or

induced losses during wor)over of the well. There are also, however, a number of special cases to be

considered. The base case and the special cases will be addressed in this section.

4.1. +nternal pressure profile

2.-.-. Belo" the production pac(er

The casing below the production pac)er must always be designed to withstand full internal evacuation to

atmospheric pressure. This is to account for high drawdowns, differential depletion, and bac)-surging

operations.

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2.-.2. Abo&e the production pac(er

#asing above the production pac)er is usually not sub(ect to critical collapse loading during normal production

operations.

;uring completion and wor)over, however, mud&brine losses may lead to evacuation of the upper section of the

production casing. The deepest possible evacuation level should be calculated based on the pore pressure

profile and the fluid density in use.

2.-.. $pecial cases

Special cases li)e gas lift and pump-off are dealt with later.

4.4. 2'ternal pressure profile

The e'ternal pressure profile for collapse during production should be constructed in two sections - that for the

cement column and that for the annulus fluid column - as described below.

2.2.-. Cement column

Set cement behaves as a porous matri' of low permeability 6in the micro;arcy to milli;arcy range7 containing a

pore fluid at a certain pressure. The permeability of the cement around the casing is usually intermediate

between those of a high-permeability and of a low-permeability formation. =here the cement column is set

across a high-permeability formation 6milli;arcy and above7, the pressure in the cement will be equal to the

pore pressure in the formation. =here the cement column is set across a low-permeability formation

6micro;arcy and below7, the pressure will depend on its quality.

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shallowest high-permeability formation will then be semi-static, connecting the pore pressure at the top of this

high-permeability formation with the pressure at the top of cement due to the hydrostatic pressure of the

annulus fluid. The pressure profile in the segment of cement column lying across the low-permeability interval

between two high-permeability formations will also be semi-static, connecting the pore pressures at the bottom

and top of the high-permeability formations it straddles.

Poor cement column

+n this case, the cement column no longer acts as an effective seal between the high-permeability formation6s7

and the top of cement. The pressure gradient in the cement across the low-permeability interval above the

shallowest high-permeability formation will then be equal to the cement mi'water gradient. The pressure profile

in the segment of cement column lying across the low-permeability interval between two high-permeability

formations will be semi-static, connecting the pore pressures at the bottom and top of the high-permeability

formations it straddles. The pressure at the top of cement will therefore be determined by drawing a pressure

line of slope equal to the cement mi'water gradient upwards from the pressure at the top of the shallowest

high-permeability formation. This leads to an annulus level drop or an annulus pressure build-up.

General cement column

Io matter whether the cement column is good or bad, the cement pore-pressure profile below the deepest

high-permeability formation is given by a line of slope equal to the cement mi'water gradient e'tending

downwards from the pressure at the bottom of the high-permeability formation to the casing shoe.

%or the determination of the pore-pressure profile in the cement column opposite a previous casing, this

previous casing should be treated as a low-permeability formation.

2.2.2. Annulus fluid column

Since casing strings can have a much longer service life in the production phase than in the drilling phase,

deterioration of the annulus fluid should be ta)en into account in production-casing design for development

wells. The pressure gradient in the annulus fluid in such cases may thus be determined by the density of the

fluid used at the time of the cement (ob, or by the density of the deteriorated fluid, depending on the elapsed

time and on the inherent stability of the annulus fluid. =hile brines and bentonite&water-based muds are stable

with time, the density of oil-based and polymer&water-based muds is liable to drop to that of the base fluid.

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+n the case of a high-quality cement column over a high-permeability formation, the annulus-fluid pressure line

e'tends downwards with the above-mentioned gradient from *ero pressure at the wellhead to the top of

cement.

%or a low-quality cement column across a high-permeability formation, the annulus-fluid pressure line e'tends

upwards with the same gradient from the pressure at the top of cement towards the wellhead.

%1ploration "ells

%or e'ploration wells used for short-term production tests, it can be assumed that the annulus-fluid pressure

gradient is determined by the fluid density at the time of cementation.

De&elopment "ells

%or development wells it may be assumed that the annulus-fluid pressure gradient will be equal to that for the

base fluid for oil-based or polymer&water-based muds 6which are liable to deterioration7, but will remain at the

value prevailing at the time of the cement (ob for brines and bentonite&water-based muds 6which are inherently

stable7.

4.5. Special cases

Artificiallift "ells

as-lift well production casing above the pac)er should always be designed for complete internal evacuation to

atmospheric pressure, to account for complete venting of the tubing&production-casing annulus as a result of

surface-equipment failure.

%or artificial lift equipment wor)ing in pump-off mode, where usually no downhole pac)er is installed, the casing

should also be designed for complete internal evacuation to account for the low annulus wor)ing pressure.

$alt loading

Salt loading is modelled as if it were an e'ternal fluid pressure equal to the overburden pressure at the depth of

the salt formation. The salt loading gives rise to a step change in the e'ternal pressure profile at the top and

bottom of the salt formation.

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Salt loading is a time-dependent phenomenon but since its onset cannot be accurately predicted, the loading

should always be assumed when designing for collapse in the production phase.

)ormation compaction

2'ternal loading due to formation compaction should replace, where applicable, that resulting from annulus

fluid and cement column pressures.

Blo"out

+f the casing design is to cater for a blowout scenario, full evacuation of the string to atmospheric pressure must

be assumed for the internal pressure profile. This condition represents a blowout where the internal pressure

due to an uncontrolled gas flow is very low.

+t should be noted, however, that during the actual blow-out preceding the full evacuation, the casing integrity

might be reduced. To ma)e the design for this scenario fit for purpose, a realistic wear margin should be ta)en

into account when selecting the casing.

+nstallation loads

fter the casing string has been designed to withstand the anticipated collapse and burst loads, it should be

chec)ed against the loads that will be e'perienced during the installation, and against the loads e'perienced

during cementation and pressure testing.

Such loads are calculated on the basis that the string is fi'ed 6suspended7 at surface but free to move at the

shoe.

These loads should include:

1. Self weight 6in air7 loads?

4. ressure 6buoyancy7 loads?

5. $ending loads?

E. ;ynamic drag loads?

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3. Shoc) loads?

Q. oint loads?

H. Static drag loads.

Temperature effects do not lead to additional stresses in the installation phase since the casing is free to move

at the shoe.

$elow a brief description of the origin of these loads is included.

1. Self weight 6in air7 loads: The self weight load is the load imposed on the string by gravitational effects

6sa7. This load depends on the weight per unit length of the string and the suspended vertical length below a

point at the pipe a'is.

4. ressure 6buoyancy7 loads: The pressure load, which results when casing is submerged in the drilling

fluid, mud and&or cement, is generally referred to as the buoyancy load 6sa, sr, st7. This load is the result of the

integration of the hydrostatic pressure over the submerged internal, e'ternal and free-end surface of the

casing. +t will depend on the density of the fluid6s7 in which the casing is submerged, the presence of any

applied surface pressures, and the vertical depth of the casing. Typical e'amples are the dynamic pressure

loads generated when circulating mud prior to a cement (ob and during the actual cementation. The hydrostatic

pressure load caused by the difference in fluid densities, acting on the sealing casing shoe after the

cementation, also falls in this category.

5. $ending loads: $ending of the pipe through any curved portion of the hole will induce bending stresses

in the pipe walls 6sa7. Such stresses will be tensional in the outer or conve' wall and compressional in the inner

or concave wall. $ending is induced directly by the well path. The drilled well tra(ectory may be intentional, as

with a build-up or drop-off, but may equally be inadvertent due to changes in formation, dip, drilling assembly,

or applied drilling operation

E. ;ynamic drag loads: ;ynamic drag loads are the result of sliding resistance between the casing and

the borehole wall. The velocity profile at the point of contact results in a'ial and tangential drag force

components. 9ence, drag loads may result in torsional 6t7 and a'ial stresses 6sa7. ;rag loads can vary

considerably as a function of hole conditions, hole and casing geometry, and the mud system in use.

3. Shoc) loads: =hen a casing that is being run into the hole is suddenly obstructed at a point

somewhere along the casing, two shoc) waves will be generated: an upward travelling compression wave

above the contact point and a downward travelling tension wave below that point 6sa7. similar effect occurs

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when the casing is being pulled out-of-hole and it is suddenly stopped. Then the tension wave will travel

upwards the compression wave downwards. The origin of shoc) load can be found in for e'ample the spider

elevator early closing or the casing string hanging up on a ledge.

Q. oint loads: oint loads, in the installation phase, result usually from operational activities related to

pressure testing 6sa, sr, st7. %or e'ample, pressure testing using retrievable pac)ers or directly after the cement

displacement.

H. Static drag loads: These drag loads, referring to the remaining stresses after casing movement, have

an influence on the distribution of stresses within the casing after it has stopped moving 6s a7. 2valuation of

these loads requires a )nowledge of the movement 8history8 of the casing. Subsequent behaviour of the casing

depends on the magnitude and direction of these 8sliding resistance8 loads.

The casing design should be chec)ed against the combinatio