Casing Design Manual

ARPOENI S.p.A.Agip Division

ORGANISINGDEPARTMENT

TYPE OFACTIVITY'

ISSUINGDEPT.

DOC.TYPE

REFER TOSECTION N.

PAGE. 1

OF 134STAP P 1 M 6110

The present document is CONFIDENTIAL and it is property of AGIP It shall not be shown to third parties nor shall it be used forreasons different from those owing to which it was given

TITLE

CASING DESIGN MANUAL

DISTRIBUTION LIST

Eni - Agip Division Italian Districts

Eni - Agip Division Affiliated Companies

Eni - Agip Division Headquarter Drilling & Completion Units

STAP Archive

Eni - Agip Division Headquarter Subsurface Geology Units

Eni - Agip Division Headquarter Reservoir Units

Eni - Agip Division Headquarter Coordination Units for Italian Activities

Eni - Agip Division Headquarter Coordination Units for Foreign Activities

NOTE: The present document is available in Eni Agip Intranet (http://wwwarpo.in.agip.it) and a CD-Rom version can also be distributed (requests will be addressed to STAP Dept. in Eni -Agip Division Headquarter)

Date of issue:

Issued by P. MagariniE. Monaci

C. Lanzetta A. Galletta

28/06/99 28/06/99 28/06/99

REVISIONS PREP'D CHK'D APPR'D

28/06/99

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ENI S.p.A.Agip Division

IDENTIFICATION CODE PAGE 2 OF 134

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INDEX

1. INTRODUCTION 5

1.1. PURPOSE OF CASING 6

2. CASING PROFILES AND DRILLING SCENARIOS 7

2.1. Casing Profiles 72.1.1. Onshore Wells 72.1.2. Offshore Wells - Surface Wellhead 72.1.3. Offshore Wells - Surface Wellhead & Mudline Suspension 72.1.4. Offshore Wells - Subsea Wellhead 7

2.2. Drive, Structural & Conductor Casing 82.2.1. Surface Casing 82.2.2. Intermediate Casing 92.2.3. Production Casing 102.2.4. Liner 11

3. SELECTION OF CASING SEATS 12

3.1. Conductor Casing 15

3.2. Surface Casing 15

3.3. Intermediate Casing 15

3.4. Drilling Liner 16

3.5. Production Casing 17

3.6. CASING AND relative HOLE SIZES 173.6.1. Standard Casing and Hole Sizes 21

4. CASING SPECIFICATION AND CLASSIFICATION 22

4.1. CASING SPECIFICATION 22

4.2. API CASING CLASSIFICATION 23

4.3. NON-API CASING 25

5. MECHANICAL PROPERTIES OF STEEL 28

5.1. General 28

5.2. Stress-Strain Diagram 28

5.3. Heat Treatment Of Alloy Steels 30

6. TUBULAR RANGE LENGTHS & COLOUR CODING 36

6.1. Range lengths 36

6.2. api tubular marking and colour coding 386.2.1. Markings 386.2.2. Colour Coding 39

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7. APPROACH TO CASING DESIGN 41

7.1. WELLBORE FORCES 42

7.2. DESIGN FACTOR (DF) 427.2.1. Company Design Factors 447.2.2. Application of Design Factors 45

8. DESIGN CRITERIA 46

8.1. BURST 468.1.1. Design Methods 468.1.2. Company Design Procedure 47

8.2. COLLAPSE 508.2.1. Company Design Procedure 50

8.3. TENSION 548.3.1. General 548.3.2. Buoyancy Force 548.3.3. Company Design Procedure 598.3.4. Example Hook Load During Cementing 59

8.4. BIAXIAL STRESS 628.4.1. General 628.4.2. Effects On Collapse Resistance 628.4.3. Company Design Procedure 648.4.4. Example Collapse Caclulation 65

8.5. BENDING 678.5.1. General 678.5.2. Determination Of Bending Effect 688.5.3. Company Design Procedure 708.5.4. Example Bending Calculation 70

8.6. CASING WEAR 728.6.1. General 728.6.2. Volumetric Wear Rate 738.6.3. Factors Affecting Casing Wear (Example) 768.6.4. Wear Factors 808.6.5. Detection Of Casing Wear 868.6.6. Casing Wear Reduction 868.6.7. Wear Allowance In Casing Design 878.6.8. Company Design Procedure 88

8.7. SALT SECTIONS 898.7.1. General 898.7.2. External Loading Due To Salt Flow 898.7.3. Company Design Procedure 94

9. CORROSION 96

9.1. General 969.1.1. Exploration and Appraisal Wells 969.1.2. Development Wells 969.1.3. Contributing Factors to Corrosion 97

9.2. Forms Of Corrosion 989.2.1. Sulphide Stress Cracking (SSC) 989.2.2. Corrosion Caused By CO2 And Cl- 105

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9.2.3. Corrosion Caused By H2S, CO2 And Cl- 107

9.3. Corrosion Control Measures 108

9.4. Corrosion Inhibitors 109

9.5. Corrosion Resistance of Stainless Steels 1099.5.1. Martensitic Stainless Steels 1099.5.2. Ferritic Stainless Steels 1109.5.3. Austenitic Stainless Steels 1109.5.4. Precipitation Hardening Stainless Steels 1109.5.5. Duplex Stainless Steel 111

9.6. Casing For Sour Service 113

9.7. Ordering Specifications 114

9.8. Company Design Procedure 1149.8.1. CO2 Corrosion 1149.8.2. H2S Corrosion 115

10. TEMPERATURE EFFECTS 118

10.1. High Temperature Service 118

10.2. Low Temperature Service 119

11. LOAD CONDITIONS 120

11.1. SAFE ALLOWABLE TENSILE LOAD 120

11.2. CEMENTING CONSIDERATIONS 12011.2.1. Casing Support 12011.2.2. Cementing Loads 121

11.3. PRESSURE TESTING 122

11.4. BUCKLING AND COMPRESSIve loading 12211.4.1. Buckling 12211.4.2. Compressive Loads 123

12. PRESSURE RATING OF BOP EQUIPMENT 126

12.1. BOP selection criteria 126

12.2. Kick tolerance 129

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1. INTRODUCTION

The selection of casing grades and weights is an engineering task affected by many factors,including local geology, formation pressures, hole depth, formation temperature, logistics andvarious mechanical factors.

The engineer must keep in mind during the design process the major logistics problems incontrolling the handling of the various mixtures of grades and weights by rig personnel withoutrisk of installing the wrong grade and weight of casing in a particular hole section. World-wide,experience has shown that the use of two/three different grades or two/three different weightsis the maximum that can be handled by most rigs and rig crews.

After selecting a casing for a particular hole section, the designer should consider upgradingthe casing in cases where:

Extreme wear is expected from drilling equipment used to drill the next holesection or from wear caused by wireline equipment.

Buckling in deep and hot wells.

Once the factors are considered, casing cost should be considered.

If the number of different grades and weights are necessary, it follows that cost is not alwaysa major criterion.

Most major operating companies have differing policies for the design of casing for explorationand development wells, e.g:

For exploration, the current practice is to upgrade the selected casing,irrespective of any cost factor.

For development wells, the practice is also to upgrade the selected casing,irrespective of any cost factor.

For development wells, the practice is to use the highest measured bottomholeflowing pressures and well head shut-in pressures as the limiting factors forinternal pressures expected in the wellbore. These pressures will obviously placecontrols only on the design of production casing or the production liner, andintermediate casing.

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1.1. PURPOSE OF CASING

Casing tubulars are placed in a wellbore for the following reasons:

a) Supporting the weight of the wellhead and BOP stack.b) Providing a return path for mud to surface when drilling.c) Controlling well pressure by containing downhole pressure.d) Isolating high pressure zones from the wellbore.e) Isolating permeable zones from the wellbore which are likely to cause differential

sticking.f) Isolating special trouble zones which may cause hole problems e.g.:

Swelling clay, shales. Sloughing shales. Plastic formations (evaporites). Formations causing mud contamination e.g. gypsum, anhydrite, salt. Frozen unconsolidated layers in permafrost areas. Lost circulation zones.

g) Separating different pressure or fluid regimes.h) Providing a stable environment for packers, liner hangers, etc.i) Isolating weak zones from the wellbore during fracturing.j) Isolating permeable productive formations, reducing the risk of underground

blowouts.k) Confining produced fluid to the wellbore and providing a flow path to surface.

Production casing must perform a number of critical functions as follows:

a) Providing internal pressure containment when the tubing system leaks or fails.b) Preventing wellbore fluids from contaminating production.c) Providing protection for completion equipment.d) Providing access to producing formations for remedial operations.e) Providing cement integrity across producing formations.

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2. CASING PROFILES AND DRILLING SCENARIOS

2.1. CASING PROFILES

The following are the various casing configurations which can be used for onshore andoffshore wells.

2.1.1. Onshore Wells

Drive/structural/conductor casing Surface casing Intermediate casings Production casing Intermediate casing and drilling liners Intermediate casing and production liner Drilling liner and tie-back string.

2.1.2. Offshore Wells - Surface Wellhead

As in onshore above.

2.1.3. Offshore Wells - Surface Wellhead & Mudline Suspension

Drive/structural/conductor casing Surface casing and landing string Intermediate casings and landing strings Production casing Intermediate casings and drilling liners Drilling liner and tie-back string.

2.1.4. Offshore Wells - Subsea Wellhead

Drive/structural/conductor casing Surface casing Intermediate casings Production casing Intermediate casing and drilling liners Intermediate casing and production liner Drilling liner and tie-back string.

Refer to the following sections for descriptions of the casings listed above.

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2.2. DRIVE, STRUCTURAL & CONDUCTOR CASING

The purpose of this first string of pipe is primarily to protect incompetent surface soils fromerosion by drilling fluids. Where formations are sufficiently stable, this string may be used toinstall the full mud circulation system.

It also serves the following purposes:

Guide the drilling string and subsequent casing into the hole. The conductor inoffshore drilling may form a part of the piling system for a wellhead jacket or piledplatform.

Provide centralisation for the inner casing strings which limits column buckling.They do not carry direct axial loads except during initial installation of the surfacecasing.

Reduce wave and current loadings imposed on the inner strings. Provide sacrificial protection against oxygen corrosion in the splash zone. Minimise the transfer of stresses to the inner casings resulting from the

settlement and rotational movement of gravity platforms.

The conductor casings are usually driven completely to depth or, alternatively, run into apredrilled or jetted hole and cemented. If they are driven, they must be designed to withstandhammering loads.

Conductor casings, in offshore drilling with subsea BOP's, are usually either jetted into placeor cemented in a predrilled hole. They support a Temporary Guide Base whichaccommodates and aligns all future wellhead installations for both the drilling and productionphases. They directly carry both the axial and bending loads imposed by the wellhead, but arerigidly connected to the next casing with centralisers and cement in order to dissipate loadingand minimise resulting stresses.

2.2.1. Surface Casing

The surface casing is installed to:

Prevent poorly consolidated shallow formations from sloughing into the hole. Enable full mud circulation. Protect fresh water sands from contamination from the drilling mud. Provide protection against hydrocarbons found at shallow depths.

The surface casing string is cemented to surface or seabed and is the first casing on whichBOPs can be mounted. It is important to appreciate that the amount of protection providedagainst internal pressure will only be as strong as the formation strength at the casing shoe,hence it may be necessary to vent any influx taken through the surface string, rather thanattempt containment.

The surface string usually supports the wellhead and subsequent casing strings.

In offshore wells, above the top of the cement, the surface casing must be centralised to limitcolumn buckling.

The annulus between the conductor and surface string is usually left uncemented above themudline to minimise load transfer and bending stresses in the surface string.

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2.2.2. Intermediate Casing

These are used to ensure there is adequate blow-out protection for deeper drilling and toisolate formations or hole profile changes, that can cause drilling problems.

The first intermediate string is the first casing providing full blow-out protection. Its settingdepth is often chosen so that it also isolates troublesome formations, loss zones, shallowhydrocarbons, water sands, or the build-up section of deviated wells. It is usually cementedup into the shoe of the conductor string and in some cases all the way to surface.

It is essential to install an intermediate casing string whenever there is a risk of experiencing akick which could cause breakdown at the previous casing shoe, and/or severe losses in theopen hole section.

An intermediate casing string is, therefore, nearly always set in the transition zone above orbelow significant overpressures, and in any cap rock below a potential severe loss zone.Similarly, it is good practice when appraising untested or deeper horizons, to case off theknown hydrocarbon bearing intervals as a contingency against the possibility of encounteringa loss circulation zone. Obviously the latter is intended primarily for massive reservoirsections rather than sand-shale sequences with numerous small reservoirs and sub-reservoirs. An intermediate string may also be set simply to reduce the overall cost of drillingand completing the well by isolating intervals which have been found to cause mechanicalproblems in the past.

For example it may be desirable to isolate:

Swelling gumbo shale. Brittle caving shale. Creeping salt. Over-pressured permeable stringer. Build-up or drop-off section. High permeability sand. Partly depleted reservoir that causes differential sticking.

The designer should plan to combine many of these objectives when selecting a singlecasing point. A liner may be used instead of a full intermediate casing and difficult wells mayactually contain several intermediate casings and/or liners. Caution should be taken whenusing liners as it is necessary to ensure the higher casing is designed for the pressures atlower depths.

The cement should cover all hydrocarbon zones and any salt or other creeping evaporites.Zones containing highly corrosive formation waters are also often cemented off, especiallywhere there may be aquifer movement which replenishes the corrosive elements around thewellbore.

Longer cement columns are sometimes required to prevent buckling of the casing duringdeeper drilling. Many operating companies cement up inside the previous casing shoe for thisreason and is legislated on by some regulatory authorities.

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2.2.3. Production Casing

This is the string through which the well will be completed, produced and controlledthroughout its life.

On exploration wells this life may amount to only a very short testing period, but on mostdevelopment wells it will span a significant number of years during which many repairs andrecompletions may be performed. It is essential therefore that production casing retains itsintegrity throughout its life.

In most cases, the production casing will serve to isolate the productive intervals, to facilitateproper reservoir maintenance and/or prevent the influx of undesired fluids. In other cases,accumulation conditions are such that the well can be cased with an open hole section belowthe casing for an open hole completion (Refer to the completion design manual). The size ofthe production casing should be selected to meet with the desired method of completion andproduction.

On production wells the drilling engineer must design the casing in conjunction with thecompletion engineer to ensure the optimum completion design is obtained. This usuallyimpacts on the production casing design with regard to:

Well flow potential, i.e. tubing size. The possibility of a multiple tubing string completion. The space required for downhole equipment e.g. safety valves, artificial lift

equipment etc. The geometry required for efficient through-tubing well intervention operations. Potential well servicing and recompletion requirements. Adequate annular clearances to permit circulation at reasonable rate and

pressures.

It is also possible that the casing itself could be used as a conduit for maximising welldeliverability (casing flow), for minimising the pressure losses during frac jobs, for chemicalinjection or for lift gas. Consideration must be given to production operations which will affectthe temperature of the production casing and impose additional thermal stresses. Annulusthermal expansion can cause production casing collapse when it is cemented up into theintermediate casing. The loads to which a production casing is subjected are, therefore, quitedifferent from those imposed during drilling.

It is very important that the selection of the steel grade and connections for the productionstring are made correctly.

Special considerations are required where the production casing will be drilled through andmay therefore suffer some damage e.g.: open hole (barefoot) completions, open hole gravelpacks, liner completions, deep zone appraisal.

In a liner completion, both the liner and casing form the production string and must bedesigned accordingly.

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2.2.4. Liner

A liner is a string of pipe which is installed but does not extend all the way to surface. It ishung a short distance above the previous casing shoe and is usually cemented over its entirelength to ensure it seals within the previous casing string.

Drilling liners may be installed to:

Increase shoe strength. Meet with rig tensional load limitations. Minimise the length of reduced diameter and the possible adverse effects on

drilling hydraulics.

Production liners may be installed to:

Reduce costs. Minimise the length of reduced diameter production tubing and the consequent

adverse effect upon well flow potential. Meet with rig tensional load limitations on occasions on deep wells.

Either type of liner may subsequently be tied-back to surface with a string of pipe stabbed intoa liner hanger Polished Bore Receptacle (PBR).

There are a number of disadvantages to installing liners, including:

The risk of poor pressure integrity, either across the liner lap due to poorcementation or as a result of wear to the casing from which the liner is hung off.

The risk of the liner running equipment being cemented in the hole. The difficulty of obtaining a good cementation due to smaller liner to hole and liner

to production casing clearances. The need to set a retrievable bridge plug above the liner lap if the BOP stack

needs to be removed. (This does not apply to completion operations when atubing string has been run and landed.)

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3. SELECTION OF CASING SEATS

The selection of casing setting depths is one of the most critical in the well design processand is based on:

Total depth of well. Pore pressures. Fracture gradients. The probability of shallow gas pockets. Problem zones. Depth of potential prospects. Time limits on open hole drilling. Casing programme compatibility with existing wellhead systems. Casing programme compatibility with planned completion programme (production

well). Casing availability (grade and dimensions). Economy, i.e. time consumption to drill the hole, run casing and cost of

equipment.

When planning, all available information should be carefully documented and considered toobtain knowledge of the various uncertainties.

Information is sourced from:

Evaluation of the seismic and geological background documentation used as thedecision for drilling the well.

Drilling data from offset wells in the area. (Company wells or scoutinginformation).

The key factor to satisfactory picking of casing seats is the assessment of pore pressure andfracture pressures throughout the well.

As the pore pressures in a formation being drilled approach the fracture pressure at the lastcasing seat then installation of a further string of casing is necessary.

figure 3.a and figure 3.b show typical examples of casing seat selections.

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Figure 3.A - Example of Idealised Casing Seat Selection

Notes to figure 3.a above:

a) Casing is set at depth 1, where pore pressure is P1 and the fracture pressure isF1.

b) Drilling continues to depth 2, where the pore pressure P2 has risen to almostequal the fracture pressure (F1) at the first casing seat.

c) Another casing string is therefore set at this depth, with fracture pressure (F2).d) Drilling can thus continue to depth 3, where pore pressure P3 is almost equal to

the fracture pressure F2 at the previous casing seat.This example does not include any safety or trip margins, which would, in practice, be takeninto account.

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Figure 3.B - Example Casing Seat Selection(for a typical geopressurised well using a pressure profile).

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3.1. CONDUCTOR CASING

Setting depth is usually shallow and selected so that drilling fluid may be circulated to the mudpits while drilling the surface hole. The casing seat must be in an impermeable formation withsufficient fracturing resistance to allow fluid circulation to the surface.

Where working with subsea wellheads, no there is no circulation through the conductor stringto the surface. It is set deep enough to assist in stabilising the guide base to which guide linesare attached.

Large sizes are required (usually 16ins to 30ins diameter) as necessary to accommodate thesize of all subsequently required strings.

3.2. SURFACE CASING

Setting depths should be in an impermeable section below any fresh water formations.

In some instances, near-surface gravel or shallow gas may need to be cased off shallower.

The depth should be great enough to provide a fracture gradient sufficient enough to allowdrilling to the next casing setting point and to provide reasonable assurance that broaching tothe surface will not occur in the event of BOP closure to contain a kick.

In hard rock areas the string may be relatively shallow, but in soft rock areas deeper stringsare necessary.

3.3. INTERMEDIATE CASING

The most predominant use of intermediate casing is to protect normally pressured formationsfrom the effects of increased mud weight needed in deeper drilling.

An intermediate string may be necessary to case off lost circulation zones, salt beds, orsloughing shales.

In cases of pressure reversals against depth, intermediate casing may be set to allowreduction of mud weight.

When a transition zone is penetrated and mud weight increased, the normal pressure intervalbelow surface pipe is subjected to two detrimental effects:

The fracture gradient may be exceeded by the mud gradient, particularly if itbecomes necessary to close-in on a kick The result is loss of circulation and thepossibility of an underground blow-out occurring.

The differential between the mud column pressure and formation pressure isincreased, increasing the risk of stuck pipe.

To ensure the integrity of the surface casing seat, leak-off tests are necessary and must bespecified in the Drilling Programme.

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Sometimes it is necessary to alter the setting depth of the intermediate casing during drillingunder certain circumstances such as when:

Hole problems prohibit further drilling. Pore pressure changes occur substantially shallower or deeper than originally

calculated or estimated. For this reason the Geological Drilling Programme shouldstate the pore pressure requirement at which casing should be set when settingcasing into a transition zone.

3.4. DRILLING LINER

The setting of a drilling liner is often an economically attractive decision in deep wells asopposed to setting a full string. Such a decision must be carefully considered as theintermediate string must be designed for burst as if it were set to the depth of the liner.

If drilling is to be continued below the drilling liner then burst requirements for the intermediatestring are further increased which increases the cost of the intermediate string. Also, there isthe possibility of continuing wear of the intermediate string that must also be evaluated.

If a production liner is planned, then either the production liner or the drilling liner should betied back to the surface as a production casing.

If the drilling liner is to be tied-back, it is usually better to do so before drilling the hole for theproduction liner. By doing this, the intermediate casing can be designed for a lower burstrequirement, resulting in considerable cost savings. Also, any wear to the intermediate stringis spanned prior to drilling the producing interval.

If increasing mud weight will be required, while drilling hole for the drilling liner, then leak-offtests must be conducted and specified in the casing programme for the intermediate casingshoe within the Geological Drilling Programme (Refer to the Drilling Procedures Manual).

Insufficient fracture gradient at the shoe may limit the depth of the drilling liner.

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3.5. PRODUCTION CASING

Whether production casing or a liner is installed, the depth is determined from the geologicalobjective. Depths, hence the casing programme, may have to be altered accordingly if depthscome in too high or too low.

The objective and the method of identifying the correct production casing depth should alsobe stated in the programme.

To cater for some completion operations, a sufficient amount of sump is required for fill duringproduction or well intervention operations, run out for logging tools and to accommodate losttools or dropped TCP guns, etc. Drilling extra hole, for dropping TCP guns or similar reasons,may be costly and the effectiveness of such considerations should be seriously evaluatedbefore commitment.

3.6. CASING AND RELATIVE HOLE SIZES

In general, it is good practice to run standard bit sizes but in deep wells, thick walled casingmay be necessary to provide sufficient strength. The designer can sometimes solve thisproblem by specifying special drift casing which will allow running of bits with diametersapproaching the casing inside diameter rather than being limited to drift diameter.

Manufacturers produce oversize casing in several sizes providing strength comparable to APIsizes, but with clearances to suit standard bit sizes. A typical well may have 30ins drive/structural/conductor casing, 20ins surface casing, 133/8ins and 95/8ins intermediate casingand 7ins production casing/liner.

Although the above is one of the most common arrangements, there is a multitude of differentcombinations of casing sizes which the operator may choose to use if he desires, and if thecasing design allows.

For a normal exploration well, it is recommended that an 81/2ins hole be the smallest diameterplanned because of drilling and evaluation difficulties encountered with 6ins. A 6ins hole sizeshould only be planned as a contingency.

figure 3.c shows the choice of casing and bit sizes available to engineers.

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Figure 3.C - Casing and Bit Selection Chart

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The chart in figure 3.c can be used to select the casing bit sizes required to fulfil many drillingprogramme options.

To use the chart:

1) Determine the casing or liner size for the last size pipe to be installed.2) Enter the chart at that point.3) The flow of the chart then indicates hole sizes that may be required to set that size pipe

(i.e., 5 Liner inside 6 or 61/2 hole).Solid lines indicate commonly used bits for that size pipe and can be considered tohave adequate clearance to run and cement the casing or liner (i.e., 51/2 Casing inside77/8 hole).

The broken lines indicate less common optional hole sizes used (i.e., 5 inside 61/8hole, etc.).

The selection of one of these broken paths requires special attention be given to theconnection, mud weight, cementing and doglegs.

Large connection ODs, thick mud cake build-up, problem cementing areas (high waterloss, lost returns, etc.) and doglegs all aggravate the attempt to run casing and liners inlow clearance situations.

Once the hole size has been selected. a casing large enough to allow passage of a bitto make that hole can be selected. The solid lines are commonly required casing sizes.encompassing most weights (i.e., 61/2 bit inside 75/8 casing).The broken lines indicate casing sizes where only the lighter weights can be used(i.e. 61/8 inside 7 casing).

This selection process is repeated until the anticipated number of casing sizes hasbeen reached.

Note: Some drilling programmes can require special tools and operations toobtain the wellbore size for the casing to be installed. An underreamer isa drilling tool, used to enlarge section of hole below a restriction(situations where equipment, such as BOP or wellhead size restrictions,limit the tool entry size).

figure 3.d shows the standard casing programme and figure 3.e the possible alternative.further standard casing and hole sizes information is shown in table 3.a.

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Figure 3.D - Standard Casing Programme

Figure 3.E - Alternative Casing Programme

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3.6.1. Standard Casing and Hole Sizes

Outer CasingSize

Largest InnerCasing Size

Under-Reaming

Minimum PilotHole Size

Under-reamedDiameter

MaximumTool OD

24 20 181/2 26 1820 16 171/2 22 1716 133/8 143/4 171/2 14

133/8 (48-68#) 103/4 121/4 15 113/4113/4 85/8 105/8 121/4 10

95/8 (29.3#) 75/8 83/4 111/2 81/485/8 (24-32#) 65/8 75/8 91/2 71/485/8 (36-49#) 6 73/8 9 7

75/8 51/2 61/4 81/2 67 (17-32#) 5 6 8 53/4

Table 3.A - Recommended Casing Size Versus Hole Size

Note: Recommendations above are based on:

The minimum clearance of 0.400 on diameter between the outerstring drift diameter and inner coupling diameter.

The clearance between the hole wall and the coupling OD is at least2 on diameter. Less clearance than this may create a back pressurewhich will dehydrate the cement to a point where it cannot bepumped.

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4. CASING SPECIFICATION AND CLASSIFICATION

There is a great range of casings available from suppliers from plain carbon steel foreveryday mild service through exotic duplex steels for extremely sour service conditions. Thecasings available can be classified under two specifications, API and non-API.

Casing specifications, including API and its history, are described and discussed in sections4.1 and 4.2. Non-API casing manufacturers have produced products to satisfy a demand inthe industry for casing to meet with extreme conditions which the API specifications do notmeet. The area of use for this casing are also discussed in section 4.1 below.

The properties of steel used in the manufacture of casing is fundamentally important andshould be fully understood by design engineers, and to this end these properties aredescribed in section 4.2.

4.1. CASING SPECIFICATION

The American Petroleum Institute (API) has an appointed Committee on Standardisation oftubular goods which publishes, and continually updates, a series of Specifications, Bulletinsand Recommended Practices covering the manufacture, performance and handling of oilfieldtubular goods. They also license manufacturers to use the API Monogram on products whichmeet with their published specifications therefore can be identified as complying with thestandards.

The API Forum has been in existence since 1924, and their standardisation of oilfieldequipment and practices are almost universally accepted as the world standard on tubulars.This does not mean that the published performance data is accepted as the best theoreticalrepresentation of the parameters of tubulars.

It is essential that design engineers are aware of any changes made to the API specifications.All involved with casing design must have immediate access to the latest copy of API Bulletin5C2 which lists the performance properties of casing, tubing and drillpipe. Although these arealso published in many contractors' handbooks and tables, which are convenient for field use,care must be taken to ensure that they are current.

Also a library of the other relevant API publications shall be available and design engineersshould make themselves familiar with these documents and their contents.

It should not be interpreted from the above that only API tubulars and connections may beused in the field as some particular engineering problems are overcome by specialistsolutions which are not yet addressed by API specifications. In fact, it would be impossible todrill many extremely deep wells without recourse to the use of pipe manufactured outwith APIspecifications (non-API).

Similarly, many of the Premium connections that are used in high pressure high GORconditions are also non-API.

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When using non-API pipe, the designer must check the methods by which the strengths havebeen calculated. Usually it will be found that the manufacturer will have used the publishedAPI formulae (Bulletin 5C3), backed up by tests to prove the performance of his productconforms to, or exceeds, these specifications. However, in some cases, the manufacturershave claimed their performance is considerably better than that calculated by the using APIformulae. When this occurs the manufacturers claims must be critically examined by thedesigner or his technical advisors, and the performance corrected if necessary.

It is also important to understand, that to increase competition, the API tolerances have beenset fairly wide. However, the API does provide for the purchaser to specify more rigorouschemical, physical and testing requirements on orders, and may also request placeindependent inspectors to quality control the product in the plant.

4.2. API CASING CLASSIFICATION

Casing is classified by:

Outside diameter. Nominal unit weight. Grade of the steel. Type of connection. Length by range. Manufacturing process

An example of an API table showing the parameters listed above in given in table 4.a.Reference should always be made to current API specification 5C2 for casing lists andperformances.

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Col 1 Col 2 Col 3 Col 4 Col 5

Size: OD Nominal Wt Grade Wall Thickness Type of Thread

ins mm lbs per ft Grades Inc ins mm Short Long Buttress Extreme Line

85/8 219.1 24.00 J, K 0.264 6.71 X85/8 219.1 28.00 H 0.304 7.72 X85/8 219.1 32.00 H 0.352 8.94 X85/8 219.1 32.00 J, K 0.352 8.94 X X X X85/8 219.1 36.00 J, K 0.400 10.16 X X X X85/8 219.1 36.00 C, L, N 0.400 10.16 X X X85/8 219.1 40.00 C, L, N, P 0.450 11.43 X X X85/8 219.1 44.00 C, L, N, P 0.500 12.70 X X X85/8 219.1 49.00 C, L, N, P, Q 0.557 14.15 X X X95/8 244.5 32.30 H 0.312 7.92 X95/8 244.5 36.00 H 0.352 8.94 X95/8 244.5 36.00 J, K 0.352 8.94 X X X95/8 244.5 40.00 J, K 0.395 10.03 X X X X95/8 244.5 40.00 C, L, N 0.395 10.03 X X X95/8 244.5 43.50 C, L, N, P 0.435 11.05 X X X95/8 244.5 47.00 C, L, N, P 0.472 11.99 X X X95/8 244.5 53.50 C, L, N, P, Q 0.545 13.84 X X X95/8 244.5 59.40 C 90 only 0.609 15.4795/8 244.5 64.90 C 90 only 0.672 17.0795/8 244.5 70.30 C 90 only 0.734 18.6495/8 244.5 75.60 C 90 only 0.797 20.24103/4 273.1 32.75 H 0.297 7.09 X103/4 273.1 40.50 H 0.350 8.89 X103/4 273.1 40.50 J, K 0.350 8.89 X X103/4 273.1 45.50 J, K 0.400 10.16 X X X103/4 273.1 51.00 C, K, K, N, P 0.450 11.43 X X X103/4 273.1 55.50 C, L, N, P 0.495 12.57 X X X103/4 273.1 60.70 P, Q 0.545 13.84 X X X103/4 273.1 65.70 P, Q 0.595 15.11 X X103/4 273.1 59.40 C 90 only 0.545 13.84103/4 273.1 65.70 C 90 only 0.595 15.11103/4 273.1 73.20 C 90 only 0.672 17.07103/4 273.1 79.20 C 90 only 0.734 18.64103/4 273.1 85.30 C 90 only 0.797 20.24113/4 298.5 42.00 H 0.333 8.46 X113/4 298.5 47.00 J, K 0.375 9.52 X X113/4 298.5 54.00 J, K 0.435 11.05 X X113/4 298.5 60.00 J,K,N,C,L,P,Q 0.489 12.42 X X133/8 339.7 48.00 H 0.330 8.38 X133/8 339.7 54.50 J, K 0.380 9.65 X X133/8 339.7 61.00 J, K 0.430 10.92 X X133/8 339.7 68.00 C,L,J,K,N,P,Q 0.480 12.19 X X133/8 339.7 72.00 C, L, N, P, Q 0.514 13.06 X X16 406.4 65.00 H 0.375 9.52 X16 406.4 75.00 J, K 0.438 11.13 X X16 406.4 84.00 J, K 0.495 12.57 X X

185/8 473.0 87.50 H, J, K 0.435 11.05 X185/8 473.0 87.50 J, K 0.435 11.05 X20 508.0 94.00 H, J, K 0.438 11.13 X X20 508.0 94.00 J, K 0.438 11.13 X20 508.0 106.50 J, K 0.500 12.70 X X X20 508.0 133.00 J, K 0.635 16.13 X X X

Table 4.A - Example API Casing List

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4.3. NON-API CASING

Eni-Agip Division and Affiliates policy is to use API casings whenever feasible. Somemanufacturers produce non-API casings for H2S and deep well service where API casings donot meet requirements. The most common non-API grades are shown in the attached table

figure 4.a shows the API and non-API materials available and the environment in which theyare recommended to be used.

Figure 4.A- Casing Materials Selection

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Application (Refer tofigure 4.a)

Domain Material SMDesignation

Notes

Mild Environment Domain A API J 55N 80P 110(Q 125)

SM 95GSM 125G

Sulphide Stress CorrosionCracking (medium pressureand temperature)

Domain B Cr or Cr-Mo Steel

API L 80C 90T 95

SM 80SSM 90SSM 95S

Sulphide Stress CorrosionCracking (high pressure andtemperature)

Domain C 1Cr 0.5Mo SteelModified AISI 4130

SM 85SSSM 90SSSM C100SM C110

Higher yieldstrength for sourservice

Wet CO2 Corrosion Domain D 9Cr 1Mo Steel SM 9CR 75SM 9CR 80SM 9CR 95

Quenched andtempered

13Cr SteelModified AISI 420

SM 13CR 75SM 13CR 80SM 13CR 95

Quenched andtempered

Wet CO2 with a little H2SCorrosion

Domain E 22Cr 5Ni 3Mo Steel

25Cr 6Ni 3Mo Steel

SM 22CR 65*SM 22CR 110**SM 22CR 125**SM 25CR 75*SM 25CR 110**SM 25CR 125**SM 25CR 140**

Duplex phaseStainless steels

* Solution Treated

** Cold drawn

Wet CO2 with H2S Corrosion Domain F 25Cr 35Ni 3Mo Steel

22Cr 42Ni 3Mo Steel

20Cr 35Ni 5Mo Steel

SM 2535 110SM 2535 125SM 2242 110SM 2242 125SM 2035 110SM 2035 125

As cold drawn

Most Corrosive Environment Domain G 25Cr 50Ni 6Mo Steel

20Cr 58Ni 13Mo Steel

16Cr 54Ni 16Mo Steel

SM 2550 110SM 2550 125SM 2550 140SM 2060 110***SM 2060 125***SM 2060 140***SM 2060 155***SM C276 110***SM C276 125***SM C276 140***

As cold drawn

*** Environmentwith freeSulphur

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Table 4.B - Example Non-API Steel Grades

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5. MECHANICAL PROPERTIES OF STEEL

5.1. GENERAL

Failure of a material or of a structural part may occur by fracture (e.g. the shattering of glass),Yield, wear, corrosion, and other causes. These failures are failures of the material. Bucklingmay cause failure of the part without any failure of the material.

As load is applied, deformation takes place before any final fracture occurs. With all solidmaterials, some deformation may be sustained without permanent deformation, i.e. thematerial behaves elastically.

Beyond the elastic limit, the elastic deformation is accompanied by varying amounts ofplastic, or permanent, deformation, If a material sustains large amounts of plastic deformationbefore final fracture. It is classed as ductile material, and if fracture occurs with little or noplastic deformation. The material is classed as brittle.

5.2. STRESS-STRAIN DIAGRAM

Tests of material performance may be conducted in many different ways, such as by torsion,compression and shear, but the tension test is the most common and is qualitativelycharacteristics of all the other types of tests.

The action of a material under the gradually increasing extension of the tension test is usuallyrepresented by plotting apparent stress (the total load divided by the original cross-sectionalarea of the test piece) as ordinates against the apparent strain (elongation between twogauge points marked on the test piece divided by the original gauge length) as abscissae.

A typical plot for a carbon steel is shown in figure 5.a.

From this, it is seen that the elastic deformation is approximately a straight line defined byHooke's law, and the slope of this line, or the ratio of stress to strain within the elastic range,is the modulus of elasticity E, sometimes called Young's modulus.

Beyond the elastic limit, permanent, or plastic strain occurs.

If the stress is released in the region between the elastic limit and the yield strength (seeabove) the material will contract along a line generally nearly straight and parallel to theoriginal elastic line, leaving a permanent set.

In steels, a curious phenomenon occurs after the elastic limit, known as yielding. This givesrise to a dip in the general curve followed by a period of deformation at approximately constantload. The maximum stress reached in this region is called the upper yield point and the lowerpart of the yielding region the lower yield point. In the harder and stronger steels, and undercertain conditions of temperature, the yielding phenomenon is less prominent and iscorrespondingly harder to measure. In materials that do not exhibit a marked yield point, it iscustomary to define a yield strength. This is arbitrarily defined as the stress at which thematerial has a specified permanent set (the value of 0.2 percent is widely accepted in theindustry).

For steels used in the manufacturing of tubular goods the API specifies the yield strength asthe tensile strength required to produce a total elongation of 0.5 and 0.6 percent of the gaugelength.

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Figure 5.A - Stress - Strain Diagram

Similar arbitrary rules are followed with regard to the elastic limit in commercial practice.Instead of determining the stress up to which there is no permanent set, as required bydefinition, it is customary to designate the end of the straight portion of the curve (by definitionthe proportional limit) as the elastic limit. Careful practice qualifies this by designating it theproportional elastic limit.

As extension continues beyond yielding, the material becomes stronger causing a rise of thecurve, but at the same time the cross-sectional area of the specimen becomes less as it isdrawn out. This loss of area weakens the specimen so that the curve reaches a maximumand then falls off until final fracture occurs. The stress at the maximum point is called thetensile strength (TS) or the ultimate strength of the material and is its most often quotedproperty.

The mechanical and chemical properties of casing, tubing and drill pipe are laid down in APIspecifications 5CT and 5C2.

Depending on the type or grade, minimum requirements are laid down for the mechanicalproperties, and in the case of the yield point even maximum requirements (except for H 40).

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The denominations of the different grades are based on the minimum yield strength, e.g.:

Grade Min. Yield Strength

H 40 40,000psiJ 55 55,000psiC 75 75,000psiN 80 80,000psietc.

In the design of casing and tubing strings the minimum yield strength of the steel is taken asthe basis of all strength calculations

As far as chemical properties are concerned, in API 5CT only the maximum phosphorus andsulphur contents are specified, the quality and the quantities of other alloying elements are leftto the manufacturer.

API specification 5CT Restricted yield strength casing and tubing however, specifies thecomplete chemical requirements for grades C 75, C 95 and L 80.

5.3. HEAT TREATMENT OF ALLOY STEELS

The structure of a metal or alloy and its mechanical and corresponding physical propertiesare strongly dependent on the chemical composition of the material and heat treatmentapplied. In the heat treatment process, the temperature reached and the rate of cooling arethe essentials of obtaining the physical properties.

Comparison of the chemical composition shows that in general there is little differencebetween the various grades of steel and the difference in mechanical properties is achievedmainly through the variation heat treatment process.

Rapid cooling of the steel from above the crystallisation temperature by quenching provides ahard, brittle type steel. Slow cooling provides a soft low-strength steel.

The hardness of a specific alloy steel is directly proportional to the strength of that steel.

The various methods of heat treatment are as follows:

Annealing In this process the steel is heated above a critical temperatureand cooled very slowly, usually in the furnace. Annealingaccomplishes the following:

Refines grain structure. Makes structure more uniform. Improves machinability.

Normalising This is an identical process to annealing except that the steel isair cooled. As an example API grades J and K55 are heated toabout 860C (1,580F) before cooling.

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Tempering Consists of re-heating a quenched or normalised steel to aspecified temperature below the critical temperature, between600C and 680C (1,110F and 1,260F) depending on thegrade for a specific time and cooling back to room temperature.This process makes the steel tougher with only small loss instrength.

Stress relieving Is similar to the tempering process but is done to relieveinternal stresses set up during the manufacturing process(such as in upsetting).

Quenching Is the same procedure as normalising but has rapid cooling,usually done in water, salt water or oil. un-tempered quenchedsteels are very hard and brittle.

See the following tables for process of manufacturing, heat treatments, chemical compositionand mechanical properties of API tubulars.

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TemperingTemperature Min.

Group Grade Type Process ofManufacture

HeatTreatment

oF oC

H 40 - S or EW None - -J 55 - S or EW None

Note 1- -

1 K 55 - S or EW NoneNote 1

- -

N 80 (Casing) - S or EW NoneNote 1

- -

N 80 (Tubing) - S or EW Note 1 - -C 75 1 S or EW N&T 1,150 621C 75 2 S or EW Q&T 1,150 621C 75 3 S or EW N&T 1,150 621C 75 9 Cr S Q&T* 1,100 593C 75 18 Cr S Q&T* 1,100 593

2 C 90 1 S Q&T 1,150 621C 90 2 S Q&T 1,150 621C 95 - S or EW Q&T 1,000 538L 80 1 S or EW Q&T 1,050 566L 80 9 Cr S Q&T* 1,100 593L 80 13 Cr S Q&T* 1,100 593

3 P 105 - S Q&T or N&T** - -P 110 - S Q&T or N&T** - -Q 125 1 S or EW*** Q&T - -

4 Q 125 2 S or EW*** Q&T - -Q 125 3 S or EW*** Q&T - -Q 125 4 S or EW*** Q&T - -

Note:

Full length normalised, normalised and tempered (N&T) or quenched and tempered (Q&T) at themanufactures option or if so specified on the order.Type 9 Cr and 13Cr grades may be air quenched** Unless otherwise agreed between purchaser and manufacturer/processor*** Special requirements unique to electric welded Q 125 casing are specified in SR11. When

welded Q 125 casing is furnished, the provisions of SR11 automatically in effect.S = Seamless pipeEW = Electric welded Pipe

Table 5.A - API Process of Manufacture and Heat Treatment

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Group Grade Type Carbon Maganese Molybdenum Chromium Nickel Copper Phos-phorous

Sulphur Silicon

min max. min max. min max. min max. max. max. max. max. max.

1 H - 40 ... ... ... ... ... ... ... ... ... ... ... 0.040 0.060 ...J - 55 ... ... ... ... ... ... ... ... ... ... ... 0.040 0.060 ...K - 55 ... ... ... ... ... ... ... ... ... ... ... 0.040 0.060 ...N - 80 ... ... ... ... ... ... ... ... ... ... ... 0.040 0.060 ...

2 C - 75 1 ... 0.50 ... 1.90 0.15 0.40 *** *** *** *** 0.040 0.060 0.45C - 75 2 ... 0.43 ... 1.50 ... ... ... ... ... ... 0.040 0.060 0.45C - 75 3 0.38 0.48 0.75 1.00 0.15 0.25 0.80 1.10 ... ... 0.040 0.040 ...C - 75 9Cr ... 0.15 0.30 0.60 0.90 1.10 8.0 10.0 ... ... 0.020 0.010 1.0C - 75 13Cr 0.15 0.22 0.25 1.00 ... ... 12.0 14.0 0.5 0.25 0.020 0.010 1.0L - 80 1 ... 0.43* ... 1.90 ... ... ... ... 0.25 0.35 0.040 0.060 0.45L - 80 9Cr ... 0.15 0.30 0.60 0.90 1.10 8.0 10.0 0.5 0.25 0.020 0.010 1.0L - 80 13Cr 0.15 0.22 0.25 1.00 ... ... 12.0 14.0 0.5 0.25 0.020 0.010 1.0C90 1 ... 0.35 ... 1.00 ... 0.75 ... 1.20 0.99 ... 0.030 0.010 ...C90 2 ... 0.50 ... 1.90 ... NL ... NL 0.99 ... 0.030 0.010 ...C95 ... ... 0.45* ... 1.90 ... ... ... ... ... ... 0.040 0.060 0.45

3 P -105 ... ... ... ... ... ... ... ... ... ... ... 0.040 0.060 ...P -110

... ... ... ... ... ... ... ... ... ... ... 0.040 0.060 ...

4 Q -125 1 ... 0.35 ... 1.00 ... .75 ... 1.20 0.99 ... 0.020 0.010 ...Q -125 2 ... 0.35 ... 1.00 ... NL ... NL 0.99 ... 0.020 0.020 ...Q -125 3 ... 0.50 ... 1.90 ... NL ... NL 0.99 ... 0.030 0.010 ...Q -125 4 ... 0.50 ... 1.90 ... NL ... NL 0.99 ... 0.030 0.020 ...

Note:*** For Grade C - 75, Type 1, Chromium, Nickel and Copper combined shall not exceed 0.50%.* The Carbon contents for L - 80 may be increased to 0.50% max. if the product is oil

quenched.* The Carbon contents for C - 95 may be increased to 0.55% max. if the product is oil

quenched.NL No Limit. Elements shown must be reported in product analysis.

Table 5.B - Chemical Composition of API Tubulars

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Yield Strength TensileStrength

Hardness Specified WallThickness

AllowableHardnessVariation

Group Grade min. max. min. max.*psi MPa psi MPa psi MPa HRC BHN Inches HRC

1 H -40 40,000 276 80,000 552 60,000 414 ... ...J - 55 55,000 379 80,000 552 75,000 517 ... ...K - 55 55,000 379 80,000 552 95,000 655 ... ...N - 80 80,000 552 110,000 758 100,000 689 ... ...

2 C - 75 1,2,3 75,000 517 90,000 620 95,000 655 ... ...C - 75 9Cr 75,000 517 90,000 620 95,000 655 22 237C - 75 13Cr 75,000 517 90,000 620 95,000 655 22 237

L - 80 1 80,000 552 95,000 655 95,000 655 23 241L - 80 9 Cr 80,000 552 95,000 655 95,000 655 23 241L - 80 13 Cr 80,000 552 95,000 655 95,000 655 23 241

C - 90 90,000 620 105,000 724 100,000 690 25.4 255 0.500 or less 3.0C - 90 90,000 620 105,000 724 100,000 690 25.4 255 0.501 to 0.749 4.0C - 90 90,000 620 105,000 724 100,000 690 25.4 255 0.750 to 0.999 5.0C - 90 90,000 620 105,000 724 100,000 690 25.4 255 1.000 and

above6.0

C - 95 95,000 655 110,000 758 105,000 724 ... ...

3 P - 105 105,000 724 135,000 931 120,000 827 ... ...P - 110 110,000 758 140,000 965 125,000 862 ... ...

4 Q -125 125,000 860 150,000 1035 135,000 930 ... ... 0.500 or less 3.0Q -125 125,000 860 150,000 1035 135,000 930 ... ... 0.501 to 0.749 4.0Q -125 125,000 860 150,000 1035 135,000 930 ... ... 0.750 and

above5.0

* In case of dispute, laboratory Rockwell C hardness tests shall be used as the refereemethod.

Table 5.C - API Tensile and Hardness Requirements

AR

PO

ENI S.p.A.

Ag

ip D

ivision

IDEN

TIFICATIO

N C

OD

EP

AG

E 35 OF 134

REVISIO

N

ST

AP

-P-1-M

-61100

Fig

ure 5.B

- Yield

Stren

gth

/Ten

sile Stren

gth

Ratio

s

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6. TUBULAR RANGE LENGTHS & COLOUR CODING

6.1. RANGE LENGTHS

The following tables provide the API tubular length ranges available.

Range 1 2 3

Casing And Liners

** Total range length include 16-25 25-24 24-48* Range Length for 95% or more of carloadPermissible Variation, max. 6 5 6Permissible length, min 18 28 36

Tubing

** Total range length include 20-24 28-32 -* Range Length for 100% or more of carloadPermissible Variation, max. 2 2 -Permissible length, min 20 28 -

Pup Joint

*** Lengths 2,3,4,6,8,10 and 12ftTolerance 3ins

* Carload tolerance shall not apply to orders of less than a carload. For any carload of pipe, shippedto the final destination without transfer or removal from the car, the tolerance shall apply to each car.For any order consisting of more than a carload and shipped from the manufacturers facility by rail.but not to the final destination, the carload tolerance shall apply to the total order, but not to theindividual carloads.** By agreement between purchaser and manufacturer or processor the total range length for range1 tubing may be 20-28ft*** 2ft pup joints may be furnished up to 3ft long by agreement between purchaser andmanufacturer, and lengths other than those listed may be furnished by agreement betweenpurchaser and manufacturer.

Table 6.A - API Range Length In Feet

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Range 1 2 3

Casing And Liners

Total range length include 4.88-7.62 7.62-10.36 10.36-14.63* Range Length for 95% or more of carloadPermissible Variation, max. 1.83 1.52 1.83Permissible length, min 5.49 8.53 10.97

Tubing

** Total range length include 6.10-7.32 8.53-9.75 -* Range Length for 100% or more of carloadPermissible Variation, max. 0.61 0.61 -Permissible length, min 6.10 8.53 -

Pup Joint

*** Lengths 0.61, 0.19, 1.22, 1.83, 2.44, 3.05 and 3.66mTolerance 76.2mm

* Carload tolerance shall not apply to orders of less than a carload shipped from the manufacturersor processors facility. For any carload of pipe shipped from the manufacturers or processorsfacility to the final destination without transfers or removal from the car, the tolerance shall apply toeach car. For any order consisting of more than a carload and shipped by rail, but not to the finaldestination in the rail cars loaded, the carload tolerance shall apply to the total order, but not to theindividual carloads.** By agreement between the purchaser and manufacturer or processor the total range length forrange 1 tubing may be 6.10-8.53m*** 0.61m pup joints may be furnished up to 0.91m long by agreement between purchaser andmanufacturer, and lengths other than those may be furnished be agreement between purchaser andmanufacturer.

Table 6.B - API Range Length in Metres

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6.2. API TUBULAR MARKING AND COLOUR CODING

6.2.1. Markings

All API tubulars are marked as per API specification 5CT. The following example shows themarking code.

Table 6.C - Example Marking Code (Dalmine)

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6.2.2. Colour Coding

Group 1, Group 3, Group 4

In addition to the required identification markings as specified in 6.2.1 above, each length ofcasing and tubing shall be colour coded by one or more of the following methods.

A paint band encircling the pipe at a distance not greater than 2ft (0.61m) from thecoupling or box.

A paint band encircling the centre of the coupling. Paint entire outside surface of coupling.

For pup joints shorter than 6ft (1.83m) in length, the entire surface except the threads shall bepainted.

The colour and number of bands shall be as follows:

Grade H 40 No colour marking, or black at the manufacturers option

Grade J 55 One bright green band

Grade K 55 Two bright green bands

Grade N 80 One red band

Grade P 105 White

Grade P 110 White

Grade Q 125 Orange

Group 2

1) A paint band or bands encircling the pipe at a distance not greater than 2ft (0,61m) fromthe coupling or box.

Grade C75 One blue band

Grace C75, 9Cr One blue band and two yellow bands

Grade C75, 13Cr One blue and one yellow band

Grade L80 One red band and one brown band

Grade L80, 9Cr One red and one brown and two yellow bands

Grade L80, 13Cr. One red and one brown and one yellow band

Grade C90 One purple band

Grade C95 One brown band

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2) A paint band or bands encircling the centre of the coupling.Grade C75 One blue band

Grade C90 One purple band

Grade C95 One brown band

3) Paint entire outside surface of coupling. The colour shall be as follows:Grade C75 Blue

Grade C75, 9Cr Blue with two yellow bands

Grade C75, 13Cr. Blue with one yellow band

Grace L80 Red with brown band or longitudinal stripe

Grade L80, 9Cr Red with two yellow bands

Grade L80, 13Cr. Red with one yellow band

Grade C90 Purple

Grade C95 Brown

4) For pup joints shorter than 6ft (1.83m) in length, the entire surface except the threadsshall be painted.

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7. APPROACH TO CASING DESIGN

Casing design is actually a stress analysis procedure. The objective of the procedure is toproduce a pressure vessel which can withstand a variety of external, internal, thermal, andself weight loading, while at the same time being subjected to wear and corrosion.

During the drilling phase, this pressure vessel is a composite of steel and in conjunction witha variety of biaxially stressed rock materials.

As there is little point in designing for loads that are not encountered in the field, or in having acasing that is disproportionally strong in relation to the underlying formations, there are fourmajor elements to the casing design process:

Definition of the loading conditions likely to be encountered throughout the life ofthe well.

Specification of the mechanical strength of the pipe. Estimation of the formation strength using rock and soil mechanics. Estimation of the extent to which the pipe will deteriorate through time and

quantification of the impact that this will have on its strength.

Considering the axial stress (sa) in a string of casing, it is obvious that the stress due to thebuoyant weight of the casing below any point of interest will be a major component of the totalaxial stress.

Furthermore any changes in the internal and external pressures acting on casing will inducechanges in the axial stress as well as the radial (sr) and tangential (st) stresses.

In addition, since the pipe is held or fixed at both ends, changes in all three stresses will occurdue to temperature changes and from the occurrence, and degree, of any buckling effect.

The inter-relationship between these loads can be analysed manually by applying acombination of Hooke's Law, Lame's Equations and some form of yield criteria. This isreferred to as Triaxial Stress Analysis.

The forces affecting casing design are outlined in section 7.1.

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7.1. WELLBORE FORCES

Various wellbore forces affect casing design. Besides the three basic conditions (burst,collapse and axial loads or tension), these include:

Buckling. Wellbore confining stress. Thermal and dynamic stress. Changing internal pressure caused by production or stimulation operations Changing external pressure caused by plastic formation creep. Subsidence effects and the effect of bending in crooked holes.

This list above is by no means comprehensive and research in progress may identify someother effects.

The steps in the casing design process are:

1) Consider the loading factors for burst first, since burst will dictate the design for themajor part of the string.

2) Next, the collapse loading should be evaluated and the string sections upgraded ifnecessary.

3) Once the weights, grades and section lengths have been determined to satisfy theburst and collapse loading, the tensile load can then in turn be evaluated.

4) The pipe can be upgraded as necessary as the loading is determined.5) From all of the above, the appropriate casing connection can be determined although, if

the well is to be completed and the casing exposed to long term production,consideration may be given to using a premium connection.

The final step is a check on biaxial reductions in burst strength and collapse resistancecaused by compression and tension loads, respectively. If these reductions show thestrength of any part of the section to be less than the potential load, the section should againbe upgraded.

7.2. DESIGN FACTOR (DF)

The design process can only be completed if knowledge of all the anticipated forces isavailable. This however, is idealistic and never actually occurs, therefore somedeterminations are usually necessary and a degree of risk has to be present and accepted.The risk is usually associated with the assumed values and the level of the design factorsapplied.

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The design factors are necessary to cater for:

Uncertainties in the determination of actual loads that the casing needs towithstand and the presence of any stress concentrations due to dynamic loads orspecific well conditions.

Reliability of listed properties of the various steels used in the industry and theuncertainty in the determination of the spread between ultimate strength and yieldstrength.

Probability of the casing needing to bear the maximum load determined from thecalculations.

Uncertainties regarding the collapse pressure formulas. Possible damage to casing during transport and storage. Damage to the pipe body from slips, wrenches or inner defects due to cracks,

pitting, etc. Rotational wear by the drill string while drilling.

The DF may vary with the capability of the steel to resist damage inflicted from handling andrunning equipment.

The company values selected for DFs are a compromise between safety margin andeconomics. The use of excessively high DFs guarantees against failure but providesexcessive strength and, therefore, increased cost. The use of low DFs requires accurateknowledge about the loads to be imposed on the casing as there is less margin available.

Casing is generally designed to withstand stress which, in practice, it seldom encounters dueto the assumptions used in calculations, whereas, production tubing has to bear pressuresand tensions which are known or can be calculated with considerable accuracy.

Furthermore, casing is cemented in place after installation whereas tubing is often recoveredand used again. As a consequence of this, and due to the fact that tubing has to combatcorrosion effects from formation fluid, a higher DF is used for tubing than casing.

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7.2.1. Company Design Factors

The following table gives the DFs are Eni-Agips specified design factors used in casingdesign calculations:

Casing Grade Burst Collapse Tension

H 40 1.05 1.10 1.7

J 55 1.05 1.10 1.7

K 55 1.05 1.10 1.7

C 75 1.10 1.10 1.7

L 80 1.10 1.10 1.7

N 80 1.10 1.10 1.7

C 90 1.10 1.10 1.7

C 95 1.10 1.10 1.7

P 110 1.10 1.10 1.8

Q 125 1.20 1.10 1.8

Table 7.A - Eni-Agip Design Factors

Note: The tensile DF on grade C 95 and below is 1.7, and higher than C 95 is 1.8.

Note: The tensile DF must be considerably higher than the previous factors toavoid exceeding the elastic limit and, therefore invalidating the criteriaon which burst and collapse resistances are calculated.

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7.2.2. Application of Design Factors

The minimum performance properties of tubing and casing specified in the API bulletin areonly used to determine if the chosen casing is within the DF. The design factors are appliedas follows:

Burst For the chosen casing (diameter, grade, weight and thread) take thelowest value from API casing tables, columns 13 through 19. Thisvalue then divided by the applied DF gives the internal pressureresistance of casing to be used for design calculation.

Collapse Use only column 11 of the API casing tables and divide the value bythe DF to obtain the collapse resistance for design calculations.

Tension Use the lowest value from columns 20 through 27 of the API casingtables and divide it by the DF to obtain the joint strength for designcalculations.

Note: It should be recognised that the Design Factor used in the context ofcasing string design is essentially different from the Safety Factor usedin many other engineering applications.

The term Safety Factor as used in tubing design, implies that the actual physical propertiesand loading conditions are exactly known and that a specific margin is being allowed forsafety. The loading conditions are not always precisely known in casing design, and thereforein the context of casing design the term Safety Factor should be avoided at all times.

Section 8 describes the exact design process in detail including the determination of all theloading applied.

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8. DESIGN CRITERIA

8.1. BURST

Burst loading on the casing is induced when internal pressure exceeds external pressure.

8.1.1. Design Methods

The most conservative design for burst assumes the gradient of dry gas inside the casing,the pressure of which equals the formation pressure of the lowest pressure zone from whichthe gas may have originated or, alternatively the fracture pressure of the open hole below theshoe.

The basis for this design criteria is that a dry gas blow-out is assumed that, when shut-in atthe surface, would either build to the blow-out zone's static shut-in pressure or cause anunderground blow-out once the shut-in pressure reaches the fracture pressure of theweakest formation exposed in the open hole section.

Most operating companies modify this basic dry gas design concept according to a numberof other influences including:

Casing wear considerations Amount of open hole section Depth of the shoe DF applied Current BOP rating, etc.

Based on the vast amount of well data which is currently available, a set of key designconsiderations are made:

a) Blowouts, especially those which are capable of exerting ultra high surfacepressure (i.e. dry gas blowouts), are very rare.

b) Ultra high surface pressures can only be experienced if an actual dry gas blow-out does occur.

c) High strength casing, regardless of how overdesigned it may be, has no impacton the reduction of the blow-out risk.

d) Once a blow-out has occurred, damage to the rig, environment, etc. will havealready commenced, regardless of how strong the casing may be.

e) If there is a blow-out, even a dry gas blow-out, it does not always concur that thecasing will is exposed to high burst pressures.

f) Surface wellheads have an advantage over subsea wellheads during drillingoperations, as there is access to any of the previous casing annuli whereas this isnot available with conventional subsea wellheads.Access to these annuli could in turn provide a means of applying back-uppressure to a casing string, thus reducing the net burst pressure being exerted onthat particular string. This feature is not always possible if the annulus may iseither cemented to the surface or not cemented into the previous casing shoe.

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The key to this problem is to recognise the rare and exceptional well circumstances that mayrequire or result in a hard dry gas shut-in. The decision process should be based on the initialadoption of a middle ground design.

The Eni-Agip Drilling Engineering Department evaluated these key design considerations andhave decided to use the most conservative method and to reduce the obtained results by40%.

8.1.2. Company Design Procedure

To evaluate the burst loading, surface and bottom-hole casing burst resistance must first beestablished.

Surface Casing

a) Internal Pressure

1) The wellhead burst pressure limit is arbitrary, and is generally set equal to that ofthe working pressure rating of the wellhead and BOP equipment but with aminimum of 140kg/cm2. See BOP selection criteria in section 12.1.With a subsea wellhead, the wellhead burst pressure limit is taken as 60% of thevalue obtained as the difference between the fracture pressure at the casing shoeand the pressure of a gas column to surface but in any case not less than2,000psi (140atm).

Consideration should be given to the pressure rating of the wellhead and BOPequipment which must always be equal to, or higher than, the pressure rating ofthe pipe.

When an oversize BOP having a capacity greater than that necessary is selected,the wellhead burst pressure limit will be 60% of the calculated surfacepressure obtained as difference between the fracture pressure at the casing shoewith a gas column to surface. Methane gas (CH4) with density of 0.3kg/dm3 isnormally used for this calculation. In any case it shall never be considered lessthan 2,000psi (140atm).

The use of methane for this calculation is the worst case when the specificgravity of gas is unknown, as the specific gravities of any gases which may beencountered will usually be greater than that of methane.

2) The bottom-hole burst pressure limit can be calculated and is equal to thepredicted fracture gradient of the formation below the casing shoe.

3) Connect the wellhead and bottom-hole burst pressure limits with a straight line toobtain the maximum internal burst load verses depth.

When taking a gas kick, the pressure from bottom-hole to surface will assume differentprofiles according to the position of influx into the wellbore. The plotted pressure versusdepth will produce a curve.

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b) External Pressure

In wells with surface wellheads, the external pressure is assumed to be equal to thehydrostatic pressure of a column of drilling mud.

In wells with subsea wellheads:

At the wellhead - Water Depth x Seawater Density x 0.1 (if atm) At the shoe - (Shoe Depth - Air Gap) x Seawater Density x 0.1 (if atm)

c) Net Pressure

The resultant load, or net pressure, will be obtained by subtracting, at each depth, theexternal from internal pressure.

Intermediate Casing


1) The wellhead burst pressure limit is taken as 60% of the calculated value obtainedas the difference between the fracture pressure at the casing shoe and thepressure of a gas column to the wellhead.In subsea wellheads, the wellhead burst pressure limit is taken as 60% of thevalue obtained as the difference between the fracture pressure at the casing shoeand the pressure of a gas column to the wellhead minus the seawater pressure.

3) The bottomhole burst pressure limit is equal to that of the predicted fracturegradient of the formation below the casing shoe.

4) Connect the wellhead and bottom-hole burst pressure limits with a straight line toobtain the maximum internal burst pressure.


The external collapse pressure is taken to be equal to that of the formation pressure.

With a subsea wellhead, at the wellhead, hydrostatic seawater pressure should beconsidered.

c) Net Burst Pressure

The effective burst pressures are obtained by subtracting the external from internalpressure versus depth.

Production Casing

The worst case burst load condition on production casing occurs when a well is shut-in andthere is a leak in the top of the tubing, or in the tubing hanger, and this pressure is applied tothe top of the packer fluid (i.e. completion fluid) in the tubing-casing annulus.

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1) The wellhead burst limit is obtained as the difference between the pore pressureof the reservoir fluid and the hydrostatic pressure produced by a colum of fluidwhich is usually gas (density = 0.3kg/dm3).

2) Actual gas/oil gradients can be used if information on these are known andavailable.

3) The bottom-hole pressure burst limit is obtained by adding the wellhead pressureburst limit to the annulus hydrostatic pressure exerted by the completion fluid.Generally the completion fluid density is equal to, or close to, the mud weight inwhich casing is installed.

Note: It is usually assumed that the completion fluid and mud on the outside ofthe casing remains homogeneous and retains the original density valueshowever this is not actually the case, particularly with heavy fluids, but it isalso assumed that the two fluids will degrade similarly under the sameconditions of pressure and temperature.

4) Connect the wellhead and bottomhole burst pressure limits with a straight line toobtain the maximum internal burst pressures.

Note: If it is foreseen that future stimulation or hydraulic fracturing operationsmay be necessary, assume: at the perforation depth the fracture pressureat that point and at the wellhead the fracture pressure at the perforationdepth minus the hydrostatic head in the casing plus a safety margin of70kg/cm2 (1,000psi).


The external pressure is taken to be equal to that of the formation pressure.

With a subsea wellhead, at the wellhead, hydrostatic seawater pressure should beconsidered.

c) Net Burst Pressure

The resultant burst pressure is obtained by subtracting the external from internalpressure at each depth.

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Intermediate Casing and Liner

If a drilling liner is to be used in the drilling of a well, the casing above where the liner issuspended must withstand the burst pressure that may occur while drilling below the liner.The design of the intermediate casing string is, therefore, altered slightly:

1) Since the fracture pressure and mud weight may be greater or lower below theliner shoe than casing shoe, these values must be used to design theintermediate casing string as well as the liner.

2) When well testing or producing through a liner, the casing above the liner is part ofthe production string and must be designed according to this criteria.

Tie-Back String

In a high pressure well, the intermediate casing string above a liner may be unable towithstand a tubing leak at surface pressures according to the production burst criteria. Thesolution to this problem is to run and tie-back a string of casing from the liner top to surface,isolating the intermediate casing.

8.2. COLLAPSE

Pipe collapse will occur when the external force on a pipe exceeds the combination of theinternal force plus the collapse resistance.

It occurs as a result of either, or a combination of:

Reduction in internal fluid pressure. Increase in external fluid pressure. Additional mechanical loading imposed by plastic formation movement.

8.2.1. Company Design Procedure

The design of a string of casing in collapse mode consists of selecting the lowest cost pipethat has sufficient strength to meet with the desired design criteria and design factor.

If, when making a selection, a choice exists between a lower grade heavy pipe and a highergrade but lighter pipe, both of which provide adequate strength at similar cost, the highergrade (lighter) pipe should be chosen due to the reduction of tension loading.

Note : The reduced collapse resistance under biaxial stress (tension/collapse)should be considered.

Note : No allowance is given to increased collapse resistance due to cementing.

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Surface Casing


For wells with a surface wellhead, the casing is assumed to be completely empty.

In offshore wells with subsea wellheads, the internal pressure assumes that the mudlevel drops due to a thief zone.


In wells with a surface wellhead, the external pressure is assumed to be equal to that ofthe hydrostatic pressure of a column of drilling mud.

In offshore wells with a subsea wellhead, it is calculated:

At the wellhead - Water Depth x Seawater Density x 0.1 (if atm). At the shoe - (Shoe Depth - Air Gap) x Seawater Density x 0.1 (if atm).

c) Net Collapse Pressure

The resultant collapse pressure is obtained by subtracting the internal pressure fromexternal pressure at each depth.

Intermediate Casing


The worst case collapse loading occurs when a loss of circulation is encountered whiledrilling the next hole section with the maximum allowable mud weight. This results in themud level inside the casing dropping to an equilibrium level where the mud hydrostaticequals the pore pressure of the thief zone. Consequently it will be assumed the casingis empty to the height (H) calculated as follows:

(Hloss-H) x dm = H loss x GpH = H loss (dm - Gp)/dm

If Gp = 1.03 (kg/cm2/10m)

Then H = H loss (dm - 1.03)/dm

where:

Hloss = depth at which circulation loss is expected (m)

dm = mud density expected at Hloss (kg/dm2)

Gp = pore pressure of thief zone (kg/cm2/10m) - usually normally pressuredwith 1.03 as gradient.

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Figure 8.A - Fluid Height Calculation

When thief zones cannot be confirmed, or otherwise, during the collapse design, as isthe case in exploration wells, Eni-Agip division and associates suggests that on wellswith surface wellheads, the casing is assumed to be half empty and the remaining partof the casing full of the heaviest mud planned to drill the next section below the shoe.

In wells with subsea wellheads, the mud level inside the casing is assumed to drop toan equilibrium level where the mud hydrostatic pressure equals the pore pressure of thethief zone.


The pressure acting on the outside of casing is the pressure of mud in which casing isinstalled.

The uniform external pressure exerted by salt on the casing or cement sheath throughoverburden pressure, should be given a value equal to the true vertical depth of therelative point.


The effective collapse line is obtained by subtracting the internal pressure from externalat each depth.

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Production Casing


Assume the casing worst case is being completely empty. It is a fact of life, that duringthe productive life of well, tubing leaks often occur and wells. Also wells may be onartificial lift, or have plugged perforations or very low internal pressure values and, underthese circumstances, the production casing string could be partially or completelyempty. This must be taken into consideration in the design and the ideal solution is todesign for zero pressure inside the casing which provides full safety, nevertheless inparticular well situations, the Drilling and Completions Manager may consider that thelowest casing internal pressure is the level of a column of the lightest density producibleformation fluid.


Assume the hydrostatic pressure exerted by the mud in which casing is installed.

The uniform external pressure exerted by salt on the casing or cement sheath throughoverburden pressure, should be given a value equal to the true vertical depth of therelative point.


In this case of the casing being empty, the net pressure is equal to the externalpressure at each depth.

In other cases it will be the difference between external and internal pressures at eachdepth.

Intermediate Casing and Liner

1) If a drilling liner is to be used in the drilling of a well, the casing above where the liner issuspended must withstand the collapse pressure that may occur while drilling belowthe liner.

2) When well testing or producing through a liner, the casing above the liner is part of theproduction string and must be designed according to this criteria.

Tie-Back String

If the intermediate string above the liner is unable to withstand the collapse pressurecalculated according to production collapse criteria, it will be necessary run and tie-back astring of casing from the liner top to surface.

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8.3. TENSION

8.3.1. General

Tensile failure occurs if the longitudinal force exerted on a pipe exceeds, either the tensilestrength of the pipe or its connection. Generally, the connection used in a string of casing isstronger than the pipe body although this must always be confirmed.

For situations where a connection coupling has to be special clearance, (i.e. of a smallerdiameter than the normal) the connection will be weaker or if flush joint pipe must be used inspecial circumstances.

Tensile loads are imposed on the casing by:

The weight of pipe itself. The highest tensile stresses will occur at the uppermostportion of the pipe. The tension is the weight of the pipe in air less buoyancy.

Shock loading:a) While lowering casing through unstable formations such as cavings where

the casing string may get temporarily stuck before suddenly slipping throughthereby inducing tensile shock loads.

b) When landing casing in a subsea wellhead from a floater.

Upward and downward reciprocating movements carried out where there is atendency to become differential stuck, etc. in order to become free. To free thepipe considerable pull may be necessary.

Bumping a cement plug. High internal pressure will induce tensional stresses caused by radial expansion

and, hence, axial contraction. Bending.

Note: The varying parameters which can affect tensile loading leads to theestimates used for the tensile forces are more uncertain than theestimates for either burst and collapse. The DF imposed is thereforecorrespondingly much larger.

8.3.2. Buoyancy Force

The effect of buoyancy is generally assumed to be the reduction in weight of the casing stringwhen it is suspended in a liquid compared to its weight in air.

The buoyancy or reduction in string weight, as observed on the block is actually the resultantof pressure forces acting on all the exposed horizontal faces and in calculations is defined asnegative as it act upwards, hence reducing the pipe weight.

The areas referred to are the tube end areas, the shoulders at point of changing casingweights and, to a smaller degree, the shoulders on collars (Refer to figure 8.b).

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a) Different casing weights b) Shoulders on collars

Figure 8.B - Casing Buoyancy Areas

The forces acting on the areas of collar shoulders (F3) are for practical purposes negligible incasing design as the upward and downward facing shoulders countered each other overshort distances.

Note: When calculating the tension with regard to buoyancy trends, thedifferent weights per unit length of the casing must be taken intoaccount, as they have different cross-sectional areas. In the followingexample an average weight value is assumed since this does notsubstantially affect the calculations.

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Well Depth(m)

Casing Data Casing Weight(kg)

Size(ins)

Unit Weightlbs/ft (kg/m)

Cross SectionalArea (Af cm2)

0-10001000-20002000-3000

95/895/895/8

47.043.540.0

69.964.759.5

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Casing Design Manual

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