Download - ENI - 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

ARPO

ENI S.p.A.Agip Division

IDENTIFICATION CODE PAGE 2 OF 134

REVISION

STAP-P-1-M-6110 0

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

ARPO



REVISION

STAP-P-1-M-6110 0

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

ARPO



REVISION

STAP-P-1-M-6110 0

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

ARPO



REVISION

STAP-P-1-M-6110 0

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.

ARPO



REVISION

STAP-P-1-M-6110 0

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.

ARPO



REVISION

STAP-P-1-M-6110 0

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.

ARPO



REVISION

STAP-P-1-M-6110 0

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.

ARPO



REVISION

STAP-P-1-M-6110 0

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.

ARPO



REVISION

STAP-P-1-M-6110 0

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.

ARPO



REVISION

STAP-P-1-M-6110 0

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.)

ARPO



REVISION

STAP-P-1-M-6110 0

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.

ARPO



REVISION

STAP-P-1-M-6110 0

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.

ARPO



REVISION

STAP-P-1-M-6110 0

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

ARPO



REVISION

STAP-P-1-M-6110 0

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.

ARPO



REVISION

STAP-P-1-M-6110 0

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.

ARPO



REVISION

STAP-P-1-M-6110 0

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.

ARPO



REVISION

STAP-P-1-M-6110 0

Figure 3.C - Casing and Bit Selection Chart

ARPO



REVISION

STAP-P-1-M-6110 0

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 61/8”

hole, 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.

ARPO



REVISION

STAP-P-1-M-6110 0

Figure 3.D - Standard Casing Programme

Figure 3.E - Alternative Casing Programme

ARPO



REVISION

STAP-P-1-M-6110 0

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.

ARPO



REVISION

STAP-P-1-M-6110 0

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.

ARPO



REVISION

STAP-P-1-M-6110 0

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.

ARPO



REVISION

STAP-P-1-M-6110 0

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

ARPO



REVISION

STAP-P-1-M-6110 0

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

ARPO



REVISION

STAP-P-1-M-6110 0

Application (Refer tofigure 4.a)

Domain Material SM’Designation

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


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


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

ARPO



REVISION

STAP-P-1-M-6110 0

Table 4.B - Example Non-API Steel Grades

ARPO



REVISION

STAP-P-1-M-6110 0

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.

ARPO



REVISION

STAP-P-1-M-6110 0

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 the‘proportional 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).

ARPO



REVISION

STAP-P-1-M-6110 0

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 860°C (1,580°F) before cooling.

ARPO



REVISION

STAP-P-1-M-6110 0

Tempering Consists of re-heating a quenched or normalised steel to aspecified temperature below the critical temperature, between600°C and 680°C (1,110°F and 1,260°F) 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.

ARPO



REVISION

STAP-P-1-M-6110 0

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 themanufacture’s 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

ARPO



REVISION

STAP-P-1-M-6110 0

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

ARPO



REVISION

STAP-P-1-M-6110 0

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

ARPO



REVISION

STAP-P-1-M-6110 0

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 manufacturer’s 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

ARPO



REVISION

STAP-P-1-M-6110 0

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 manufacturer’sor processor’s facility. For any carload of pipe shipped from the manufacturer’s or processor’sfacility 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

ARPO



REVISION

STAP-P-1-M-6110 0

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)

ARPO



REVISION

STAP-P-1-M-6110 0

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 manufacturer’s 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

ARPO



REVISION

STAP-P-1-M-6110 0

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.

ARPO



REVISION

STAP-P-1-M-6110 0

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 (σa) 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 (σr) and tangential (σt) 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.

ARPO



REVISION

STAP-P-1-M-6110 0

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.

ARPO



REVISION

STAP-P-1-M-6110 0

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.

ARPO



REVISION

STAP-P-1-M-6110 0

7.2.1. Company Design Factors

The following table gives the DF’s are Eni-Agip’s 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.

ARPO



REVISION

STAP-P-1-M-6110 0

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.

ARPO



REVISION

STAP-P-1-M-6110 0

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.

ARPO



REVISION

STAP-P-1-M-6110 0

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.

ARPO



REVISION

STAP-P-1-M-6110 0

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.

ARPO



REVISION

STAP-P-1-M-6110 0


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 values’however 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.

ARPO



REVISION

STAP-P-1-M-6110 0

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.


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.

ARPO



REVISION

STAP-P-1-M-6110 0

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 Gp

H = 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.

ARPO



REVISION

STAP-P-1-M-6110 0

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.

ARPO



REVISION

STAP-P-1-M-6110 0

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.

ARPO



REVISION

STAP-P-1-M-6110 0

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).

ARPO



REVISION

STAP-P-1-M-6110 0

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.

ARPO



REVISION

STAP-P-1-M-6110 0

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

87.681.073.9

69.90064.70059.500

Total Casing Weight 194.100

Well Depth (m) Hydrostatic Head(atm (*))

Buoyancy (kg)

100020003000

150300450

150 (87.6-81) = 990300 (81-73.9) = 2.130450 (73.9) = 33.255

Total Buoyancy 36.375Table 8.A - Buoyancy Example Calculation

* Mud density, dm = 1.5kg/dm3

The average buoyancy for the whole profile is:

S = 194,100 - (194,100 x 0.808)

= 37,267kg

The difference (37,267-36,375) is 892kg and thus negligible in the calculations.

Refer to table 8.b for buoyancy factors.

ARPO



REVISION

STAP-P-1-M-6110 0

Density Fluid Head

DegreesAPI

SpecificGravity

lbs/gal lbs/cu ft g/cc psi/ft kg/spcm/m

BuoyancyFactor*

60 0.738 6.160 46.08 0.738 0.320 0.0738 0.90555 0.758 6.325 47.31 0.765 0.328 0.0758 0.90350 0.779 6.499 48.62 0.779 0.336 0.0779 0.90045 0.801 6.683 49.99 0.801 0.347 0.0801 0.89740 0.825 6.878 51.45 0.825 0.357 0.0825 0.89435 0.849 7.085 53.00 0.848 0.368 0.0649 0.89130 0.876 7.304 58.64 0.876 0.379 0.0876 0.68825 0.904 7.537 56.38 0.904 0.391 0.904 0.88420 0.933 7.786 58.24 0.933 0.404 0.0933 0.68015 0.985 8.052 60.23 0.965 0.418 0.0965 0.67510 1.000 8.337 62.36 1.000 0.433 0.1000 0.872

1.007 8.400 62.63 1.007 0.435 0.1007 0.8711.031 8.600 64.33 1.031 0.446 0.1031 0.8681.055 8.800 65.82 1.055 0.457 0.1055 0.8651.079 9.000 67.32 1.079 0.467 0.1079 0.6621.103 9.200 68.82 1.103 0.477 0.1103 0.8591.127 9.400 70.31 1.127 0.488 0.1127 0.8561.151 9.800 71.81 1.151 0.498 0.1151 .08521.175 9.800 73.30 1.175 0.509 0.1175 0.8491.199 10.00 74.80 1.199 0.519 0.1199 0.8461.223 10.200 75.30 1.223 0.529 0.1223 0.8431.247 10.400 77.79 1.247 0.540 0.1247 0.8401.271 10.600 79.29 1.271 0.550 0.1271 0.8371.295 10.800 80.78 1.295 0.561 0.1295 0.8341.319 11.00 82.28 1.319 0.571 0.1319 0.8311.343 11.200 83.78 1.343 0.581 0.1343 0.8281.367 11.400 85.27 1.367 0.592 0.1367 0.8251.391 11.500 86.77 1.391 0.602 0.1391 0.8221.415 11.800 88.27 1.415 0.612 0.1415 0.8191.439 12.000 89.76 1.439 0.823 0.1439 0.8161.463 12.200 91.26 1.463 0.633 0.1463 0.6131.487 12.400 92.75 1.487 0.644 0.1487 0.8101.511 12.600 94.25 1.511 0.654 0.1511 0.8061.535 12.800 95.75 1.535 0.664 0.1535 0.8031.559 13.000 97.24 1.559 0.675 0.1559 0.8001.583 13.200 98.74 1.583 0.585 0.1583 0.7971.607 13.399 100.23 1.607 0.696 0.1607 0.794

s/m1BF ρρ−=BF = Buoyancy Factor

mρ = Mud Densitysρ = Steel Density

Fluid Density Pressure and Buoyancy Factors(60oF) (Continued Over Page)

ARPO



REVISION

STAP-P-1-M-6110 0

Density Fluid Head

DegreesAPI

SpecificGravity

lbs/gal lbs/cu ft g/cc psi/ft kg/spcm/m

BuoyancyFactor*

1.631 13.600 101.73 1.631 0.706 0.1831 0.7911.655 13.800 103.23 1.655 0.716 0.1655 0.7881.679 14.000 104.72 1.679 0.727 0.1579 0.7851.703 14.200 106.22 1.703 0.737 0.1703 0.7821.727 14.399 107.71 1.727 0.748 0.1727 0.7791.751 14.600 109.21 1.751 0.755 0.1751 0.7761.775 14.800 110.71 1.775 0.768 0.1775 0.7731.799 15.000 112.20 1.799 0.779 0.1799 0.7701.823 15.200 113.70 1.823 0.789 0.1823 0.7671.847 15.399 115.20 1.847 0.799 0.1547 0.7641.871 15.600 116.89 1.871 0.610 0.1871 0.7611.895 15.800 118.19 1.895 0.820 0.1895 0.7571.919 16.000 119.68 1.918 0.831 0.1919 0.7541.943 16.200 121.18 1.943 0.841 0.1943 0.7511.967 16.400 122.68 1.967 0.851 0.1967 0.7481.991 16.600 124.17 1.991 0.862 0.1991 0.7452.015 16,800 125.67 2.015 0.872 0.2015 0.7422.039 17.000 127.16 2.039 0.863 0.2039 0.7392.063 17.200 128.66 2.063 0.893 0.2063 0.7362.087 17.400 130.18 2.067 0.903 0.2087 .07332.111 17.600 131.65 2.111 0.914 0.2111 0.7302.135 17.800 133.15 2.135 0.924 0.2135 0.7272.159 18.000 134.54 2.159 0.935 0.2159 0.7242.183 18.200 136.14 .2183 0.945 0.2183 0.722.207 18.400 137.64 2.207 0.955 0.2207 0.7182.231 18.600 139.13 2.231 0.955 0.2231 0.7152.255 18.800 140.63 2.255 0.976 0.2255 0.7122.278 19.000 142.12 2.278 0.987 0.2278 0.7082.326 19.400 145.12 2.326 1.007 0.2326 0.7922.350 19.600 146.61 2.350 1.018 0.2350 0.6992.374 19.800 148.11 2.374 1.028 0.2374 0.6962.398 20.000 149.61 2.398 1.038 0.2398 0.693

Buoyancy factor is used is used compensate for loss of weight when steel tubulars are immersed in fluid.Applicable only when tubing or casing is completely filled with fluid.Apparent Weight = Weight in Air - Buoyant Force

Buoyancy Force = DensitySteel

DensityMudxAirinWeight

Apparent Weight =

−DensitySteel

DensityMudDensitySteelAirinWieght

Apparent Weight = Weight in Air x Buoyancy FactorsSteel Density = 7.85 kg/l

Table 8.B - Fluid Density Pressure and Buoyancy Factors(60oF)

ARPO



REVISION

STAP-P-1-M-6110 0


1) Calculate the casing string weight in air.2) Calculate the casing string weight in mud by multiplying the previous weight by the

buoyancy factor (BF) in accordance with the mud weight in use.

Example:

Weight of casing in air = 250,000kg

Mud weight = 1.70kg/dm3

Buoyancy factor = 0.782

Weight of casing in mud = 250,000 x 0.782

= 195,500kg

Buoyancy force = 54,500kg

3) Add the additional load due to bumping the cement plug to the casing string weight inmud.

Note: This pull load is calculated by multiplying the expected bump-plugpressure by the inside area of the casing.

Example: 95/8" 43.5 lbs/ft casing

Pressure when at bumping plug = 180kg/cm2

Inside casing area, Ai = 388.39cm2

Additional pull load = 388.39 x 180

= 69,910kg

A calculation of this kind is an approximation only because the assumption has beenmade that:

• No buoyancy changes occur during cementing.• The pressure is applied only at the bottom and not where there are changes in

section. As seen with the previous case, the differences in the calculated valuesare quite small, which justifies the preference for the simpler approximationmethod.

Once the magnitude and location of the forces are determined, the total tensile load linemay be constructed graphically.

Note: More than one section of the casing string may be loaded in compression.

8.3.4. Example Hook Load During Cementing

The following is an example of casing load and therefore hook load when conducting a casingcement job. This calculation includes the use of temperature data.

ARPO



REVISION

STAP-P-1-M-6110 0

Example Data

Estimated top of cement 2,800mCemented length of casing 1,250mCasing size 7insSteel grade P 110Weight (imperial) 38lbs/ftWeight (metric) 56.55kg/mInternal diameter 5.898insCasing shoe depth 4050mMud weight during cementing operation 1.93kg/lAverage cement slurry density 2.00kg/lExpected mud weight at end of next phase 2.16kg/lEstimated bump plug pressure 140kg/cm2

Next phase total depth 4400m

Calculation of Cross-Sectional Areas

Casing external area 248.28cm2

Casing internal area 176.26cm2

Cross-sectional area 72.02cm2

Input Temperature Data

Average flowing temperature at casing shoe 65oCAverage static temperature at casing shoe 95oCEstimated flowing temperature at next phase depth 95.5oCEstimated static temperature at next phase depth 120.0oC

Estimated Total Hook Load (at end of cement operation)

Weight of casing in air 229tInternal fluid weight plus bump plug 162tBuoyancy effect 196tBack pressure 0tTotal load at the end of cementing 195t

Total Hang-Off Weight

Weight in air of uncemented casing 158tStress due to the variation in internal pressure -3tStress due to the variation in external pressure 0tDelta T m1 at casing shoe 75.4oCDelta T m1 at end of next phase 103.3oCAverage delta T 27.9 oC

Stress due to temperature variations 52tCritical shock load If negative ignore) -28t

Total required hang-off load 207t

ARPO



REVISION

STAP-P-1-M-6110 0

Guidelines For Landing The Casing

The load conditions in the casing do not consider the additional axial stress placed in thecasing when it is landed. Casing practices make it difficult to estimated the various stresseswhen it is landed in the wellhead. The API have identified four common methods for landingcasing:

• In tension which was present when cement displacement was completed.• In tension at the freeze point, which is generally considered to be at the top of the

cement.• In neutral point of axial strength at the freeze point.• In compression at the freeze point.

API recommendation is to land the casing with the same tension at the end of thedisplacement in all wells where the mud density does not exceed 12.5ppg (1.50kg/l) in thenext section.

The second option is used when excessive mud weights are anticipated, to prevent anytendency of the casing to buckle above the freeze point.

ARPO



REVISION

STAP-P-1-M-6110 0

8.4. BIAXIAL STRESS

8.4.1. General

When the entire casing string has been designed for burst, collapse and tension, and theweights, grades, section lengths and coupling types are known, the reduction in burstresistance needs to be applied due to biaxial loading.

The total tensile load, which is tensile loading versus depth, is used to evaluate the effect ofbiaxial loading and can be shown graphically.

By noting the magnitude of tension (positive) or compression (negative) loads at the top andbottom of each section length of casing, the strength reductions can be calculated using the‘Holmquist & Nadai’ ellipse, see figure 8.c

Note: The effects of axial stress on burst resistance are negligible for themajority of wells.

8.4.2. Effects On Collapse Resistance

The collapse strength of casing is seriously affected by axial load, but the correction adoptedby the API (API Bulletin 5C3) is only valid for D/t ratios of about 15 or less. In principle collapseresistance is reduced or increased when subjected to axial tension or compression loading.

As can be seen from figure 8.c, increasing tension reduces collapse resistance where iteventually reaches zero under full tensile yield stress.

The adverse effects of tension on collapse resistance usually affects the upper portion of acasing string which is under tension reducing the collapse resistance of the pipe.

After these calculations, the upper section of casing string may need to be upgraded.

Note: Fortunately for instances, the biaxial effects of axial stress on collapseresistance are insignificant.

ARPO



REVISION

STAP-P-1-M-6110 0

Figure 8.C - Ellipse of Biaxial Yield Stress

ARPO



REVISION

STAP-P-1-M-6110 0


The value for the percentage reduction of rated collapse strength is determined as follows:

1) Determine the total tensile load.2) Calculate the ratio (X) of the actual applied stress to yield strength of the casing.3) Refer to .figure 8.d and curve ‘effect of tension on collapse resistance’ and find the

corresponding percentage collapse rating (Y).4) Multiply the collapse resistance by the percentage (Y), without tensile loads to obtain the

reduced collapse resistance value.This is the collapse pressure which the casing can withstand at the top of the string.

Figure 8.D - Stress Curve Factors

0

0.1

0.2

0.3

0.4

0.5

0.6

0.7

0.8

0.9

1

1.1

0 0.1 0.2 0.3 0.4 0.5 0.6 0.7 0.8 0.9 1 1.1

X= Tensile load Pipe body yield strength

Y=

Co

llap

sres

iste

nce

wit

h t

ensi

le lo

ad

C

olla

pse

res

iste

nce

wit

ho

ut

ten

sile

load

ARPO



REVISION

STAP-P-1-M-6110 0

8.4.4. Example Collapse Caclulation

Determine the collapse resistance of 7", N80, 32lbs/ft (4 kg/m), BTR casing with the shoe at adepth of 5,750m and a mud weight of 1.1kg/dm3.

Collapse resistance without tensile load = 8,610psi (605kg/cm2)

Pipe body yield strength = 745,000lbs (338t)

Buoyancy factor = 0.859

Weight in air of casing = t274000,1

62.47x750,5=

Weight in mud of casing = 274 x 0.859 = 235t

695.0338235

Strength Body Yield PipecasingofmudinWeight

x ===

From the curve or stress curve factors in figure 8.g, if X = 0.695 then Y = 0.445 and thecollapse resistance against tensile load can be determined:

Collapse resistance under load = Nominal Collapse Rating x 0.445

Refer to figure 8.e for a graphical representation of this calculation.

ARPO



REVISION

STAP-P-1-M-6110 0

Figure 8.E - Graphical Representation

ARPO



REVISION

STAP-P-1-M-6110 0

8.5. BENDING

8.5.1. General

When calculating tensile loading, the effect of bending must also be considered, if applicable.

The bending of the pipe causes additional stress in the walls of the pipe. This bending causestension on the outside of the pipe and in compression on the inside of the bend, assuming thepipe is not already under tension (Refer to figure 8.f).

Figure 8.F - Bending Stress

Bending is caused by any deviation in the wellbore resulting from side tracks, build-ups anddrop-offs.

Since bending load increases the total tensile load, it must be deducted from the usable ratedtensile strength of the pipe.

ARPO



REVISION

STAP-P-1-M-6110 0

8.5.2. Determination Of Bending Effect

For determination of the effect of bending, the following formula should be used:

TB = 15.52 x α x D x Af Eq. 8.A

where:

α = Rate of build-up or drop off (degrees per 30m)

D = Outside diameter of casing (ins)

Af = Cross-section area of casing (cm2)

TB = Additional tension (kg)

The formula is obtained from the two following equations:

J2DMB

××=σ

Eq. 8.B

where:

MB = Bending moment (MB = E x J/R) (kg x cm)

D = Outside diameter of casing (cm)

J = Inertia moment (cm4)

σ = Bending stress (kg/cm2)

E x J = Bending stiffness (kg x cm2)

R = Radius of curvature (cm)

JELMB

××

=θEq. 8.C

where:

MB = Bending moment (kg x cm)

L = Arch length (cm)

E = Modulus of elasticity (kg/cm2)

J = Inertia moment (cm4)

θ = Change in angle of deviation (radians)

Obtaining L

JEMB ××θ= from equation 2), equation 1) becomes:

L2DE

×××θ=σ

Eq. 8.D

ARPO



REVISION

STAP-P-1-M-6110 0

Then, by using the more current units giving the build-up or drop-off angles in degrees/30m,we obtain the final form of the equation for ‘TB’ as follows:

L2AfDE

TB

AfTB

××××θ

=

=σEq. 8.E

302180AfDETB

R1L

30180R

×××××α×π=

=

α×π×

=Eq. 8.F

α=

απ=

==

x 15.52 TB100 x 30

x AfD x 4) x (25x180 x 2

)10 x (2.1 x x TB

106kg/cm2 x 2.1 m221,000Kg/m E6

Eq. 8.G

When:

Af = Square inches

α = Degrees/100ft

TB = 218 x α x D x Af (lbs) or 63 x α x D x W (lbs)

W = Casing weight (lbs/ft)

Note: Since most casing has a relatively narrow range of wall thickness (from0.25 to 0.60ins), the weight of casing is approximately proportional to itsdiameter. This means the value of the bending load increases with thesquare of the pipe diameter for any given value of build-up/drop-off rate.At the same time, joint tension strength rises a little less than the directratio. The result is that bending is a much more severe problem withlarge diameter casing than with smaller sizes.

ARPO



REVISION

STAP-P-1-M-6110 0


Since bending load, in effect, increases tensile load at the point applied, it must be deductedfrom the usable strength rating of each section of pipe that passes the point of bending.

The section which is ultimately set through a bend must have the bending load deducted fromits usable strength up to the top of the bend. From that point up to the top of the section thefull usable strength can be used.

8.5.4. Example Bending Calculation

Data:

• Casing: OD 133/8", 72lbs/ft (107,14kg/m), C75, BTR• Directional well with casing shoe at 2,000m (MD)• Kick-off point at 300m• Build-up rate: 3°/30m• Maximum angle: 30°• Mud weight : 1.1kg/dm3

• Pipe body yield strength: 1,558,000lbs (707t)• Design factor : 1.7

Calculation:

1) Casing weight in air (Wa)Wa = 107.14 x 2,000 = 214t

2) Casing weight in mud (Wm)Wm = 214 x 0.859 = 184t

3) Additional tension due to the bending effect (TB)TB = 15.52 x 3 x 13.375 x 133.99 = 83,441kg = 83t

This stress will be added to the tensile stress already existing on the curved section ofhole.

4) Tension in the casing at 300m(TVD)=156 t. 5)5) Total tension in the casing at 300m = 156 + 83 = 239t6) Tension in the casing at 600m (MD) =129t.7) Total tension in the casing at 600m (MD) = 129 + 83 = 212t.

See figure 8.g for the graphical representation of the example.

ARPO



REVISION

STAP-P-1-M-6110 0

Figure 8.G - Bending Load Example

ARPO



REVISION

STAP-P-1-M-6110 0

8.6. CASING WEAR

8.6.1. General

There is no reliable method of predicting casing wear and defining the reduction in casingproperties due to the reduction in casing performance through decreases in burst andcollapse values which are proportional to the reduction in wall thickness. However, theoreticalpredictions may be made as described in this section.

For most purposes, consideration of wear allowances can be restricted to deviated wells withthe most likely wear spot at the kick-off point where burst reduction will be the greatestconsideration. In a vertical well , casing wear is usually in the first few joints below thewellhead or intervals with a high dogleg severity. In deviated wells, wear will be over the build-up and drop off sections.

Figure 8.H - Casing Wear

The major factors affecting casing wear are:

• Rotary speed.• Tool joint lateral load and diameter.• Drilling rate.• Inclination of the hole.• Severity of dog legs.• Casing wear factor.

The location and magnitude of volumetric wear in the casing string can be estimated bycalculating the energy imparted from the rotating tool joints to the casing at different casingpoints and dividing this by the amount of energy required to wear away a unit volume of thecasing. The percentage casing wear at each point along the casing is then calculated fromthe volumetric wear.

ARPO



REVISION

STAP-P-1-M-6110 0

Eni-Agip acceptable casing wear limit is </= 7%.

Volumetric wear is proportional to an empirical ‘wear factor’ which is defined as the coefficientof friction divided by the volume of casing material removed per unit of energy input.

The wear factor depends upon several variables including :

• Mud properties.• Lubricants.• Drill solids.• Tool joint roughness.• Tool joint hardness.

Note: The chemical action of gases such as H2S, CO2 and 02 tends to reducethe surface hardness of steel and, thus, contributes significantly to therate of wear.

8.6.2. Volumetric Wear Rate

The volume of casing worn away by the rotating tool joint equals:

EnergySpecificFootPerInputEnergy

V =Eq. 8.H

where:

V = Wear volume per foot

Specific Energy = The amount of energy required to wear away a unit volume ofcasing material.

The frictional energy imparted to the casing by the rotating tool joint equals:

Energy Input Per Foot = Friction Force Per Foot x Sliding Distance Eq. 8.I

where:

Friction Force Per Foot = Friction Factor x Tool Joint Lateral Load Per Foot

Sliding Distance = n x TJ Diameter x Rotary Speed x Contact Time

and

Tool Joint Contact Time =DPJL

TJLxS Eq. 8.J

where:

S = Drilling distance(ft)

TJL = Tool joint length (ins)

P = Rate of penetration (ft/hr)

DPJL = Drill pipe joint length (ft)

ARPO



REVISION

STAP-P-1-M-6110 0

The lateral load on the drill pipe equals:

DPJLTJLxTJLLPF

L =Eq. 8.K

where:

L = Drill pipe lateral load per foot

TJLLPF = Tool joint lateral load (lbs/ft)

TJL = Tool joint length (ins)

DPJL = Drill pipe joint length (ft)

The Wear Factor controlling the wear efficiency is defined as:

Wear Factor = Friction Factor/Specific Energy Eq. 8.L

Combining eq. 8.h-eq. 8.l shows that the Wear Volume ’V’ equals:

PS x N x D x L x F x x 60 v π=

Eq. 8.M

where:

V = Wear volume per foot (in3/ft)

F = Wear factor (ins2/lbs)

L = Lateral load on drill pipe per foot (lbs/ft)

D = Tool joint diameter (ins)

N = Rotary speed (RPM)

S = Drilling distance (ft)

P = Penetration rate (ft/hr)

The tool joint and drill pipe lengths do not appear in Equation 6 because they do noteffect the amount of casing wear in the linear model.

Note: Wear volume increases non-linearly against wear depth, becausegrooves become wider as the wear depth increases.

ARPO



REVISION

STAP-P-1-M-6110 0

Figure 8.I - Wear Rate

ARPO



REVISION

STAP-P-1-M-6110 0

8.6.3. Factors Affecting Casing Wear (Example)

Figure 8.J - Example Well

Figure 8.K - Factors Affecting Casing Wear

ARPO



REVISION

STAP-P-1-M-6110 0

Figure 8.L - Wellbore Displacement

Figure 8.M - Factors Affecting Casing Wear

ARPO



REVISION

STAP-P-1-M-6110 0

Figure 8.N - Affect of Tool Joint Diameter on Casing Wear

Figure 8.O - Casing Wear

ARPO



REVISION

STAP-P-1-M-6110 0

Figure 8.P - Lateral Tool Joint Loads in Smooth Ideal Well

Figure 8.Q - Lateral Forces in Actual Well

ARPO



REVISION

STAP-P-1-M-6110 0

8.6.4. Wear Factors

Drilling Fluid Tool Joint Wear Factor (F) (10-1psi-l)

Water+Betonite+Barite Smooth 0.5 to 1Water+Betonite+Lubricant (2%) Smooth 0.5 to 5Water+Betonite+Drill Solids Smooth 5 to 10Water Smooth 10 to 30Water+Betonite Smooth 10 to 30Water+Betonite+Barite Slightly Rough 20 to 50Water+Betonite+Barite Rough 50 to 150Water+Betonite+Barite Very Rough 200 to 400

Table 8.C - Typical Casing Wear Factors

When tool joints are smooth, casing wear is minimised when the mud consists of water,bentonite and barite, (F = 0.5 to 1.0).

The small particles of barite appear to act as ball bearings and prevents the tool joint andcasing materials from coming into intimate contact.

Casing wear is increased tenfold when the mud is weighted with drill solids instead of barite,(F = 5 to 10). This shows the importance of having good solids control when running heavilyweighted muds.

Water (without solids) causes high wear, (F = 10 to 30) because there are no solids toprevent the sliding metals surfaces from coming into contact and causing galling wear. Inextreme cases, the surface can weld together resulting in chunks of metal being torn from thesurfaces.

When tool joints have rough hardbanding, the wear is controlled primarily by the roughness ofthe tool joint and is almost independent of the mud properties. In this case, the rough tooljoints tend to machine away the casing in even larger pieces (similar to the cutting action of amill) resulting in rapid failure of the casing. table 8.d gives comparisons of casing wear withtwelve different hardmetal materials tested in the DEA-42 project.

ARPO



REVISION

STAP-P-1-M-6110 0

Tool Joint Tool Joint Wear(Open Hole)

CasingWear, %

WearFactor

FrictionFactor

Remarks

Smooth Steel 0.043 18.2 5.6 0.21 AISI Steel 4145Rough Tungsten

Carbide 75 1417 0.29 Mesh size 14/24 (20min test)

Smooth TungstenCarbide 0.014 27.8 10.8 0.20 Mesh size 14/24

(field worn surface)Hughes Smooth X 21.8 7.6 0.15 Tungsten Carbide

(spherical granules)Drilco Sphere 7.6 1.95 0.21 Tungsten Carbide

(spherical)Agip Tungsten

Carbide 17.2 5.5 0.19 Low vibration

Agip Austenite 14.6 4.3 0.18 Low vibrationAluminium

Bronze 9.5 2.3 0.32 High friction

Armacor-M 0.027 5.9 1.1 0.15 Amorphous materialArnco-200X 0.018 7.0 1.43 0.14 Chromium CarbideColmonoy 5 0.016 5.9 1.06 0.15 Nickle base

Triboloy-800 0.020 4.2 0.65 0.12 Cobalt Molybdenum

Duocor 9.7 2.24 0.24 Titanium CarbideStellite 6 9.7 2.19 0.17 Cobal base

Polished Chrome 6.6 1.27 0.15 Sensitive in saltmud

BP-1 10.2 2.53 0.19 Steel machineground smooth

BP-2 18.6 6.74 0.21 Steel hand groundfinish

Table 8.D - DEA-42 Comparable Tool Joint Hardmetal Test Results(N 80 with 3,000ft/lbs load and Water Based Mud)

ARPO



REVISION

STAP-P-1-M-6110 0

figure 8.r below shows casing wear versus tool joint passes.

Figure 8.R - Effect of Hardmetal Roughness on Casing Wear

Drilling Fluid Tool Joint Wear Factor (10-1psi-l)

Water+Betonite+Barite Rubber Protector 1 to 2Water Rubber Protector 4 to 10

Table 8.E - Typical Casing Wear Factors (Shell-Bradley, 1975)

The data given in table 8.c and table 8.e show that drill pipe rubber protectors (F= 1 to 10) willreduce casing wear under all conditions except when using smooth tool joints with waterbase mud weighted with barite, (F = 0.5 to 1.0).

In applications where very rough hard metal tool joints (F= 200 to 400) are being used, therubber protectors (F = 1 to 10) can reduce casing wear by 95 to 99 percent.

Limited casing wear data for oil based muds is also available. These limited tests indicate thatcasing wear rates are nearly identical for oil based and water based muds.

Shell (Bol. 1985) found that the addition of barite to the mud significantly reduces casing wear(Refer to figure 8.s).

The barite apparently acts as ball bearings and keeps the sliding metal surfaces from cominginto contact with each other and causing galling wear as already described in the previoussection.

ARPO



REVISION

STAP-P-1-M-6110 0

Figure 8.S - Effect of Barite on Casing Wear (Bol, 1985)

The barite reduced the wear factor from 25 using no barite to 1 to 2 with barite.

Shell (Bol, 1985) conducted tests which showed that a 10ppg mud weighted with drill solidsproduced significantly more casing wear then a 10ppg mud weighted with barite (Refer tofigure 8.t below).

ARPO



REVISION

STAP-P-1-M-6110 0

Figure 8.T - Effects of Barite on Casing Wear

With lateral loads of 900 to 1,800lbs (4 to 8kN), the wear factor ranged from 5 to 10 with drillsolids compared to 0.5 to 1.0 with barite. Apparently the small diameter of the baritecontributed to this reduced wear.

Shell (Bol, 1985) conducted tests with muds weighted with different weighting materials andfound that weighting materials significantly reduce casing wear.

Figure 8.U - Effect of Weighting Materials on Casing Wear (Bol, 1985)

ARPO



REVISION

STAP-P-1-M-6110 0

Drilling Fluid Mud Weight(lbs/gal)

Tool Joint WeightingMaterial

Wear Factor(10-l0psi-1)

Oil+Bentonite 10 Smooth Barite 0.9 to 1.2Water+Bentonite 10 Smooth Barite 0.8 to 1.6Water+Bentonite 10 Smooth Iron Oxide 3 to 4Water+Betontite 10 Smooth Drill Solid 5 to 11Water+Betontite 10 Smooth Sand 11 to 13Water+Betontite 8.8 Smooth None 22 to 27

Table 8.F - Effect of Weighting Material on Casing Wear Factor (Bol, 1985)

Weighting materials were found to reduce casing wear in all cases. Wear was greatest (F=22 to 27), when no weighting material was present to act as a buffer between the tool jointand the casing. The addition of silica sand to the bentonite and water reduced the casingwear in half, (F = 11 to 13).

Drill solids (F = 5 to 11) produced less wear than silica sand.

Iron oxide (F = 3 to 4), which is often considered very abrasive, produced less wear than all ofthe other weighting materials except barite. This is apparently due to the small size of the ironoxide weighting particles.

These tests indicate that the size of the weighting particles may be more important than thecomposition of the particles.

Oil based and water based muds weighted with barite produced minimal wear (F = 0.8 to1.6). This shows the importance of having good solids control when using heavily weightedmuds.

Shell (Bol, 1985) found that the addition of 2% lubricant to an unweighted mud consisting ofwater and bentonite significantly reduced casing wear refer to figure 8.v.

ARPO



REVISION

STAP-P-1-M-6110 0

Figure 8.V - Effect of Lubricant on Casing Wear

The addition of 2% lubricant reduced the wear factor with the bentonite mud from between 30to 5 with 1,800lbs lateral load (8kN) on the tool joint to between 30 to 0.5 with 900lbs load(4kN).

These tests show that lubricants may be useful in wells where casing wear may be aproblem.

8.6.5. Detection Of Casing Wear

Detecting casing wear can be achieved by two methods:

• Use of magnets in the mud flow return.• Running a caliper survey after setting the casing to provide a base log. A wear log

can then be run at any time throughout the life of the next section.

8.6.6. Casing Wear Reduction

If there are fears about casing wear, it stands to reason practices to reduce it should beconsidered, including:

• Using down hole motors and turbines.• Using rubber drill pipe casing protectors.• Using drill pipe without hard facing.• Keeping doglegs to a minimum.• Keeping sand content low.• Using oil based mud.

ARPO



REVISION

STAP-P-1-M-6110 0

8.6.7. Wear Allowance In Casing Design

With the design loads recommended it is highly unlikely that a reduction in collapseresistance due to wear will be critical at shallow depths or similarly that the reduction in burstresistance will be critical at the lower end of the casing string.

The most likely wear points in a deviated wells are at the kick-off point and near surface in thevertical portion where buckling may occur (particularly at the top of cement).

In the vertical wells, wear points may also develop at the top of cement if buckling occurs butunless there are known sudden changes in formation dip, which could cause a large ‘drilleddogleg’, wear is likely to be small and uniformly spread over the entire length of the string.

For most purposes, consideration of wear allowances can be restricted to deviated wells,with the most likely wear point at the kick-off point where burst reduction will be the primeconsideration.

Since wear estimates are order of magnitude calculations, it is recommended that wearallowances be considered only in cases where the burst (or collapse) resistance of thecasing at the wear point will be approached during the anticipated operating time in the string.

In marginal cases, it may well prove cost effective to run a base caliper survey to re-surveythe casing prior to entering a hydrocarbon bearing zone (or pressure test the casing to theequivalent of the burst pressures anticipated from the zone) than to run heavy walled casingthrough all the anticipated wear sections.

The recommended procedure is therefore:

1) Conduct the casing design.2) At the wear points, calculate the allowable reduction in wall thickness so that the burst

(or collapse) resistance of the casing just equals the burst (or collapse) load, includingthe appropriate Design Factor applied.

3) Estimate the wear rate in terms of loss of wall thickness per operating day.4) Calculate, from the allowable loss in wall thickness and the rate of wear, the allowable

operating time in the string.

If the allowable operating time is less than the anticipated operating time, use heavier casing(or increases the grade) 100m above and to 60m below the wear point until the allowableoperating time exceeds the anticipated operating time.

If the allowable operating time is greater than the anticipated operating time (say estimated 50days allowable versus estimated 20 days operating) do not include a wear allowance. If theallowable operating time and the anticipated operating time are about the same, either:

a) Include a wear allowanceor

b) Monitor casing wear during drilling, and commission an intermediate string if theworn casing strength approaches the design loads.

In any given situation whether option a) or b) is exercised will be dependent upon a number offactors, many of which are beyond the scope of routine casing design.

ARPO



REVISION

STAP-P-1-M-6110 0

Option a)

Is the conservative approach, but it may be too high, given the gross uncertainties inherent inwear estimations. However, in rank wildcats, particularly in remote locations, it may bejustified.

Option b)

Requires a base caliper survey to be run immediately after installing the casing string,followed by runs at discrete intervals during the drilling phase.

If wear is proven to have occurred, and an intermediate string has to be commissioned early,the deeper objectives of the well may not be reached. However, conditions as drillingproceeds may indicate that the design loads assumed are not going to be encountered andthe reduction in casing strength is acceptable.

In any event, valuable data on casing wear in the area will be obtained and field practices maybe improved as result of the attention paid to wear, eventually leading to a reduction in overallwear rates.

In most cases, option b) is preferred.


There is no reliable method of predicting casing wear and defining the correspondingreduction in casing performance. Because the reduction in burst and collapse rating isdirectly proportional to wall thickness the revised theoretical value may be calculated.

The normal procedure to cater for possible wear when designing casing is to select the nextcasing grade or wall thickness, therefore, in a vertical well, casing wear is usually in the firstfew joints below the wellhead or intervals with a high dog-leg severity.

Consideration should be given to increasing the grade or wall thickness of the first few jointsbelow the wellhead.

In deviated wells, wear will be over the build-up and drop-off sections. Again the casing overthese depths can be of a higher grade or heavier wall thickness.

ARPO



REVISION

STAP-P-1-M-6110 0

8.7. SALT SECTIONS

8.7.1. General

Salt formations often exhibit plastic flow properties which can cause exceedingly high loadson casing. The rate of salt flow is a function of its composition, temperature, depth oroverburden pressure and also probably influenced by how it is bedded or interbedded withother formations.

The problem of salt formations has to be assessed on an individual well to well and/or area toarea basis.

The objectives for drilling through salt zones should be:

a) To achieve trouble free drilling.b) Prevent casing collapse during the drilling and the production life of the well.

With regards to trouble free drilling, sticking due to salt flow, mud problems from saltcontamination, hole enlargement and the well's overall casing programme, are the primefactors to be considered.

There are other factors that have to not be under evaluated such as:

• Control of gas flows from porous zones interbedded in the salt, differential stickingin porous zones.

• Abnormal pressure due to entrapment of pressure by salt.• Shale sloughing from interbedded or boundary shales.

To prevent casing collapse, the designer should plan for non-uniform salt loading, obtainingthe best possible cement job, using casing with higher than normal collapse ratings andpossibly two strings of casing through the salt section.

Running casing in salt sections is rather a cementing problem than a casing design problem.

In some cases, two strings may be more advantageous as experience has demonstrated thatit is not practical to design a casing string to resist collapse. This technique is probably themost reliable and safest approach for preventing casing collapse but is probably notnecessary for the majority of salt sections.

8.7.2. External Loading Due To Salt Flow

Traditional analyses of casing response to external loading are not adequate whenconsidering all of the possible effects caused by salt formation flow.

Three additional factors have to be analysed for casing design in areas where there is saltflow:

a) Uniform external loading.b) Non-uniform or non symmetric external loading.c) Asymmetrical formation loading.

ARPO



REVISION

STAP-P-1-M-6110 0

Uniform External Loads

Figure 8.W - Uniform External Loading

If there is a possibility of salt loading, several remedial actions may be taken. The first groupof precautions may be classified under the general heading of filling the casing internally,either, with gravel, other solids or a fluid. For production casing, such actions are usually notpossible.

The alternative is to run a scab liner inside the casing opposite the suspect formation andcement the annulus between the two casing strings refer to figure 8.x.

The benefits gained from running such a liner are substantial.

ARPO



REVISION

STAP-P-1-M-6110 0

Figure 8.X - Casing With Liner Installed and Cemented

ARPO



REVISION

STAP-P-1-M-6110 0

Another source of non-uniform loading is bending of the casing as a result of curvature of thewellbore. Consider an initially straight casing length under external pressure and axial loadsthat are insufficient to result in collapse. Now assume that the casing is gradually bent by anadditional external force as for example due to salt flowing (Refer to figure 8.y below).

Figure 8.Y - Non-Uniform Loading

In the lower portion of the figure, the flowing formation has come in contact with the casingthus restricting its movement. Above this point of contact, additional flow of the formation isdepicted as being in progress. Subsequent formation movement above the frozen point willcause severe bending loads and, thus, reduce the casing cross-sectional integrity.

Problems may be observed before final catastrophic failure of the cross section e.g. theovality of the cross section may be sufficient enough to result in restrictions in the casing thatwill prohibit the passage of bits or production equipment.

However, even in the presence of non-uniform external loads, the structural benefits of usingconcentric casing strings are substantial.

ARPO



REVISION

STAP-P-1-M-6110 0

Asymmetrical Formation Loads

For straight casing the most severe loading situation that could be expected from the saltenvironment is 'point loading’.

If for some reason cement placement results in only a partial sheath around the casing, theremainder of the annulus being filled with mud, subsequent movement of the salt formationwill result (Refer to figure 8.z below).

The result of point loading is devastating leading to complete casing collapse. In fact, nocasing is strong enough to resist point loading in its extremist form.

Figure 8.Z - Point Loading

ARPO



REVISION

STAP-P-1-M-6110 0


In designing casing for any application, the accepted design load is the one for which thecasing is subjected to the greatest conceivable loads.

In the particular case of casing design opposite salt formations, certain guidelines can beconsidered:

• For production casing exposed to salt formations, assume the casing will bealways evacuated at some point during the well life.

• The uniform external pressure exerted by salt on the casing (or cement sheath)due to overburden pressure should be given a value equal to the true verticaldepth to the point in question.

• Proper cement placement opposite a salt section is often difficult due to washout.• Any beneficial effects of the cement sheath should be ignored during design of the

casing.• If the wellbore is deviated, additional axial forces due to hole curvature should be

considered when determining the collapse resistance of the casing.

Conclusions:

• Running casing in salt sections is rather a cementing problem than a casingproblem.

• If the pipe is well cemented, it is sufficient to design for collapse load in thetraditional mode (overburden pressure/design factor).

• If the casing is poorly cemented the collapse effect may be very high. In this case,it may help to run heavier wall casing (Refer to figure 8.aa).

ARPO



REVISION

STAP-P-1-M-6110 0

Figure 8.AA - High Collapse Resistance Casing For Deep Wells

ARPO



REVISION

STAP-P-1-M-6110 0

9. CORROSION

9.1. GENERAL

A production well design should attempt to contain produced corrosive fluids within tubing.They should not be produced through the casing/tubing annulus.

However, it is accepted that tubing leaks and pressured annuli are a fact of life and as such,production casing strings are considered to be subject to corrosive environments whendesigning casing for a well where hydrogen sulphide (H2S) or carbon dioxide (CO2) ladenreservoir fluids can be expected.

During the drilling phase, if there is any likelihood of a sour corrosive influx occurring,consideration should be given to setting a sour service casing string before drilling into thereservoir.

The BOP stack and wellhead components must also be suitable for sour service.

9.1.1. Exploration and Appraisal Wells

Routine measures to be taken during drilling include:

• Use of casing and wellhead equipment with a metallurgy suitable for sour service.• Use of high alkaline mud to neutralise the H2S gas.• Use of inhibitors and/or scavengers.

These measures will provide a degree of short term protection necessary to control corrosionof the casing in the hole during the drilling phase.

9.1.2. Development Wells

Casing corrosion considerations for development wells can be confined to the productioncasing only.

• Internal corrosion

The well should be designed to contain any corrosive fluids (produced or injected) withinthe tubing string by using premium connections.

Any part of the production casing that is likely to be exposed to the corrosiveenvironment, during routine completion/workover operations or in the event of a tubingor wellhead leak, should be designed to withstand such an environment.

• External corrosion

Where the likelihood of external corrosion due to electrochemical activity is high and theconsequences of such corrosion are serious, the production casing should becathodically protected (either cathodically or by selecting a casing grade suitable for theexpected corrosion environment).

ARPO



REVISION

STAP-P-1-M-6110 0

9.1.3. Contributing Factors to Corrosion

Most corrosion problems which occur in oilfield production operations are due to the presenceof water. Whether it may be present in large amounts or in extremely small quantities, it isnecessary to the corrosion process. In the presence of water, corrosion is an electrolyticprocess where electrical current flows during the corrosion process. To have a flow ofcurrent, there must be a generating or voltage source in a completed electrical circuit.

The existence, if any, of the following conditions alone, or in any combination may be acontributing factor to the initiation and perpetuation of corrosion:

• Oxygen (O2)Oxygen dissolved in water drastically increases its corrosivity potential. It can causesevere corrosion at very low concentrations of less than 1.0ppm.

The solubility of oxygen in water is a function of pressure, temperature and chloridecontent. Oxygen is less soluble in salt water than in fresh water.

Oxygen usually causes pitting in steels.

• Hydrogen Sulphide (H2S)Hydrogen sulphide is very soluble in water and when dissolved behaves as a weak acidand usually causes pitting. Attack due to the presence of dissolved hydrogen sulphide isreferred to as ‘sour’ corrosion.

The combination of H2S and CO2 is more aggressive than H2S alone and is frequentlyfound in oilfield environments.

Other serious problems which may result from H2S corrosion are hydrogen blisteringand sulphide stress cracking.

It should be pointed out that H2S also can be generated by introduced micro-organisms.

• Carbon Dioxide (CO2)When carbon dioxide dissolves in water, it forms carbonic acid, decreases the pH ofthe water and increase its corrosivity. It is not as corrosive as oxygen, but usually alsoresults in pitting.

The important factors governing the solubility of carbon dioxide are pressure,temperature and composition of the water. Pressure increases the solubility to lowerthe pH, temperature decreases the solubility to raise the pH.

Corrosion primarily caused by dissolved carbon dioxide is commonly called ‘sweet’corrosion.

Using the partial pressure of carbon dioxide as a yardstick to predict corrosion, thefollowing relationships have been found:

Partial pressure >30psi usually indicates high corrosion risk.

Partial pressure 3-30psi may indicate high corrosion risk.

Partial pressure <3psi generally is considered non corrosive.

ARPO



REVISION

STAP-P-1-M-6110 0

• TemperatureLike most chemical reactions, corrosion rates generally increase with increasingtemperature.

• PressurePressure affects the rates of chemical reactions and corrosion reactions are noexception.

In oilfield systems, the primary importance of pressure is its effect on dissolved gases.More gas goes into solution as the pressure is increased, this may in turn increase thecorrosivity of the solution.

• Velocity of fluids within the environmentStagnant or low velocity fluids usually give low corrosion rates, but pitting is more likely.Corrosion rates usually increase with velocity as the corrosion scale is removed fromthe casing exposing fresh metal for further corrosion.

High velocities and/or the presence of suspended solids or gas bubbles can lead toerosion, corrosion, impingement or cavitation.

9.2. FORMS OF CORROSION

The following forms of corrosion are addressed in this manual:

Corrosion caused by H2S (SSC)

Corrosion caused by CO2 and Cl-

Corrosion caused by combinations of H2S, CO2 and Cl-

Corrosion in injection wells and the effects of pH and souring are not included.

The procedure adopted to evaluate the corrosivity of the produced fluid and the methodologyused to calculate the partial pressures of H2S and CO2 will be illustrated in the following sub-sections.

9.2.1. Sulphide Stress Cracking (SSC)

The SSC phenomenon is occurs usually at temperatures of below 80°C and with thepresence of stress in the material. The H2S comes into contact with H2O which is anessential element in this form of corrosion by freeing the H+ ion. Higher temperatures, e.g.above 80°C inhibit the SSC phenomenon, therefore knowledge of temperature gradients isvery useful in the choice of the tubular materials since differing materials can be chosen forvarious depths.

Evaluation of the SSC problem depends on the type of well being investigated. In gas wells,gas saturation with water will produce condensate water and therefore create the conditionsfor SSC. In oil wells, two separate cases need to be considered, vertical and deviated wells:

a) In vertical oil wells, generally corrosion occurs only when the water cut becomeshigher than 15% which is the ‘threshold’ or commonly defined as the ‘critical level’and it is necessary to analyse the water cut profile throughout the producing life ofthe well.

ARPO



REVISION

STAP-P-1-M-6110 0

b) In highly deviated wells (i.e. deviations >80o), the risk of corrosion by H2S is highersince the water, even if in very small quantities, deposits on the surface of thetubulars and so the problem can be likened to the gas well case where the criticalthreshold for the water cut drops to 1% (WC >1%).

The following formulae are used to calculate the value of pH2S (partial pressure of H2S) inboth the cases of gas (or condensate gas) wells or oil wells.

Firstly, the potential for SSC occurring is evaluated by studying the water cut valuescombined with the type of well and deviation profile. If the conditions specified above areverified then the pH2S can be calculated.

Gas Or Condensate Gas Well

H2S partial pressure is calculated by:

pH2S = SBHP x Y(H2S)/100

where:

SBHP = Static bottom-hole pressure [atm]

Y(H2S) = Mole fraction of H2S

pH2S = Partial H2S pressure [atm]

SSC is triggered at pH2S >0.0035 atm and SBHP >4.5 atm.

Oil Bearing Well

The problem of SSC exists when there is wetting water; i.e.:

Water cut >15% for vertical wells

Water cut >1% for horizontal or highly deviated wells (>80o)

or if the GOR >800 Nm3/m3

The pH2S calculation is different for undersaturated and oversaturated oil.

Undersaturated Oil

In an oil in which the gas remains dissolved, because the wellhead and bottom-holepressures are higher than the bubble point pressure (Pb) at reservoir temperature, is termedundersaturated.

In this case the pH2S is calculated in two ways:

• Basic method.• Material balance method.

If the quantity of H2S in gas at the bubble point pressure [mole fraction = Y(H2S)], is not knownor the values obtained are not reliable, the pH2S is calculated using both methods and thehigher of the two results is taken as the a reliable value. Otherwise the basic method is used.

ARPO



REVISION

STAP-P-1-M-6110 0

Basic Method

This method is used, without comparison with the other method, when the H2S value in theseparated gas at bubble point conditions is known and is reliable or if Y(H2S), molar fraction inthe separated gas at bubble point pressure (Pb) is higher than 2%.

The pH2S is calculated by:

pH2S = Pb x Y(H2S)/100

where:

Pb = Bubble point pressure at reservoir temperature [atm]

Y(H2S) = Mole fraction in the separated gas at bubble point (from PVT data ifextrapolated)

pH2S = Partial H2S pressure [atm]

Material Balance Method

This method is used when data from production testing is available and/or when the quantityof H2S is very small (<2,000ppm) and the water cut value from is lower than 5% (this methodcannot be used when the WC values are higher). The value of H2S in ppm to be used in thecalculation must also be from stable flowing conditions. Note: H2S sampled in shortproduction tests, is generally lower than the actual value under stabilised conditions.

The following algorithm is used to calculate the pH2S:

pH2S is calculated at the separator (pH2Ssep):

pH2Ssep = (Psep x H2Ssep)/106 Eq. 9.A

where:

Psep = Absolute mean pressure at which the separator works (from tests) inatm

H2Ssep = Mean H2S value in the separator gas (generally measured in ppm)

ARPO



REVISION

STAP-P-1-M-6110 0

The mean molecular weight of the produced oil, PM :

( )PM

GORd

PMGOR

res

=+

−

γ

γ

1000

100023 6

29

23 6.

.

Eq. 9.B

where:

PM res = mean molecular weight of the reservoir oil = CiMii

n

=∑

1

100/

Ci = Mole% of the ith component of the reservoir oil

Mi = Molecular weight of the ith component of the reservoir oil

d = Density of the gas at separator conditions referred to air =1

The quantity of H2S in moles/litre dissolved in the separator oil is calculated:

[H2S]oil = (pH2Ssep/H1 x (γ x 1000)/ PM ) Eq. 9.C

where:

H1 = Henry constant of the produced oil at separator temperature (atm/Molefraction). (See Procedure for calculating Henry constant)

PM = Mean molecular weight of the produced oil

γ = Specific weight g/l of the produced oil

The quantity of H2S in the gas in equilibrium is calculated (per litre of oil):

[H2S]gas = (GOR/23.6 x H2Ssep/106) Eq. 9.D

where:

GOR = Gas oil ratio Nm3/m3 (from production tests)

23.6 = Conversion factor

The pH2S is calculated at reservoir conditions:

pH2S = (([H2S]oil + [H2S]gas)/K ) x H2 Eq. 9.E

where:

K = (γ x 1000/ PM + GOR/23.6) total number of moles of the liquid phase in

the reservoir

H2 = Henry constant for the reservoir temperature and reservoir oil. (Seeprocedure for calculating Henry constant)

ARPO



REVISION

STAP-P-1-M-6110 0

In general, H2S corrosion can occur at either the wellhead or bottom-hole without distinction.

There is SSC potential if pH2S >0.0035 atm and STHP >18.63 atm.

Procedure For Calculating Henry Constant

The value of the Henry constant is a function of the temperature measured at the separator.The mapping method can be applied for temperatures at the separator of between 20°C and200°C. Given the diagram in figure 9.a which represents the functions H(t) for the three typesof oils:

• Heptane PM = 100

• N-propyl benzene PM = 120

• Methylnaphthalene PM = 142

Remarks On The H1 Calculation

Having calculated the molecular weight of the produced oil PM using the formula in eq. 9.b,

the reference curve is chosen (given by points) to calculate the Henry constant on the basisof the following value thresholds:

• If PM > 142, the H(t) curve of methylnaphthalene is used.

• If PM = 120, the H(t) curve of propyl benzene is used.

• If PM < 100, the H(t) curve of heptane is used.

• If 100 <PM < 120, the mean value is calculated using the H(t) curve of propyl

benzene and the H(t) curve of methylnaphthalene.• If 120 <PM < 142 the mean value is calculated using the H(t) curve of heptane

and the H(t) curve of propyl benzene.• Given FTHT, wellhead flowing temperature, the H1 value is interpolated linearly on

the chosen curve(s). For this purpose the temperature values immediately beforeand after the temperature studied are taken into consideration.

Comments On The H2 Calculation

Having calculated the molecular weight of the reservoir oil PM res, using temperature

measured at the separator, H2 is measured in a similar way as H1.

ARPO



REVISION

STAP-P-1-M-6110 0

Figure 9.A - H(t) Reference Curves

Oversaturated Oil

Oil is considered oversaturated when the gas in the fluid separates because the pressure ofthe system is lower than the bubble point pressure. Two situations can arise:

Case A

FTHP < Pb

FBHP > Pb

Case B

FTHP < Pb

FBHP < Pb

20

30

40

50

60

70

80

90

100

110

120

130

20 30 40 50 60 70 80 90 100 110 120 130 140 150 160 170 180 190 200

methylnaphthalene PM = 142

N-propylbenzene PM = 120

heptane PM = 100

T C°

Henry atm/Y[H 2S]

ARPO



REVISION

STAP-P-1-M-6110 0

Calculation Of Partial Pressure In Case A:

1) Calculation is of the partial pressure in the reservoir:In this case pH2S is calculated in the way described for undersaturated oil.

2) Calculation is of the partial pressure at the wellhead, i.e. when FTHP <Pb:The data result from the production conditions and only the basic method is used.

Basic Method

pH2S = STHP x Y(H2S) / 100

where:

STHP = static tubing head pressure [atm]

Y(H2S) = mole fraction in separated gas at STHP pressure and wellhead temperature

pH2S = partial H2S pressure [atm]

The SSC phenomenon is triggered off at the wellhead if pH2S >0.0035 atm and STHP >18.63atm.

Calculation Of Partial Pressure In Case B:

Calculation of partial pressure in the reservoir:

In the reservoir the gas is already separated, FBHP <Pb, calculation of pH2S can beapproximated on the basis of the following:

• the PVTs are reliable, Y(H2S) >0.2%, the partial pressure is calculated as:pH2S = Y(H2S)(1) x FBHP

where:

Y(H2S) = molar fraction in gas separated at FBHP and at reservoir temperature (from PVT)

• the PVTs are not reliable, the material balance method can be used as in thecase of undersaturated oil; these are the worst conditions. The error made can behigh when Pb >FBHP.

Calculation Of Partial Pressure At Wellhead

The calculation method is that used for case A (FTHP <Pb)(2)

Notes: (1) If the percentage (ppm) of H2S in the gas under static conditions is not known, the

corresponding value in reservoir conditions is assumed as being partial pressure at thewellhead.

(2) If the percentage (ppm) of H2S in the separated gas under static conditions is notknown, the corresponding value in reservoir conditions is assumed as being partialpressure at the wellhead.

ARPO



REVISION

STAP-P-1-M-6110 0

9.2.2. Corrosion Caused By CO2 And Cl-

In the presence of water, CO2 gives rise to a corrosion form which is different to thosecaused by the presence of H2S. It also occurs only if the partial pressure of CO2 exceeds aparticular threshold. As in the case of SSC, the possibility that corrosions exist in water cutvalues combined with the type of well and deviation profile, is evaluated. If the conditionsdescribed in section 9.2.1 exist, then the pCO2 is then calculated.

Gas Or Condensate Gas Wells

The partial pressure is calculated:

pCO2 = SBHP x Y(CO2)/100

where:

SBHP = Static bottom-hole pressure [atm]

Y(CO2) = Mole fraction of CO2

pCO2 = Partial pressure of CO2 [atm]

Corrosion occurs if pCO2 >0.2 atm.

Oil Bearing Wells

The problem exists where there is wetting water; i.e.:

• Water cut >15% for vertical wells.• Water cut >1% for horizontal or highly deviated wells (> 80 degrees).

Undersaturated Oil Wells

The partial pressure of CO2 is calculated:

pCO2 = Pb x Y(CO2)/100

where:

Pb = Bubble point pressure at reservoir temperature

Y(CO2) = Mole fraction of CO2 in separated gas at bubble point pressure (from thePVTs)

pCO2 = Partial pressure of CO2 [atm]


The pCO2 values calculated in this way are used to evaluate the corrosion at bottom hole andwellhead; i.e. pCO2 at wellhead is assumed as corresponding to reservoir conditions.

ARPO



REVISION

STAP-P-1-M-6110 0

Oversaturated Oil

The oil is considered oversaturated when the gas separates in the fluid because the pressureof the system is lower than bubble point pressure. Two situations may arise:

Case A

FTHP <Pb

FBHP >Pb

Case B

FTHP <Pb

FBHP <Pb

Calculation Of Partial Pressure In Case A:

Calculation of pCO2 in reservoir conditions:

FBHP >Pb pCO2 is calculated in the same way as undersaturated oil wells earlier in thissection.

pCO2 = Pb x Y(CO2)/100

where:

Pb = bubble point pressure at reservoir temperature

Y(CO2) = mole fraction in separated gas at bubble point pressure (from the PVTs)

pCO2 = partial pressure of CO2 [atm]


Calculation Of PCO2 At Wellhead:

pCO2 = STHP x Y(CO2)/100

where:


Y(CO2) = mole fraction in separated gas at STHP(3)



Note:(3) If the percentage (ppm) of CO2 in the gas under static conditions is not known, the

corresponding value in reservoir conditions is assumed as being partial pressure at thewellhead.

ARPO



REVISION

STAP-P-1-M-6110 0

Calculation Of Partial Pressure In Case B:

Calculation of pCO2 at reservoir conditions:

pCO2 = FBHP x Y(CO2)/100

where:

FBHP = flowing bottom-hole pressure [atm]

Y(CO2) = mole fraction in separated gas at pressure FBHP (from the PVTs)


Calculation Of pCO2 At Wellhead:

The calculation method is the same as the one used in the wellhead conditions in case A:

pCO2 = STHP x Y(CO2)/100

where:


Y(CO2) = mole fraction in separated gas at STHP(4)


There is corrosion if pCO2 >0.2 atm.

9.2.3. Corrosion Caused By H2S, CO2 And Cl-

It is possible to encounter H2S and CO2 besides Cl-. In this case the problem is much morecomplex and the choice of suitable material is more delicate. The phenomenon is diagnosedby calculating the partial pressures of H2S and CO2 and comparing them with the respectivethresholds.

Note:

(4) If the percentage (ppm) of CO2 in the gas under flowing/static conditions is not known,the corresponding value in reservoir conditions is assumed as being partial pressure atthe wellhead.

ARPO



REVISION

STAP-P-1-M-6110 0

9.3. CORROSION CONTROL MEASURES

Corrosion control measures may involve the use of one or more of the following:

• Cathodic protection• Chemical inhibition• Chemical control• Oxygen scavengers• Chemical sulphide scavengers• pH adjustment• Deposit control• Coatings• Non metallic materials or metallurgical• Control• Stress reduction• Elimination of sharp bends• Elimination of shock loads and vibration• Improved handling procedures• Corrosion allowances in design• Improved welding procedures• Organisation of repair operations.

Refer to table 9.a below.

Measure Means

Control of the environment • pH• Temperature• Pressure• Chloride concentration• CO2 concentration• H2S concentration• H2O concentration• Flow rate• Inhibitors

Surface treatment • Plastic coating• Plating

Improvement of the corrosion resistivity of thesteel

Addition of the alloying elements micro structure

Table 9.A - Counter Measures to Prevent Corrosion

ARPO



REVISION

STAP-P-1-M-6110 0

9.4. CORROSION INHIBITORS

An inhibitor is a substance which retards or slows down a chemical reaction. Thus, acorrosion inhibitor is a substance which, when added to an environment, decreases the rateof attack by the environmental on a metal.

Corrosion inhibitors are commonly added in small amounts to acids, cooling waters, steam orother environments, either continuously or intermittently to prevent serious corrosion.

There are many techniques used to apply corrosion inhibitors in oil and gas wells:

• Batch treatment (tubing displacement, standard batch, extended batch)• Continuous treatment• Squeeze treatment• Atomised inhibitor squeeze - weighted liquids• Capsules• Sticks.

9.5. CORROSION RESISTANCE OF STAINLESS STEELS

Stainless steel is usually used in applications for production tubing, however it is occasionallyused for production casing or tubing below the packer depth.

The main reason for the development of stainless steel is its resistance to corrosion. To beclassed as a stainless steel, an iron alloy usually must contain at least 12% chromium involume. The corrosion resistance of stainless steels is due to the ability of the chromium topassivate the surface of the alloy.

Stainless steels may be divided into four distinct classes on the basis of their chemicalcontent, metallurgical structure and mechanical properties these are:

9.5.1. Martensitic Stainless Steels

The martensitic stainless steels contain chromium as their principal alloying element. Themost common types contain around 12% chromium, although some chromium content maybe as high as 18%.

The carbon content ranges from 0.08% to 1.10% and other elements such as nickel,columbium, molybdenum, selenium, silicon, and sulphur are added in small amounts forother properties in some grades.

The most important characteristic that distinguishes these steels from other grades is theirresponse to heat treatment. The martensitic stainless steels are hardened by the same heattreatment procedures used to harden carbon and alloy steels.

The martensitic stainless steels are included in the ‘400’ series of stainless steels. The mostcommonly used of the martensitic stainless steels is AISI Type 410. The only grade of oilfieldtubular used in this category is 13Cr. As their name indicates, the microstructure of thesesteels is martensitic. Stainless steels are strongly magnetic whatever the heat treatmentcondition.

ARPO



REVISION

STAP-P-1-M-6110 0

9.5.2. Ferritic Stainless Steels

The second class of stainless steels, is the ferritic stainless steels, which are similar to themartensitic stainless steels in that they have chromium as the principal alloying element. Thechromium contents of ferritic stainless steels is normally higher than that of the martensitic,stainless steel, and the carbon content is generally lower.The chromium content ranges between 13% to 27% but are not able to be hardened by heattreatment. They are used principally for their temperature properties.Ferritic stainless steels are also part of the ‘400’ series, the principal types being 405, 430,and 436.The microstructure of the ferritic stainless steels consists of ferrite, which are also stronglymagnetic. Ferrite is simply body cantered cubic iron or an alloy based on this structure.

9.5.3. Austenitic Stainless Steels

The austenitic stainless steels have two principal alloying elements, chromium and nickel.Their micro-structure consists essentially of austenite which is face cantered cubic iron or aniron alloy based on this structure.

They contain a minimum of 18% chromium and 8% nickel, with other elements added forparticular reasons, and may range up to as high as 25% chromium and 20% nickel.

Austenitic stainless steels generally have the highest corrosion resistance of any of thestainless steels, but their strength is lower than martensitic and ferritic stainless steels.

They are not able to be hardened by heat treatment although they are hardenable to someextent by cold working and are generally non-magnetic.

Austenitic stainless steels are grouped in the ‘300’ series, the most common being 304.Others commonly used are 303 free machining, 316 high Cr and Ni which may include Mo,and 347 stabilised for welding and corrosion resistance.

These steels are widely used in the oilfield for fittings and control lines, but due to its lowstrength is not used for well tubulars.

9.5.4. Precipitation Hardening Stainless Steels

The most recent development in stainless steel is a general class known as ‘precipitationhardened stainless steels’, which contain various amounts of chromium and nickel.

They combine the high strength of the martensitic stainless steels with the good corrosionresistance properties of the austenitic stainless steels.

Most were developed as proprietary alloys, and there is a wide variety of compositionsavailable.

The distinguishing characteristic of the precipitation hardened stainless steel is that throughspecific heat treatments at relatively low temperatures, the steels can be hardened to varyingstrength levels.

Most can be formed and machined before the final heat treatment and the finished productbeing hardened. Precipitation in alloys is analogous to precipitation as rain or snow.

These are most commonly used for component parts in downhole and surface tools and notas oilfield tubulars. Refer to figure 9.b for the various compositions of stainless steels.

ARPO



REVISION

STAP-P-1-M-6110 0

Figure 9.B- Stainless Steel Compositions

9.5.5. Duplex Stainless Steel

ARPO



REVISION

STAP-P-1-M-6110 0

In general, ferritic-austenitic (duplex) stainless steel consists of between 40-70% ferrite andhas a typical composition of 22% Cr-5.5% Ni-3% Mo-0.14% N.

The resulting steel has properties that are normally found in both phases: the ferrite promotesincreased yield strength and resistance to chloride and hydrogen sulphide corrosion cracking;while the austenite phase improves workability and weldability.

This material is used extensively for tubulars used in severe CO2 and H2S conditions.

As a general note, there is a large gap between the 13CR and Duplex Stainless Steels usedas tubulars for their good anti-corrosion properties. This gap is attempted to be filled with‘Super 13CR’ tubing being developed.

ARPO



REVISION

STAP-P-1-M-6110 0

9.6. CASING FOR SOUR SERVICEOCTG Materials For Corrosion By H2S Only In Oil Wells

Conditions Material Alternately0.0035< pH2S max < 0.1 FBHT >80oC J55, K55, N80, C95, P110 L80-Mod, C90-1, T95-10.0035< pH2S max < 0.1 60oC< FBHT >80oC J55, K55, N80 L80-Mod, C90-1, T95-10.0035< pH2S max < 0.1 FBHT >80oC L80 L80-Mod, C90-1, T95-1

pH2S max < 0.1 L80 Mod, C90-1, T95-1OCTG Materials For Corrosion By H2S Only In Gas Wells

Conditions Material Alternately0.0035< pH2S max < 0.1 FBHT >80oC J55, K55, N80-2, C95 L80-Mod, C90-1, T95-10.0035< pH2S max < 0.1 FBHT <80oC L80 L80-Mod, C90-1, T95-1

OCTG Materials For Corrosion By CO2 And Cl-

Conditions Material Alternately0.2< pCO2S max <100 FBHT <150oC Cl- <50,000 13% Cr

0.2< pCO2S max <100150oC< FBHT <200oC

22% Cr

0.2< pCO2S max <100200oC< FBHT <250oC

25% Cr-SA 25% CrOCTG Materials For Corrosion By CO2 , H2S And Cl -

Conditions Material Alternately0.2< pCO2S max <100e

0.0035< pH2S max < 0.005 FBHT <150oC Cl- <50,00013% Cr-80KSI

Max22% Cr25% Cr

0.2< pCO2S max <100epH2S max <0.005

FBHT <200oC Cl- >50,00022% Cr CW25% Cr CW

0.2< pCO2S max <100e0.0035< pH2S max <0.005

150oC< FBHT <200oCCl- <50,000

22% Cr25% Cr

0.2< pCO2S max <100e0.0035< pH2S max <0.005

200oC< FBHT <250oCCl- <50,000 25% Cr

0.2< pCO2S max <100e0.0035< pH2S max <0.005

200oC< FBHT <250oCCl- >50,000 25% Cr CW

0.2< pCO2S max <100e0.005< pH2S max <0.1

FBHT <250oC Cl- <20,000 25% Cr

pCO2S max <100e0.005< pH2S max <0.1

FBHT <250oC Cl- <50,000 25% Cr CW

0.2< pCO2S max <100e0.005< pH2S max <0.1

200oC< FBHT <250oCCl- <50,000 28% Cr

0.2< pCO2S max <100e0.1< pH2S max <1

FBHT <200oC Cl- <50,000 22% Cr SA22% Cr, 25% Cr

Incoloy 8250.2< pCO2S max <100e

0.1< pH2S max <1FBHT <250oC Cl- <50,000 25% Cr SA

28% CrIncoloy 825

0.2< pCO2S max <100e0.1< pH2S max <1

FBHT <200oC Cl- >50,000 28% Cr Incoloy 825

0.2< pCO2S max <100epH2S max >1

28% Cr Incoloy 825

Table 9.B - OCTG Materials for Sour Service

ARPO



REVISION

STAP-P-1-M-6110 0

9.7. ORDERING SPECIFICATIONS

When ordering tubulars for sour service, the following specifications should be included, inaddition to those given in the above table.

1) Downgraded grade N80, P105 or P110 tubulars are not acceptable for orders for J55 orK55 casing.

2) The couplings must have the same heat treatment as the pipe body.3) The pipe must be tested to the alternative test pressure (see API Bulletins 5A and 5AC).4) Cold die stamping is prohibited, all markings must be paint stencilled or hot die

stamped.5) Three copies of the report providing the ladle analysis of each heat used in the

manufacture of the goods shipped, together with all the check analyses performed,must be submitted.

6) Three copies of a report showing the physical properties of the goods supplied and theresults of hardness tests (Refer to step 3 above) must be submitted.

7) Shell modified API thread compound must be used.

Note: Recommendations for casing to be used for sour service must bespecified according to the API 5CT for restricted yield strength casings.

The casing should also meet the following criteria:

• The steel used in the manufacture of the casing should have been quenched andtempered. (This treatment is superior to tubulars heated/treated by other methodse.g. normalising and tempering).

• All sour service casing should be inspected using non-destructive testing orimpact tests only, as per API Specification 5CT.

9.8. COMPANY DESIGN PROCEDURE

9.8.1. CO2 Corrosion

The following guidelines should be used for the appropriate corrosive environment.

• In exploration wells, generally the presence of CO2 in the formation causes littleproblems, and will have no influence on material selection for the casing.

• In producing wells, the presence of CO2 may lead to corrosion on those partscoming in contact with CO2 which normally means the production tubing and partof the production casing below the packer.

Corrosion may be limited by:

• The selection of high alloy chromium steels, resistant to corrosion.• Inhibitor injection, if using carbon steel casing. Generally, wells producing CO2

partial pressure higher than 20psi requires inhibition to limit corrosion.

ARPO



REVISION

STAP-P-1-M-6110 0

9.8.2. H2S Corrosion

In exploration wells, if there is high probability of encountering H2S, consideration shouldbe given to limit casing and wellhead yield strength according to API 5CT and ‘NACE’standard MR-01-75.

In producing wells, casing and tubing material will be selected according to the amountof H2S and other corrosive media present.

Refer to figure 9.c and figure 9.d for partial pressure limits.

Figure 9.C - Sour Gas Systems

Figure 9.D - Sour Multiphase Systems

ARPO



REVISION

STAP-P-1-M-6110 0

Figure 9.E - Sumitomo Metals

ARPO



REVISION

STAP-P-1-M-6110 0

Application(Refer to figure 9.e)

Domain Material SM’Designation

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


13Cr SteelModified AISI 420

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


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” 25C -35Ni 3Mo Steel

22Cr 42N -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



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

ARPO



REVISION

STAP-P-1-M-6110 0

10. TEMPERATURE EFFECTS

10.1. HIGH TEMPERATURE SERVICE

For deep wells, reduction in yield strength must be considered due to the effect on steel bythe temperature.

It no information is available on temperature gradients in the area, a gradient of 3°C/100m isto be used.

Use the values in figure .a10.a for reduction in yield strength.

where:

K0.2 = Yield strength as per ISO normative with permanent deformation of 0.2%.

Figure .A10.A - Temperature Effects

ARPO



REVISION

STAP-P-1-M-6110 0

10.2. LOW TEMPERATURE SERVICE

Operations at low temperatures require tubulars made from steel with high ductility at lowtemperatures to prevent brittle failures during transport and handling.

(Refer to figure 10.b below)

Figure 10.B - Arctic Service

ARPO



REVISION

STAP-P-1-M-6110 0

11. LOAD CONDITIONS

When running casing, shock loads are exerted on the pipe due to:

• Sudden deceleration forces (e.g.: if the spider accidentally closes or the slips arekicked-in when the pipe is moving or the pipe hits a bridge).

• Sudden acceleration forces (e.g.: picking the pipe out of the slips or if the casingmomentarily hangs up on a ledge then freed).

Either of the above will cause a stress wave to be created which will travel through the casingat the speed of sound.

This effect is quantified as follows:

SL = 150 x V x Af

where:SL = Shock load (lbs x ins2)V = Peak velocity when running (ins/sec)Af = Cross-sectional area (ins2)150 = Speed of sound in steel (lbs x sec/ins)

11.1. SAFE ALLOWABLE TENSILE LOAD

A safe allowable pull on the pipe should be calculated, stipulated during the casing stringdesign process and specified in the Geological Drilling Programme or communicated to thewell site prior to running casing. This is particularly important when reciprocating pipe duringthe cementing procedure.

The application of the pulling load should only be considered as an emergency measure toretrieve the casing string from the wellbore. It is normal to incorporate an overpull contingencyof 100,000lbs (45tons over the weight of the string in the mud as part of the casing stringdesign).

11.2. CEMENTING CONSIDERATIONS

11.2.1. Casing Support

The cement sheath can protect the casing against several types of potential downholedamage including:

• Deformation through perforating gun detonations.• Formation movement, salt flows, etc. (Refer to previous section 8.7).• The loss of the bottom joint on surface or intermediate strings during drilling.

ARPO



REVISION

STAP-P-1-M-6110 0

However, the following aspects also need to be noted:

• Adding resistance to casing collapse for design purposes is questionable.• In fault slippage zones, doglegs and certain sand control failures, the cement

sheath may contribute to problems.

11.2.2. Cementing Loads

As a cement slurry is pumped into the casing, the weight indicator increases to a maximumwhen mud has been displaced from the casing by the full amount of cement.

The maximum weight of the string occurs when the cement reaches the casing shoe or whenthe top cement plug is released.

This weight increase can approach the remaining allowable pull margin of the string. Ifreciprocation is contemplated, this remaining margin may be so small to preventreciprocation and, hence stretching of the pipe. After considering this issue, the designengineer may decide that a higher allowable pull contingency is required.

For design calculation, the worst case situation is assumed as follows:

• The mud weight in the annulus is the lowest planned for the section.• The inside of the casing is full of cement slurry, with mud above.• The shoe instantaneously plugs off just as the cement reaches it and the

pressure rises to a value of approximately ‘1,000psi’ before the pumps are able tobe shut down.

The load in this situation is calculated as follows:

CCL = [(Cw - Mw) x D + 1,000] x Ai

where:

CCL = Cementing contribution load (lbs)

Cw = Cement weight (psi/ft)

Mw = Outside mud weight (psi/ft)

D = Length over which Cw & Mw act(ft)

Ai = Internal area of casing (ins2)

1,000 = Pressure increment (psi)

ARPO



REVISION

STAP-P-1-M-6110 0

11.3. PRESSURE TESTING

Casing pressure tests will be carried out according to the pressure stated in the drillingprogramme. The leading criteria for pressure testing will be the maximum anticipatedwellhead pressure.

In all cases the test pressure will be no higher than 70% of API minimum internal yieldpressure of the weakest casing in the string or to 70% of the BOP WP.

When establishing an internal casing pressure test, the differential pressure due to adifference in fluid level and/or fluid density, inside and outside the casing, shall be taken intoaccount.

Consideration should be taken on the maximum allowable tensile strength of the casingthread considering the relevant tensile design factor.

Each casing shall be pressure tested at the following times:

• When cement plug bumps on bottom with a pressure stated in the drillingprogramme.

• When testing blind/shear rams of the BOP stack against the casing.• After having drilled out a DV collar.

A cemented liner overlap will be positively tested applying a pressure greater than the lea-offpressure of the previous casing. If there is any doubt, an inflow test could be carried out, witha sufficient drawdown to test the liner top to the most severe negative differential pressurethat will exist during the life of the well.

The test pressure shall be held and remain stable for at least 10-15 mins

The test pressure and method for each well are determined on an individual basis and shallbe included in the Geological and Drilling Programme.

11.4. BUCKLING AND COMPRESSIVE LOADING

The following buckling and compressive loads must also be considered.

11.4.1. Buckling

Buckling is a failure of stability which can occur at stress levels well below the yield stress ofthe material. Buckling cannot occur where the casing is supported by cement.

Factors responsible for buckling and the degree of buckling are:

• Length of casing, supported by cement.• Hole size and degree of washout.• Tensile loads on the casing string.• Changed pressure conditions across the pipe.• Temperature increases downhole.

All these factors are interrelated but the first three are generally considered major contributorsto buckling, while temperature and pressure changes are primarily the mechanisms thatcause the initial buckling.

ARPO



REVISION

STAP-P-1-M-6110 0

A buckling potential may exist in the uncemented portion of a string of casing, if the:

• Internal mud density is increased.• Internal surface pressure is increased.• Annular fluid removed or its density reduced.• Casing is landed with less than full hanging weight.• Temperature of the casing increases.

Buckling of long, uncemented portions of the casing string, in vertical wells, can be preventedby:

• Cementing the casing up above the neutral point.• Pre-tensioning the casing after landing.• Limiting the increase in mud density used after drilling out the casing.• Rigidly centralising the casing below the neutral point.

Provided that all casing strings can be landed with full hanging weight, the buckling calculationis only required on the small percentage of deep vertical wells in which the mud density is tobe raised during the drilling of the next open hole section. Thus, for the majority of wells,buckling is not a major design problem.

11.4.2. Compressive Loads

Compressive loads can occur in casing strings as a result of:

• Landing inner strings within or on top of an outer string.• Restricting length changes that would occur as the result of increasing downhole

temperatures. This condition occurs when casing strings are anchored firmly atboth ends with an unsupported interval between.

In most well designs, the total compressive load is the buoyant load of the intermediatecasings, the tubing to production packer overpull and the weight of the wellhead. Thiscompressive load is carried by the outer casing string. This outer casing is usually theconductor or surface casing.

When discussing compressive loads it is convenient to consider three types of well where:

a) The wellhead is at ground level or at the seabed.b) The wellhead is above seabed (i.e.: platform wells).c) The mudline suspension takes the weight of the casing at the seabed, but the

wellhead is above seabed.

ARPO



REVISION

STAP-P-1-M-6110 0

Wellhead at Ground Level or at Seabed

When the surface casing (i.e.: 20ins or 185/8ins) is cemented to the surface or seabed it canbe considered as a rigid foundation capable of carrying the total buoyant weight of the innerstrings, the wellhead and any tubing to packer load.

If the surface casing is not cemented to surface the uncemented portion will compress in theelastic manner until either the yield is exceeded or buckling occurs (if the unsupported lengthexceeds a critical length). From this, it is obvious that surface casing should and must becemented to surface. The surface casing string must be designed to carry the compressiveloads placed upon it.

No compressive load is carried by the inner strings.

Buckling may be ignored if the surface casing is completely cemented to the base of thewellhead.

Wellhead above Sea Level (Platform Wells, No Mudline Suspension)

Compressive loads in surface strings on wells in which the wellheads is above sea level, canlead to buckling in the free-standing portion of the well.

To prevent buckling, every joint of the surface casing must be centralised within the previousstring (usually a free standing 30ins or 26ins string) or restrained by a wellhead jacket.

The surface casing must be designed for compression loads as outlined in a) above. Forevery new platform, a full structural analysis should be commissioned. This analysis mustassess the adequacy of the conductor/surface casing design for buckling resistance.

Mudline Suspension

In this case, the weight of the casing strings is taken at the seabed. The surface casing mustbe designed and cemented as outlined in a) above.

The tieback strings above the mudline suspension hanger may be subject to some degree ofbuckling.

Most wellhead hook-ups can be safely supported on a 20ins x 133lbs/ft casing string in waterdepths up to 300ft (92m). However, if buckling may be suspected to occur in the tied backsurface string a full structural analysis should be commissioned. The structural analysis maybe carried out by companies involved in the supply of conductors.

The analysis is in effect a Riser Tensioner Analysis as is evaluated for semi-submersiblesand it takes into account the effect of waves, current and the weight of the pipe in the freestanding mode.

ARPO



REVISION

STAP-P-1-M-6110 0

Compressive Loads Due to Temperature

Temperature rises in the uncemented portion of a casing string will give rise to axiallycompressive forces in the string, if the casing is constrained. However, the compressiveforces will relieve the tensional forces in the casing and need not be considered in the designunless buckling occurs.

Therefore, except in extreme cases such as thermal recovery wells, temperature loads needonly be assessed in casing strings on which buckling may occur and need only be treated inthis context.

Decrease in Temperature

a) Drilling Phase:

It is highly unlikely that any routine operation (other than extensive reverse circulation)will cause a long term temperature decrease in the uncemented portion of a casingstring, thus, no loading applies.

b) Production Phase:

Temperature induced stresses are of no consequence in the outer strings of casingand attention need only be paid to the production string.

Producers are normally subjected to temperature increases under operating conditionsand the compressive load induced should be treated in the context of buckling.

The tensile loads induced by cooling in high volume injection wells, or in producersduring high volume stimulation treatments or emergency squeeze kills, must be takeninto account.

It should be added to the axial load and included in the design load if the occurrence ofsuch loading is anticipated

ARPO



REVISION

STAP-P-1-M-6110 0

12. PRESSURE RATING OF BOP EQUIPMENT

This section includes design criteria for BOP equipment which are extracted from the WellControl Policy Manual.

The prime considerations, when selecting and procuring pressure control equipment, are thesafety of the personnel, rig and maintaining the integrity of the wellbore. In order to assure thissafety requirement, several factors need to be considered.

Note: It should be realised that each drilling area may have local regulationsunique to that particular area which exceed the general requirementsstated in this section, or indeed the Eni-Agip Well Control Policy Manual.In addition, the various operating companies and their contractors mayalso vary from these general requirements, if dictated by individualcompany policy and philosophy providing they are not less stringent thandescribed herein.

The anticipated formation pressure is the governing parameter which dictates the casingdepth, casing selection, BOP selection and pressure rating of the BOP equipment asdescribed previously in section 2.

The weakest element within any pressure control system determines the maximum pressurethat can be safely controlled.

Individual elements of the pressure control system may exceed the assembly WP, andunder no circumstances should components be used which are less than theassembly WP. For instance, a 10,000psi choke may be rigged up with a 2,000psi BOP stackin anticipation of its later use when the 10,000psi BOP stack is nippled up for a subsequentstring of casing.

The equipment in the well control system which has the lowest pressure rating will set therating for entire system e.g. 2,000psi stack and 10,000psi choke manifold would be rated toonly 2,000psi WP.

Since the well control system must be able to contain any anticipated formation pressuresthat may be encountered, the maximum anticipated surface pressures must first becalculated.

Many different methods are available to determine the maximum casing pressures which maybe encountered during a kick as described in section 2.

12.1. BOP SELECTION CRITERIA

Blow-out preventer equipment configurations shall consist of an annular preventer and aspecified number of ram type preventers.

The working pressure of any blow-out preventer shall exceed the maximum anticipatedsurface pressure to which it may be subjected.

ARPO



REVISION

STAP-P-1-M-6110 0

The graph illustrated in the attached figure 12.a has been prepared to enable the firstapproximation of the BOP rating necessary for use in drilling an exploration well. To use thegraph, the setting depths of the various casings and the relative pore pressure gradients mustbe found or determined during the design phase.

The co-ordinates in the graph are depth and pressure and comprises two groups of linesrespectively, one representing the BOPs to be used while drilling and the other the BOPs tobe used during well testing.

Each group outlines the different solutions available to the various pore pressure gradients.

Example: The casing program assumes that a well test will be carried out at the shoe of 7”casing. From the diagram shown in table 12.a, the maximum test, drillingpressure values and the size of BOP to be used should be obtained which isgiven in table 12.a below.

Casing(ins)

ShoeDepth

(m)

OverburdenGradient

(kg/cm2/10m)

Pore Press.Gradient

(kg/cm2/10m)

FractureGradient

(kg/cm2/10m)

BOPDrilling

(psi)

SizeProductionTest (psi)

20 750 2.23 1.03 1.83 2,000 /

133/8 2.620 2.36 1.30 2.01 5,000 /

95/8 4.200 2.42 1.70 2.18 10,000 /

7 4.830 2.43 2.00 2.29 / 15,000

Table 12.A - BOP Selection Example Data

The maximum theoretical stress possible at the casing head, Pmax, occurs when the well isfull of gas and the fracture pressure has been reached at the shoe of the last casing run.

This pressure is:

)(Kg/cm )D-G(10HPmax 2

gr=

where:

H = Casing shoe depth (m)

Gf = Fracture gradient of the casing shoe (kg/cm2/10m)

Dg = Gas density, assumed = 0.3(kg/dm3)

In the case of a well test, this pressure roughly corresponds to the limit value required forpumping gas into the formation and is thus actually attainable in practice.

This hypothesis however is completely unrealistic in the drilling design, for which 60% of thepressure Pmax will be used as limit value according to company policy in ‘burst designcriteria’, section 8.1. This value is also adopted by many other companies as the realisticcriterion of choice.

ARPO



REVISION

STAP-P-1-M-6110 0

Figure 12.A - BOP Selection Example

ARPO



REVISION

STAP-P-1-M-6110 0

12.2. KICK TOLERANCEKick tolerance is the term used to define the maximum kick volume which can be safelycontrolled by any well control method with constant BHP without fracturing the formationbelow the last casing shoe.

The most dangerous situation is when the top of the kick reaches the casing shoe. This iscalculated with the following formula:

( )10

HGHGHGP mmiip

top

×+×−×=

Ptop < Pfr

( )10

x

10

xx

10

x HGHGHHHGP sfriiism

P =−−

−

( )[ ]im

Pmmf rSi GG

P10HGGGHH−

×−×+−=

Vshoe = Ca x Hi

V1 x P1 = P2 X V2

V1bottom x Pp = Vshoe x Pfr

where:

Ca = Annular capacity below the shoe, mH = Total depth, mHi = Height of influx, mHS = Shoe DepthGfr = Formation fracture gradient at shoe, kg/cm2/10mGm = Mud weight, kg/ltrPP = Formation pressure at total depth, kg/cm2

Gi = Density of the influxPtop = Top Influx PressureGp = Pore gradientHm = Hight of the mud below the influxPfr = Fracture pressure

ARPO



REVISION

STAP-P-1-M-6110 0

Appendix A - ABBREVIATIONS

API American Petroleum InstituteBG Background gasBHA Bottom Hole AssemblyBHP Bottom Hole PressureBHT Bottom hole temperatureBOP Blow Out PreventerBPD Barrel Per DayBPM Barrels Per MinuteBSW Base Sediment and WaterBUR Build Up RateBWOC By Weight Of CementBWOW By Weight Of WaterCBL Cement Bond LogCCD Centre to Centre DistanceCCL Casing Collar LocatorCET Cement Evaluation ToolCGR Condensate Gas RatioCP Conductor PipeCRA Corrosion Resistant AlloyCW Current WellDC Drill CollarDHM Down Hole MotorDLP Dog Leg PotentialDLS Dog Leg SeverityD&CM Drilling & Completion ManagerDOB Diesel Oil BentoniteDOBC Diesel Oil Bentonite CementDOR Drop Off RateDP Drill PipeDST Drill Stem TestDV DV CollarECD Equivalent Circulation DensityECP External Casing PackerEMS Electronic Multi ShotEMW Equivalent Mud WeightEOC End Of CurvatureESD Electric Shut-Down SystemESP Electrical Submersible PumpFBHP Flowing Bottom Hole PressureFBHT Flowing Bottom Hole TemperatureFPI/BO Free Point Indicator / Back OffFTHP Flowing Tubing Head PressureFTHT Flowing Tubing Head TemperatureGLR Gas Liquid RatioGMS Gyro Multi Shot

ARPO



REVISION

STAP-P-1-M-6110 0

GOC Gas Oil ContactGOR Gas Oil RatioGPM Gallon (US) per MinuteGPS Global Positioning SystemGR Gamma RayGSS Gyro Single ShotHAZOP Hazard and OperabilityHHP Hydraulic HorsepowerHP/HT High Pressure - High TemperatureHW/HWDP Heavy Weight Drill PipeIADC International Drilling ContractorID Inside DiameterIPR Inflow Performance RelationshipJAM Joint Make-up Torque AnalyserKMW Kill mud weightKOP Kick Off PointLAT Lowest Astronomical TideLCM Lost Circulation MaterialsLCP Lower Circulation Position (GP)LEL Lower Explosive LimitLOT Leak Off TestLQC Log Quality ControlLWD Log While DrillingMAASP Max Allowable Annular Surface PressureMD Measured DepthMLS Mudline SuspensionMMS Magnetic Multi ShotMODU Mobile Offshore Drilling UnitMOP Margin of OverpullMPI Magnetic Particle InspectionMSL Mean Sea LevelMSS Magnetic Single ShotMW Mud WeightMWD Measurement While DrillingNACE National Association of Corrosion EngineersNDT Non Destructive TestNMDC Non Magnetic Drill CollarNSG North Seeking GyroNTU Nephelometric Turbidity UnitOBM Oil Based MudOD Outside DiameterOH Open HoleOIM Offshore Installation ManagerOMW Original Mud weightORP Origin Reference PointOWC Oil Water ContactP&A Plugged & Abandoned

ARPO



REVISION

STAP-P-1-M-6110 0

PBR Polished Bore ReceptaclePCG Pipe Connection GasPDC Polycrystalline Diamond CutterPDM Positive Displacement MotorPGB Permanent Guide BasePI Productivity IndexPLT Production Logging Toolppb Pounds per Barrelppg Pounds per Gallonppm Part Per MillionPV Plastic ViscosityPVT Pressure Volume TemperatureQ Flow RateQ/A Q/C Quality Assurance, Quality ControlRFT Repeat Formation TestRKB Rotary Kelly BushingROE Radius of ExposureROP Rate Of PenetrationROU Radios Of UncertaintyROV Remote Operated VehicleRPM Revolutions Per MinuteRT Rotary TableS (HDT) High Resolution DipmeterS/N Serial NumberSBHP Static Bottom-hole PressureSBHT Static Bottom-hole TemperatureSCC Stress Corrosion CrackingSD Separation DistanceSDE Senior Drilling EngineerSF Safety FactorSG Specific GravitySICP Shut-in Casing PressureSIDPP Shut-in Drill Pipe PressureSPM Stroke per MinuteSR Separation RatioSRG Surface Readout GyroSSC Sulphide Stress CrackingSTG Short trip gasTCP Tubing Conveyed PerforationsTD Total DepthTGB Temporary Guide BaseTOC Top of CementTOL Top of LinerTVD True Vertical DepthTW Target WellUAR Uncertainty Area RatioUR Under Reamer

ARPO



REVISION

STAP-P-1-M-6110 0

VBR Variable Bore Rams (BOP)VDL Variable Density LogVSP Velocity Seismic ProfileW/L Wire LineWBM Water Base MudWC Water CutWL Water LossWOB Weight On BitWOC Wait On CementWOW Wait On WeatherWP Working PressureYP Yield Point

ARPO



REVISION

STAP-P-1-M-6110 0

Appendix B - BIBLIOGRAPHY

Document: STAP Number

Drilling Procedures Manual STAP-P-1-M-6140

Drilling Design Manual STAP-P-1-M-6100

Overpressure Manual STAP-P-1-M-6130

Drilling Fluids Manual STAP-P-1-M-6160

Well Control Policy Manual STAP-P-1-M-6150

API Specification 5C

Holmquist & Nadai

Shell (Bol, 1985)

NACE Standard MR-01-75

Sumitomo Metals Literature

Download - ENI - Casing Design Manual

Top Related