A R P O ENI S.p.A. Agip Division ORGANISING DEPARTMENT TYPE OF ACTIVITY' ISSUING DEPT. DOC. TYPE REFER TO SECTION N. PAGE. 1 OF 134 STAP 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 for reasons 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 CDRom version can also be distributed (requests will be addressed to STAP Dept. in Eni -Agip Division Headquarter)
Date of issue: „ ƒ ‚ • € Issued by P. Magarini
E. Monaci C. Lanzetta A. Galletta
28/06/99 28/06/99 28/06/99
REVISIONS PREP'D CHK'D APPR'D
INDEX
1.
INTRODUCTION
5
1.1. PURPOSE OF CASING 6
2.
CASING PROFILES AND DRILLING SCENARIOS
7
2.1. Casing Profiles 7
2.1.1. Onshore Wells 7
2.1.2. Offshore Wells - Surface Wellhead 7
2.1.3. Offshore Wells - Surface Wellhead & Mudline Suspension 7
2.1.4. Offshore Wells - Subsea Wellhead 7
2.2. Drive, Structural & Conductor Casing 8
2.2.1. Surface Casing 8
2.2.2. Intermediate Casing 9
2.2.3. Production Casing 10
2.2.4. Liner 11
3.
SELECTION OF CASING SEATS
12
3.1. Conductor Casi ng 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 17
3.6.1. 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 38
6.2.1. Markings 38
A R P O
ENI
S.p.A.Agip Division
IDENTIFICATION CODE PAGE 3 OF 134
REVISION
STAP-P-1-M-6110 0
7.
APPROACH TO CASING DESIGN
41
7.1. WELLBORE FORCES 42
7.2. DESIGN FACTOR (DF) 42
7.2.1. Company Design Factors 44
7.2.2. Application of Design Factors 45
8.
DESIGN CRITERIA
46
8.1. BURST 46
8.1.1. Design Methods 46
8.1.2. Company Design Procedure 47
8.2. COLLAPSE 50
8.2.1. Company Design Procedure 50
8.3. TENSION 54
8.3.1. General 54
8.3.2. Buoyancy Force 54
8.3.3. Company Design Procedure 59
8.3.4. Example Hook Load During Cementing 59
8.4. BIAXIAL STRESS 62
8.4.1. General 62
8.4.2. Effects On Collapse Resistance 62
8.4.3. Company Design Procedure 64
8.4.4. Example Collapse Caclulation 65
8.5. BENDING 67
8.5.1. General 67
8.5.2. Determination Of Bending Effect 68
8.5.3. Company Design Procedure 70
8.5.4. Example Bending Calculation 70
8.6. CASING WEAR 72
8.6.1. General 72
8.6.2. Volumetric Wear Rate 73
8.6.3. Factors Affecting Casing Wear (Example) 76
8.6.4. Wear Factors 80
8.6.5. Detection Of Casing Wear 86
8.6.6. Casing Wear Reduction 86
8.6.7. Wear Allowance In Casing Design 87
8.6.8. Company Design Procedure 88
8.7. SALT SECTIONS 89
8.7.1. General 89
8.7.2. External Loading Due To Salt Flow 89
8.7.3. Company Design Procedure 94
9.
CORROSION
96
9.1. General 96
9.1.1. Exploration and Appraisal Wells 96
9.1.2. Development Wells 96
9.1.3. Contributing Factors to Corrosion 97
9.2. Forms Of Corrosion 98
9.2.1. Sulphide Stress Cracking (SSC) 98
9.2.2. Corrosion Caused By CO2 And Cl
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 109
9.5.1. Martensitic Stainless Steels 109
9.5.2. Ferritic Stainless Steels 110
9.5.3. Austenitic Stainless Steels 110
9.5.4. Precipitation Hardening Stainless Steels 110
9.5.5. Duplex Stainless Steel 111
9.6. Casing For Sour Service 113
9.7. Ordering Specifications 114
9.8. Company Design Procedure 114
9.8.1. CO2 Corrosion 114
9.8.2. 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 120
11.2.1. Casing Support 120
11.2.2. Cementing Loads 121
11.3. PRESSURE TESTING 122
11.4. BUCKLING AND COMPRESSIve loading 122
11.4.1. Buckling 122
11.4.2. Compressive Loads 123
12.
PRESSURE RATING OF BOP EQUIPMENT
126
12.1. BOP selection criteria 126
A R P O
ENI
S.p.A.Agip Division
IDENTIFICATION CODE PAGE 5 OF 134
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 and various mechanical factors.
The engineer must keep in mind during the design process the major logistics problems in controlling the handling of the various mixtures of grades and weights by rig personnel without risk 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 weights is 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 upgrading the casing in cases where:
• Extreme wear is expected from drilling equipment used to drill the next hole section 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 always a major criterion.
Most major operating companies have differing policies for the design of casing for exploration and 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 bottomhole flowing pressures and well head shut-in pressures as the limiting factors for internal pressures expected in the wellbore. These pressures will obviously place controls only on the design of production casing or the production liner, and intermediate casing.
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.
A R P O
ENI
S.p.A.Agip Division
IDENTIFICATION CODE PAGE 7 OF 134
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 and offshore 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.
2.2. DRIVE, STRUCTURAL & CONDUCTOR CASING
The purpose of this first string of pipe is primarily to protect incompetent surface soils from erosion by drilling fluids. Where formations are sufficiently stable, this string may be used to install the full mud circulation system.
It also serves the following purposes:
• Guide the drilling string and subsequent casing into the hole. The conductor in offshore drilling may form a part of the piling system for a wellhead jacket or piled platform.
• Provide centralisation for the inner casing strings which limits column buckling. They do not carry direct axial loads except during initial installation of the surface casing.
• 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 a predrilled or jetted hole and cemented. If they are driven, they must be designed to withstand hammering loads.
Conductor casings, in offshore drilling with subsea BOP's, are usually either jetted into place or cemented in a predrilled hole. They support a Temporary Guide Base which accommodates and aligns all future wellhead installations for both the drilling and production phases. They directly carry both the axial and bending loads imposed by the wellhead, but are rigidly connected to the next casing with centralisers and cement in order to dissipate loading and 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 which BOPs can be mounted. It is important to appreciate that the amount of protection provided against 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 than attempt 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 limit column buckling.
The annulus between the conductor and surface string is usually left uncemented above the mudline to minimise load transfer and bending stresses in the surface string.
A R P O
ENI
S.p.A.Agip Division
IDENTIFICATION CODE PAGE 9 OF 134
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 to isolate formations or hole profile changes, that can cause drilling problems.
The first intermediate string is the first casing providing full blow-out protection. Its setting depth is often chosen so that it also isolates troublesome formations, loss zones, shallow hydrocarbons, water sands, or the build-up section of deviated wells. It is usually cemented up 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 a kick which could cause breakdown at the previous casing shoe, and/or severe losses in the open hole section.
An intermediate casing string is, therefore, nearly always set in the transition zone above or below 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 the known hydrocarbon bearing intervals as a contingency against the possibility of encountering a loss circulation zone. Obviously the latter is intended primarily for massive reservoir sections 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 drilling and completing the well by isolating intervals which have been found to cause mechanical problems 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 single casing point. A liner may be used instead of a full intermediate casing and difficult wells may actually contain several intermediate casings and/or liners. Caution should be taken when using liners as it is necessary to ensure the higher casing is designed for the pressures at lower 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, especially where there may be aquifer movement which replenishes the corrosive elements around the wellbore.
Longer cement columns are sometimes required to prevent buckling of the casing during deeper drilling. Many operating companies cement up inside the previous casing shoe for this reason and is legislated on by some regulatory authorities.
2.2.3. Production Casing
This is the string through which the well will be completed, produced and controlled throughout its life.
On exploration wells this life may amount to only a very short testing period, but on most development wells it will span a significant number of years during which many repairs and recompletions may be performed. It is essential therefore that production casing retains its integrity throughout its life.
In most cases, the production casing will serve to isolate the productive intervals, to facilitate proper 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 below the casing for an open hole completion (Refer to the completion design manual). The size of the production casing should be selected to meet with the desired method of completion and production.
On production wells the drilling engineer must design the casing in conjunction with the completion engineer to ensure the optimum completion design is obtained. This usually impacts 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 well deliverability (casing flow), for minimising the pressure losses during frac jobs, for chemical injection or for lift gas. Consideration must be given to production operations which will affect the temperature of the production casing and impose additional thermal stresses. Annulus thermal expansion can cause production casing collapse when it is cemented up into the intermediate casing. The loads to which a production casing is subjected are, therefore, quite different from those imposed during drilling.
It is very important that the selection of the steel grade and connections for the production string are made correctly.
Special considerations are required where the production casing will be drilled through and may therefore suffer some damage e.g.: open hole (barefoot) completions, open hole gravel packs, liner completions, deep zone appraisal.
In a liner completion, both the liner and casing form the production string and must be designed accordingly.
A R P O
ENI
S.p.A.Agip Division
IDENTIFICATION CODE PAGE 11 OF 134
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 is hung a short distance above the previous casing shoe and is usually cemented over its entire length 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 into a 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 poor cementation 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 a tubing string has been run and landed.)
3.
SELECTION OF CASING SEATS
The selection of casing setting depths is one of the most critical in the well design process and 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 to obtain knowledge of the various uncertainties.
Information is sourced from:
• Evaluation of the seismic and geological background documentation used as the decision for drilling the well.
• Drilling data from offset wells in the area. (Company wells or scouting information).
The key factor to satisfactory picking of casing seats is the assessment of pore pressure and fracture pressures throughout the well.
As the pore pressures in a formation being drilled approach the fracture pressure at the last casing seat then installation of a further string of casing is necessary.
A R P O
ENI
S.p.A.Agip Division
IDENTIFICATION CODE PAGE 13 OF 134
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 is F1.
b) Drilling continues to depth 2, where the pore pressure P2 has risen to almost equal 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 taken into account.
Figure 3.B - Example Casing Seat Selection
A R P O
ENI
S.p.A.Agip Division
IDENTIFICATION CODE PAGE 15 OF 134
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 mud pits while drilling the surface hole. The casing seat must be in an impermeable formation with sufficient fracturing resistance to allow fluid circulation to the surface.
Where working with subsea wellheads, no there is no circulation through the conductor string to the surface. It is set deep enough to assist in stabilising the guide base to which guide lines are attached.
Large sizes are required (usually 16ins to 30ins diameter) as necessary to accommodate the size 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 allow drilling to the next casing setting point and to provide reasonable assurance that broaching to the 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 strings are necessary.
3.3. INTERMEDIATE CASING
The most predominant use of intermediate casing is to protect normally pressured formations from the effects of increased mud weight needed in deeper drilling.
An intermediate string may be necessary to case off lost circulation zones, salt beds, or sloughing shales.
In cases of pressure reversals against depth, intermediate casing may be set to allow reduction of mud weight.
When a transition zone is penetrated and mud weight increased, the normal pressure interval below surface pipe is subjected to two detrimental effects:
• The fracture gradient may be exceeded by the mud gradient, particularly if it becomes necessary to close-in on a kick The result is loss of circulation and the possibility of an underground blow-out occurring.
• The differential between the mud column pressure and formation pressure is increased, increasing the risk of stuck pipe.
To ensure the integrity of the surface casing seat, leak-off tests are necessary and must be specified in the Drilling Programme.
Sometimes it is necessary to alter the setting depth of the intermediate casing during drilling under 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 should state the pore pressure requirement at which casing should be set when setting casing into a transition zone.
3.4. DRILLING LINER
The setting of a drilling liner is often an economically attractive decision in deep wells as opposed to setting a full string. Such a decision must be carefully considered as the intermediate 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 intermediate string are further increased which increases the cost of the intermediate string. Also, there is the 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 be tied 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 the production liner. By doing this, the intermediate casing can be designed for a lower burst requirement, resulting in considerable cost savings. Also, any wear to the intermediate string is spanned prior to drilling the producing interval.
If increasing mud weight will be required, while drilling hole for the drilling liner, then leak-off tests must be conducted and specified in the casing programme for the intermediate casing shoe 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.
A R P O
ENI
S.p.A.Agip Division
IDENTIFICATION CODE PAGE 17 OF 134
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 geological objective. Depths, hence the casing programme, may have to be altered accordingly if depths come in too high or too low.
The objective and the method of identifying the correct production casing depth should also be stated in the programme.
To cater for some completion operations, a sufficient amount of sump is required for fill during production or well intervention operations, run out for logging tools and to accommodate lost tools 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 evaluated before 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 casing may be necessary to provide sufficient strength. The designer can sometimes solve this problem by specifying ‘special’ drift casing which will allow running of bits with diameters approaching the casing inside diameter rather than being limited to drift diameter.
Manufacturers produce oversize casing in several sizes providing strength comparable to API sizes, 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 casing and 7ins production casing/liner.
Although the above is one of the most common arrangements, there is a multitude of different combinations of casing sizes which the operator may choose to use if he desires, and if the casing design allows.
For a normal exploration well, it is recommended that an 81/2ins hole be the smallest diameter planned because of drilling and evaluation difficulties encountered with 6ins. A 6ins hole size should only be planned as a contingency.
A R P O
ENI
S.p.A.Agip Division
IDENTIFICATION CODE PAGE 19 OF 134
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 drilling programme 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 to have adequate clearance to run and cement the casing or liner (i.e., 51/2” Casing inside 77/8” 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 the connection, mud weight, cementing and doglegs.
Large connection ODs, thick mud cake build-up, problem cementing areas (high water loss, lost returns, etc.) and doglegs all aggravate the attempt to run casing and liners in low clearance situations.
Once the hole size has been selected. a casing large enough to allow passage of a bit to 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 has been reached.
Note: Some drilling programmes can require special tools and operations to obtain the wellbore size for the casing to be installed. An underreamer is a 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.
Figure 3.D - Standard Casing Programme
A R P O
ENI
S.p.A.Agip Division
IDENTIFICATION CODE PAGE 21 OF 134
REVISION
STAP-P-1-M-6110 0 3.6.1. Standard Casing and Hole Sizes
Outer Casing Size
Largest Inner
Casing Size Under-Reaming
Minimum Pilot Hole Size Under-reamed Diameter Maximum Tool OD 24 20 181/2 26 18 20 16 171/2 22 17 16 133/8 14 3 /4 17 1 /2 14 133/8 (48-68#) 10 3 /4 12 1 /4 15 11 3 /4 113/4 8 5 /8 10 5 /8 12 1 /4 10 95/8 (29.3#) 7 5 /8 8 3 /4 11 1 /2 8 1 /4 85/8 (24-32#) 6 5 /8 7 5 /8 9 1 /2 7 1 /4 85/8 (36-49#) 6 7 3 /8 9 7 75/8 5 1 /2 6 1 /4 8 1 /2 6 7 (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 outer string drift diameter and inner coupling diameter.
•• The clearance between the hole wall and the coupling OD is at least 2” on diameter. Less clearance than this may create a back pressure which will dehydrate the cement to a point where it cannot be pumped.
4.
CASING SPECIFICATION AND CLASSIFICATION
There is a great range of casings available from suppliers from plain carbon steel for everyday mild service through exotic duplex steels for extremely sour service conditions. The casings available can be classified under two specifications, API and non-API.
Casing specifications, including API and its history, are described and discussed in sections 4.1 and 4.2. Non-API casing manufacturers have produced products to satisfy a demand in the industry for casing to meet with extreme conditions which the API specifications do not meet. 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 and should be fully understood by design engineers, and to this end these properties are described in section 4.2.
4.1. CASING SPECIFICATION
The American Petroleum Institute (API) has an appointed Committee on Standardisation of tubular goods which publishes, and continually updates, a series of Specifications, Bulletins and Recommended Practices covering the manufacture, performance and handling of oilfield tubular goods. They also license manufacturers to use the API Monogram on products which meet with their published specifications therefore can be identified as complying with the standards.
The API Forum has been in existence since 1924, and their standardisation of oilfield equipment 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 theoretical representation 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 Bulletin 5C2 which lists the performance properties of casing, tubing and drillpipe. Although these are also 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 engineers should make themselves familiar with these documents and their contents.
It should not be interpreted from the above that only API tubulars and connections may be used in the field as some particular engineering problems are overcome by specialist solutions which are not yet addressed by API specifications. In fact, it would be impossible to drill many extremely deep wells without recourse to the use of pipe manufactured outwith API specifications (non-API).
Similarly, many of the ‘Premium’ connections that are used in high pressure high GOR conditions are also non-API.
A R P O
ENI
S.p.A.Agip Division
IDENTIFICATION CODE PAGE 23 OF 134
REVISION
STAP-P-1-M-6110 0
When using non-API pipe, the designer must check the methods by which the strengths have been calculated. Usually it will be found that the manufacturer will have used the published API formulae (Bulletin 5C3), backed up by tests to prove the performance of his product conforms to, or exceeds, these specifications. However, in some cases, the manufacturers have claimed their performance is considerably better than that calculated by the using API formulae. When this occurs the manufacturers claims must be critically examined by the designer or his technical advisors, and the performance corrected if necessary.
It is also important to understand, that to increase competition, the API tolerances have been set fairly wide. However, the API does provide for the purchaser to specify more rigorous chemical, physical and testing requirements on orders, and may also request place independent 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 and performances.
Col 1 Col 2 Col 3 Col 4 Col 5 Size: OD Nominal Wt Grade Wall Thickness Type of Thread
ins m m lbs per ft Grades Inc ins m m Short Long Buttress Extreme Line
85/ 8 219.1 24.00 J, K 0.264 6.71 X 85/ 8 219.1 28.00 H 0.304 7.72 X 85/8 219.1 32.00 H 0.352 8.94 X 85/8 219.1 32.00 J, K 0.352 8.94 X X X X 85/8 219.1 36.00 J, K 0.400 10.16 X X X X 85/ 8 219.1 36.00 C, L, N 0.400 10.16 X X X 85/ 8 219.1 40.00 C, L, N, P 0.450 11.43 X X X 85/ 8 219.1 44.00 C, L, N, P 0.500 12.70 X X X 85/ 8 219.1 49.00 C, L, N, P, Q 0.557 14.15 X X X 95/ 8 244.5 32.30 H 0.312 7.92 X 95/8 244.5 36.00 H 0.352 8.94 X 95/8 244.5 36.00 J, K 0.352 8.94 X X X 95/8 244.5 40.00 J, K 0.395 10.03 X X X X 95/ 8 244.5 40.00 C, L, N 0.395 10.03 X X X 95/ 8 244.5 43.50 C, L, N, P 0.435 11.05 X X X 95/ 8 244.5 47.00 C, L, N, P 0.472 11.99 X X X 95/ 8 244.5 53.50 C, L, N, P, Q 0.545 13.84 X X X 95/ 8 244.5 59.40 C 90 only 0.609 15.47 95/8 244.5 64.90 C 90 only 0.672 17.07 95/8 244.5 70.30 C 90 only 0.734 18.64 95/8 244.5 75.60 C 90 only 0.797 20.24 103/ 4 273.1 32.75 H 0.297 7.09 X 103/ 4 273.1 40.50 H 0.350 8.89 X 103/ 4 273.1 40.50 J, K 0.350 8.89 X X 103/ 4 273.1 45.50 J, K 0.400 10.16 X X X 103/ 4 273.1 51.00 C, K, K, N, P 0.450 11.43 X X X 103/4 273.1 55.50 C, L, N, P 0.495 12.57 X X X 103/4 273.1 60.70 P, Q 0.545 13.84 X X X 103/4 273.1 65.70 P, Q 0.595 15.11 X X 103/ 4 273.1 59.40 C 90 only 0.545 13.84 103/ 4 273.1 65.70 C 90 only 0.595 15.11 103/ 4 273.1 73.20 C 90 only 0.672 17.07 103/ 4 273.1 79.20 C 90 only 0.734 18.64 103/ 4 273.1 85.30 C 90 only 0.797 20.24 113/4 298.5 42.00 H 0.333 8.46 X 113/4 298.5 47.00 J, K 0.375 9.52 X X 113/4 298.5 54.00 J, K 0.435 11.05 X X 113/ 4 298.5 60.00 J,K,N,C,L,P,Q 0.489 12.42 X X 133/ 8 339.7 48.00 H 0.330 8.38 X 133/ 8 339.7 54.50 J, K 0.380 9.65 X X 133/ 8 339.7 61.00 J, K 0.430 10.92 X X 133/ 8 339.7 68.00 C,L,J,K,N,P,Q 0.480 12.19 X X 133/8 339.7 72.00 C, L, N, P, Q 0.514 13.06 X X 16 406.4 65.00 H 0.375 9.52 X 16 406.4 75.00 J, K 0.438 11.13 X X 16 406.4 84.00 J, K 0.495 12.57 X X 185/ 8 473.0 87.50 H, J, K 0.435 11.05 X 185/ 8 473.0 87.50 J, K 0.435 11.05 X 20 508.0 94.00 H, J, K 0.438 11.13 X X 20 508.0 94.00 J, K 0.438 11.13 X 20 508.0 106.50 J, K 0.500 12.70 X X X 20 508.0 133.00 J, K 0.635 16.13 X X X
A R P O
ENI
S.p.A.Agip Division
IDENTIFICATION CODE PAGE 25 OF 134
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. Some manufacturers produce non-API casings for H2S and deep well service where API casings do not 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 they are recommended to be used.
Application (Refer to
figure 4.a) Domain Material
SM’
Designation Notes Mild Environment Domain “A” API J 55
N 80 P 110 (Q 125)
SM 95G SM 125G
Sulphide Stress Corrosion Cracking (medium pressure and temperature)
Domain “B” Cr or Cr-Mo Steel API L 80 C 90 T 95 SM 80S SM 90S SM 95S Sulphide Stress Corrosion
Cracking (high pressure and temperature)
Domain “C” 1Cr 0.5Mo Steel Modified AISI 4130 SM 85SS SM 90SS SM C100 SM C110 Higher yield strength for sour service
Wet CO2 Corrosion Domain “D” 9Cr 1Mo Steel SM 9CR 75
SM 9CR 80 SM 9CR 95 Quenched and tempered 13Cr Steel Modified AISI 420 SM 13CR 75 SM 13CR 80 SM 13CR 95 Quenched and tempered Wet CO2 with a little H2S
Corrosion
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 phase Stainless 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 110 SM 2535 125 SM 2242 110 SM 2242 125 SM 2035 110 SM 2035 125 As cold drawn
Most Corrosive Environment Domain “G” 25Cr 50Ni 6Mo Steel
20Cr 58Ni 13Mo Steel
16Cr 54Ni 16Mo Steel
SM 2550 110 SM 2550 125 SM 2550 140 SM 2060 110*** SM 2060 125*** SM 2060 140*** SM 2060 155*** SM C276 110*** SM C276 125*** SM C276 140*** As cold drawn *** Environment with free Sulphur
A R P O
ENI
S.p.A.Agip Division
IDENTIFICATION CODE PAGE 27 OF 134
REVISION
STAP-P-1-M-6110 0
5.
MECHANICAL PROPERTIES OF STEEL
5.1. GENERALFailure 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. Buckling may 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 solid materials, some deformation may be sustained without permanent deformation, i.e. the material behaves elastically.
Beyond the elastic limit, the elastic deformation is accompanied by varying amounts of plastic, or permanent, deformation, If a material sustains large amounts of plastic deformation before final fracture. It is classed as ductile material, and if fracture occurs with little or no plastic 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 qualitatively characteristics of all the other types of tests.
The action of a material under the gradually increasing extension of the tension test is usually represented by plotting apparent stress (the total load divided by the original cross-sectional area of the test piece) as ordinates against the apparent strain (elongation between two gauge 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 by Hooke'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 (see above) the material will contract along a line generally nearly straight and parallel to the original elastic line, leaving a permanent set.
In steels, a curious phenomenon occurs after the elastic limit, known as yielding. This gives rise to a dip in the general curve followed by a period of deformation at approximately constant load. The maximum stress reached in this region is called the upper yield point and the lower part of the yielding region the lower yield point. In the harder and stronger steels, and under certain conditions of temperature, the yielding phenomenon is less prominent and is correspondingly harder to measure. In materials that do not exhibit a marked yield point, it is customary to define a yield strength. This is arbitrarily defined as the stress at which the material has a specified permanent set (the value of 0.2 percent is widely accepted in the industry).
For steels used in the manufacturing of tubular goods the API specifies the yield strength as the tensile strength required to produce a total elongation of 0.5 and 0.6 percent of the gauge length.
A R P O
ENI
S.p.A.Agip Division
IDENTIFICATION CODE PAGE 29 OF 134
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 by definition, it is customary to designate the end of the straight portion of the curve (by definition the 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 the curve, but at the same time the cross-sectional area of the specimen becomes less as it is drawn out. This loss of area weakens the specimen so that the curve reaches a maximum and then falls off until final fracture occurs. The stress at the maximum point is called the tensile strength (TS) or the ultimate strength of the material and is its most often quoted property.
The mechanical and chemical properties of casing, tubing and drill pipe are laid down in API specifications 5CT and 5C2.
Depending on the type or grade, minimum requirements are laid down for the mechanical properties, and in the case of the yield point even maximum requirements (except for H 40).
The denominations of the different grades are based on the minimum yield strength, e.g.:
Grade Min. Yield Strength
H 40 40,000psi
J 55 55,000psi
C 75 75,000psi
N 80 80,000psi
etc.
In the design of casing and tubing strings the minimum yield strength of the steel is taken as the basis of all strength calculations
As far as chemical properties are concerned, in API 5CT only the maximum phosphorus and sulphur contents are specified, the quality and the quantities of other alloying elements are left to the manufacturer.
API specification 5CT ‘Restricted yield strength casing and tubing’ however, specifies the complete 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 properties are strongly dependent on the chemical composition of the material and heat treatment applied. In the heat treatment process, the temperature reached and the rate of cooling are the essentials of obtaining the physical properties.
Comparison of the chemical composition shows that in general there is little difference between the various grades of steel and the difference in mechanical properties is achieved mainly through the variation heat treatment process.
Rapid cooling of the steel from above the crystallisation temperature by quenching provides a hard, 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 temperature and cooled very slowly, usually in the furnace. Annealing accomplishes the following:
• Refines grain structure.
• Makes structure more uniform.
• Improves machinability.
Normalising This is an identical process to annealing except that the steel is air cooled. As an example API grades J and K55 are heated to about 860°C (1,580°F) before cooling.
A R P O
ENI
S.p.A.Agip Division
IDENTIFICATION CODE PAGE 31 OF 134
REVISION
STAP-P-1-M-6110 0
Tempering Consists of re-heating a quenched or normalised steel to a specified temperature below the critical temperature, between 600°C and 680°C (1,110°F and 1,260°F) depending on the grade for a specific time and cooling back to room temperature. This process makes the steel tougher with only small loss in strength.
Stress relieving Is similar to the tempering process but is done to relieve internal 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 quenched steels are very hard and brittle.
See the following tables for process of manufacturing, heat treatments, chemical composition and mechanical properties of API tubulars.
Tempering Temperature Min.
Group Grade Type Process of
Manufacture Heat Treatment o F oC H 40 - S or EW None - -J 55 - S or EW None Note 1 - -1 K 55 - S or EW None Note 1 - -N 80 (Casing) - S or EW None Note 1 - -N 80 (Tubing) - S or EW Note 1 - -C 75 1 S or EW N&T 1,150 621 C 75 2 S or EW Q&T 1,150 621 C 75 3 S or EW N&T 1,150 621 C 75 9 Cr S Q&T* 1,100 593 C 75 18 Cr S Q&T* 1,100 593 2 C 90 1 S Q&T 1,150 621 C 90 2 S Q&T 1,150 621 C 95 - S or EW Q&T 1,000 538 L 80 1 S or EW Q&T 1,050 566 L 80 9 Cr S Q&T* 1,100 593 L 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 the manufacture’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 pipe
EW = Electric welded Pipe
A R P O
ENI
S.p.A.Agip Division
IDENTIFICATION CODE PAGE 33 OF 134
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 0.45 C - 75 2 ... 0.43 ... 1.50 ... ... ... ... ... ... 0.040 0.060 0.45 C - 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 1.0 C - 75 13Cr 0.15 0.22 0.25 1.00 ... ... 12.0 14.0 0.5 0.25 0.020 0.010 1.0 L - 80 1 ... 0.43* ... 1.90 ... ... ... ... 0.25 0.35 0.040 0.060 0.45 L - 80 9Cr ... 0.15 0.30 0.60 0.90 1.10 8.0 10.0 0.5 0.25 0.020 0.010 1.0 L - 80 13Cr 0.15 0.22 0.25 1.00 ... ... 12.0 14.0 0.5 0.25 0.020 0.010 1.0 C90 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.
Yield Strength Tensile Strength
Hardness Specified Wall
Thickness
Allowable Hardness Variation
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 22 237 C - 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 23 241 L - 80 9 Cr 80,000 552 95,000 655 95,000 655 23 241 L - 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 3.0 C - 90 90,000 620 105,000 724 100,000 690 25.4 255 0.501 to 0.749 4.0 C - 90 90,000 620 105,000 724 100,000 690 25.4 255 0.750 to 0.999 5.0 C - 90 90,000 620 105,000 724 100,000 690 25.4 255 1.000 and above 6.0 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 3.0 Q -125 125,000 860 150,000 1035 135,000 930 ... ... 0.501 to 0.749 4.0 Q -125 125,000 860 150,000 1035 135,000 930 ... ... 0.750 and above 5.0
* In case of dispute, laboratory Rockwell C hardness tests shall be used as the referee method.
ARPO
ENI
S.p.A.
Agip Division
IDENTIFICATION CODE PAGE 35 OF 134 REVISION STAP-P-1-M-6110 0 Figure 5 .B6.
TUBULAR RANGE LENGTHS & COLOUR CODING
6.1. RANGE LENGTHSThe 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 carload
Permissible Variation, max. 6 5 6
Permissible length, min 18 28 36
Tubing
** Total range length include 20-24 28-32
-* Range Length for 100% or more of carload
Permissible Variation, max. 2 2
-Permissible length, min 20 28
-Pup Joint
*** Lengths 2,3,4,6,8,10 and 12ft Tolerance ±3ins
* Carload tolerance shall not apply to orders of less than a carload. For any carload of pipe, shipped to 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 the individual carloads.
** By agreement between purchaser and manufacturer or processor the total range length for range 1 tubing may be 20-28ft
*** 2ft pup joints may be furnished up to 3ft long by agreement between purchaser and manufacturer, and lengths other than those listed may be furnished by agreement between purchaser and manufacturer.
A R P O
ENI
S.p.A.Agip Division
IDENTIFICATION CODE PAGE 37 OF 134
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 carload
Permissible Variation, max. 1.83 1.52 1.83
Permissible 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 carload
Permissible 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 3.66m Tolerance ±76.2mm
* Carload tolerance shall not apply to orders of less than a carload shipped from the manufacturer’s or processor’s facility. For any carload of pipe shipped from the manufacturer’s or processor’s facility to the final destination without transfers or removal from the car, the tolerance shall apply to each car. For any order consisting of more than a carload and shipped by rail, but not to the final destination in the rail cars loaded, the carload tolerance shall apply to the total order, but not to the individual carloads.
** By agreement between the purchaser and manufacturer or processor the total range length for range 1 tubing may be 6.10-8.53m
*** 0.61m pup joints may be furnished up to 0.91m long by agreement between purchaser and manufacturer, and lengths other than those may be furnished be agreement between purchaser and manufacturer.
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 the marking code.
A R P O
ENI
S.p.A.Agip Division
IDENTIFICATION CODE PAGE 39 OF 134
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 of casing 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 the coupling 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 be painted.
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) from the 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
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 threads shall be painted.
A R P O
ENI
S.p.A.Agip Division
IDENTIFICATION CODE PAGE 41 OF 134
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 to produce a pressure vessel which can withstand a variety of external, internal, thermal, and self 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 with a 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 a casing that is disproportionally strong in relation to the underlying formations, there are four major elements to the casing design process:
• Definition of the loading conditions likely to be encountered throughout the life of the 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 the buoyant weight of the casing below any point of interest will be a major component of the total axial stress.
Furthermore any changes in the internal and external pressures acting on casing will induce changes 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 occur due 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 a combination of Hooke's Law, ‘Lame's Equations’ and some form of yield criteria. This is referred to as ‘Triaxial Stress Analysis’.
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 some other effects.
The steps in the casing design process are:
1) Consider the loading factors for burst first, since burst will dictate the design for the major part of the string.
2) Next, the collapse loading should be evaluated and the string sections upgraded if necessary.
3) Once the weights, grades and section lengths have been determined to satisfy the burst 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 resistance caused by compression and tension loads, respectively. If these reductions show the strength of any part of the section to be less than the potential load, the section should again be upgraded.
7.2. DESIGN FACTOR (DF)
The design process can only be completed if knowledge of all the anticipated forces is available. This however, is idealistic and never actually occurs, therefore some determinations 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 factors applied.
A R P O
ENI
S.p.A.Agip Division
IDENTIFICATION CODE PAGE 43 OF 134
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 to withstand and the presence of any stress concentrations due to dynamic loads or specific well conditions.
• Reliability of listed properties of the various steels used in the industry and the uncertainty in the determination of the spread between ultimate strength and yield strength.
• Probability of the casing needing to bear the maximum load determined from the calculations.
• 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 and running equipment.
The company values selected for DFs are a compromise between safety margin and economics. The use of excessively high DFs guarantees against failure but provides excessive strength and, therefore, increased cost. The use of low DFs requires accurate knowledge 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 due to the assumptions used in calculations, whereas, production tubing has to bear pressures and tensions which are known or can be calculated with considerable accuracy.
Furthermore, casing is cemented in place after installation whereas tubing is often recovered and used again. As a consequence of this, and due to the fact that tubing has to combat corrosion effects from formation fluid, a higher DF is used for tubing than casing.
7.2.1. Company Design Factors
The following table gives the DF’s are Eni-Agip’s specified design factors used in casing design 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 to avoid exceeding the elastic limit and, therefore invalidating the criteria on which burst and collapse resistances are calculated.
A R P O
ENI
S.p.A.Agip Division
IDENTIFICATION CODE PAGE 45 OF 134
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 are only used to determine if the chosen casing is within the DF. The design factors are applied as follows:
Burst For the chosen casing (diameter, grade, weight and thread) take the lowest value from API casing tables, columns 13 through 19. This value then divided by the applied DF gives the internal pressure resistance of casing to be used for design calculation.
Collapse Use only column 11 of the API casing tables and divide the value by the DF to obtain the collapse resistance for design calculations.
Tension Use the lowest value from columns 20 through 27 of the API casing tables and divide it by the DF to obtain the joint strength for design calculations.
Note: It should be recognised that the Design Factor used in the context of casing string design is essentially different from the ‘Safety Factor’ used in many other engineering applications.
The term ‘Safety Factor’ as used in tubing design, implies that the actual physical properties and loading conditions are exactly known and that a specific margin is being allowed for safety. The loading conditions are not always precisely known in casing design, and therefore in 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 the loading applied.
