-
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
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) 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
ENI S.p.A.Agip Division
IDENTIFICATION CODE PAGE 4 OF 134
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
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 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
ENI S.p.A.Agip Division
IDENTIFICATION CODE PAGE 6 OF 134
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
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 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
ENI S.p.A.Agip Division
IDENTIFICATION CODE PAGE 8 OF 134
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
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 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
ENI S.p.A.Agip Division
IDENTIFICATION CODE PAGE 10 OF 134
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
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 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
ENI S.p.A.Agip Division
IDENTIFICATION CODE PAGE 12 OF 134
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
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 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
ENI S.p.A.Agip Division
IDENTIFICATION CODE PAGE 14 OF 134
REVISION
STAP-P-1-M-6110 0
Figure 3.B - Example Casing Seat Selection(for a typical
geopressurised well using a pressure profile).
-
ARPO
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 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
ENI S.p.A.Agip Division
IDENTIFICATION CODE PAGE 16 OF 134
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
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 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
ENI S.p.A.Agip Division
IDENTIFICATION CODE PAGE 18 OF 134
REVISION
STAP-P-1-M-6110 0
Figure 3.C - Casing and Bit Selection Chart
-
ARPO
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 drillingprogramme options.
To use the chart:
1) Determine the casing or liner size for the last size pipe to
be installed.2) Enter the chart at that point.3) The flow of the
chart then indicates hole sizes that may be required to set that
size pipe
(i.e., 5 Liner inside 6 or 61/2 hole).Solid lines indicate
commonly used bits for that size pipe and can be considered tohave
adequate clearance to run and cement the casing or liner (i.e.,
51/2 Casing inside77/8 hole).
The broken lines indicate less common optional hole sizes used
(i.e., 5 inside 61/8hole, etc.).
The selection of one of these broken paths requires special
attention be given to theconnection, mud weight, cementing and
doglegs.
Large connection ODs, thick mud cake build-up, problem cementing
areas (high waterloss, lost returns, etc.) and doglegs all
aggravate the attempt to run casing and liners inlow clearance
situations.
Once the hole size has been selected. a casing large enough to
allow passage of a bitto make that hole can be selected. The solid
lines are commonly required casing sizes.encompassing most weights
(i.e., 61/2 bit inside 75/8 casing).The broken lines indicate
casing sizes where only the lighter weights can be used(i.e. 61/8
inside 7 casing).
This selection process is repeated until the anticipated number
of casing sizes hasbeen reached.
Note: Some drilling programmes can require special tools and
operations toobtain the wellbore size for the casing to be
installed. An underreamer isa drilling tool, used to enlarge
section of hole below a restriction(situations where equipment,
such as BOP or wellhead size restrictions,limit the tool entry
size).
figure 3.d shows the standard casing programme and figure 3.e
the possible alternative.further standard casing and hole sizes
information is shown in table 3.a.
-
ARPO
ENI S.p.A.Agip Division
IDENTIFICATION CODE PAGE 20 OF 134
REVISION
STAP-P-1-M-6110 0
Figure 3.D - Standard Casing Programme
Figure 3.E - Alternative Casing Programme
-
ARPO
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 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
ENI S.p.A.Agip Division
IDENTIFICATION CODE PAGE 22 OF 134
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
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 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
ENI S.p.A.Agip Division
IDENTIFICATION CODE PAGE 24 OF 134
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
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. 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
ENI S.p.A.Agip Division
IDENTIFICATION CODE PAGE 26 OF 134
REVISION
STAP-P-1-M-6110 0
Application (Refer tofigure 4.a)
Domain Material SMDesignation
Notes
Mild Environment Domain A API J 55N 80P 110(Q 125)
SM 95GSM 125G
Sulphide Stress CorrosionCracking (medium pressureand
temperature)
Domain B Cr or Cr-Mo Steel
API L 80C 90T 95
SM 80SSM 90SSM 95S
Sulphide Stress CorrosionCracking (high pressure
andtemperature)
Domain C 1Cr 0.5Mo SteelModified AISI 4130
SM 85SSSM 90SSSM C100SM C110
Higher yieldstrength for sourservice
Wet CO2 Corrosion Domain D 9Cr 1Mo Steel SM 9CR 75SM 9CR 80SM
9CR 95
Quenched andtempered
13Cr SteelModified AISI 420
SM 13CR 75SM 13CR 80SM 13CR 95
Quenched andtempered
Wet CO2 with a little H2SCorrosion
Domain E 22Cr 5Ni 3Mo Steel
25Cr 6Ni 3Mo Steel
SM 22CR 65*SM 22CR 110**SM 22CR 125**SM 25CR 75*SM 25CR 110**SM
25CR 125**SM 25CR 140**
Duplex phaseStainless steels
* Solution Treated
** Cold drawn
Wet CO2 with H2S Corrosion Domain F 25Cr 35Ni 3Mo Steel
22Cr 42Ni 3Mo Steel
20Cr 35Ni 5Mo Steel
SM 2535 110SM 2535 125SM 2242 110SM 2242 125SM 2035 110SM 2035
125
As cold drawn
Most Corrosive Environment Domain G 25Cr 50Ni 6Mo Steel
20Cr 58Ni 13Mo Steel
16Cr 54Ni 16Mo Steel
SM 2550 110SM 2550 125SM 2550 140SM 2060 110***SM 2060 125***SM
2060 140***SM 2060 155***SM C276 110***SM C276 125***SM C276
140***
As cold drawn
*** Environmentwith freeSulphur
-
ARPO
ENI S.p.A.Agip Division
IDENTIFICATION CODE PAGE 27 OF 134
REVISION
STAP-P-1-M-6110 0
Table 4.B - Example Non-API Steel Grades
-
ARPO
ENI S.p.A.Agip Division
IDENTIFICATION CODE PAGE 28 OF 134
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
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 bydefinition, it is
customary to designate the end of the straight portion of the curve
(by definitionthe proportional limit) as the elastic limit. Careful
practice qualifies this by designating it theproportional elastic
limit.
As extension continues beyond yielding, the material becomes
stronger causing a rise of thecurve, but at the same time the
cross-sectional area of the specimen becomes less as it isdrawn
out. This loss of area weakens the specimen so that the curve
reaches a maximumand then falls off until final fracture occurs.
The stress at the maximum point is called thetensile strength (TS)
or the ultimate strength of the material and is its most often
quotedproperty.
The mechanical and chemical properties of casing, tubing and
drill pipe are laid down in APIspecifications 5CT and 5C2.
Depending on the type or grade, minimum requirements are laid
down for the mechanicalproperties, and in the case of the yield
point even maximum requirements (except for H 40).
-
ARPO
ENI S.p.A.Agip Division
IDENTIFICATION CODE PAGE 30 OF 134
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 860C (1,580F) before cooling.
-
ARPO
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 aspecified temperature below the critical temperature,
between600C and 680C (1,110F and 1,260F) depending on thegrade for
a specific time and cooling back to room temperature.This process
makes the steel tougher with only small loss instrength.
Stress relieving Is similar to the tempering process but is done
to relieveinternal stresses set up during the manufacturing
process(such as in upsetting).
Quenching Is the same procedure as normalising but has rapid
cooling,usually done in water, salt water or oil. un-tempered
quenchedsteels are very hard and brittle.
See the following tables for process of manufacturing, heat
treatments, chemical compositionand mechanical properties of API
tubulars.
-
ARPO
ENI S.p.A.Agip Division
IDENTIFICATION CODE PAGE 32 OF 134
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 themanufactures option or if so
specified on the order.Type 9 Cr and 13Cr grades may be air
quenched** Unless otherwise agreed between purchaser and
manufacturer/processor*** Special requirements unique to electric
welded Q 125 casing are specified in SR11. When
welded Q 125 casing is furnished, the provisions of SR11
automatically in effect.S = Seamless pipeEW = Electric welded
Pipe
Table 5.A - API Process of Manufacture and Heat Treatment
-
ARPO
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 0.45C - 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
ENI S.p.A.Agip Division
IDENTIFICATION CODE PAGE 34 OF 134
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
ENI S.p.A.Agip Division
IDENTIFICATION CODE PAGE 36 OF 134
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 manufacturers facility by rail.but not to the
final destination, the carload tolerance shall apply to the total
order, but not to theindividual carloads.** By agreement between
purchaser and manufacturer or processor the total range length for
range1 tubing may be 20-28ft*** 2ft pup joints may be furnished up
to 3ft long by agreement between purchaser andmanufacturer, and
lengths other than those listed may be furnished by agreement
betweenpurchaser and manufacturer.
Table 6.A - API Range Length In Feet
-
ARPO
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 carloadPermissible Variation, max.
1.83 1.52 1.83Permissible length, min 5.49 8.53 10.97
Tubing
** Total range length include 6.10-7.32 8.53-9.75 -* Range
Length for 100% or more of carloadPermissible Variation, max. 0.61
0.61 -Permissible length, min 6.10 8.53 -
Pup Joint
*** Lengths 0.61, 0.19, 1.22, 1.83, 2.44, 3.05 and
3.66mTolerance 76.2mm
* Carload tolerance shall not apply to orders of less than a
carload shipped from the manufacturersor processors facility. For
any carload of pipe shipped from the manufacturers or
processorsfacility to the final destination without transfers or
removal from the car, the tolerance shall apply toeach car. For any
order consisting of more than a carload and shipped by rail, but
not to the finaldestination in the rail cars loaded, the carload
tolerance shall apply to the total order, but not to theindividual
carloads.** By agreement between the purchaser and manufacturer or
processor the total range length forrange 1 tubing may be
6.10-8.53m*** 0.61m pup joints may be furnished up to 0.91m long by
agreement between purchaser andmanufacturer, and lengths other than
those may be furnished be agreement between purchaser
andmanufacturer.
Table 6.B - API Range Length in Metres
-
ARPO
ENI S.p.A.Agip Division
IDENTIFICATION CODE PAGE 38 OF 134
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
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 ofcasing and tubing shall be colour
coded by one or more of the following methods.
A paint band encircling the pipe at a distance not greater than
2ft (0.61m) from thecoupling or box.
A paint band encircling the centre of the coupling. Paint entire
outside surface of coupling.
For pup joints shorter than 6ft (1.83m) in length, the entire
surface except the threads shall bepainted.
The colour and number of bands shall be as follows:
Grade H 40 No colour marking, or black at the manufacturers
option
Grade J 55 One bright green band
Grade K 55 Two bright green bands
Grade N 80 One red band
Grade P 105 White
Grade P 110 White
Grade Q 125 Orange
Group 2
1) A paint band or bands encircling the pipe at a distance not
greater than 2ft (0,61m) fromthe coupling or box.
Grade C75 One blue band
Grace C75, 9Cr One blue band and two yellow bands
Grade C75, 13Cr One blue and one yellow band
Grade L80 One red band and one brown band
Grade L80, 9Cr One red and one brown and two yellow bands
Grade L80, 13Cr. One red and one brown and one yellow band
Grade C90 One purple band
Grade C95 One brown band
-
ARPO
ENI S.p.A.Agip Division
IDENTIFICATION CODE PAGE 40 OF 134
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
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 toproduce a pressure vessel which can
withstand a variety of external, internal, thermal, andself weight
loading, while at the same time being subjected to wear and
corrosion.
During the drilling phase, this pressure vessel is a composite
of steel and in conjunction witha variety of biaxially stressed
rock materials.
As there is little point in designing for loads that are not
encountered in the field, or in having acasing that is
disproportionally strong in relation to the underlying formations,
there are fourmajor elements to the casing design process:
Definition of the loading conditions likely to be encountered
throughout the life ofthe well.
Specification of the mechanical strength of the pipe. Estimation
of the formation strength using rock and soil mechanics. Estimation
of the extent to which the pipe will deteriorate through time
and
quantification of the impact that this will have on its
strength.
Considering the axial stress (sa) in a string of casing, it is
obvious that the stress due to thebuoyant weight of the casing
below any point of interest will be a major component of the
totalaxial stress.
Furthermore any changes in the internal and external pressures
acting on casing will inducechanges in the axial stress as well as
the radial (sr) and tangential (st) stresses.
In addition, since the pipe is held or fixed at both ends,
changes in all three stresses will occurdue to temperature changes
and from the occurrence, and degree, of any buckling effect.
The inter-relationship between these loads can be analysed
manually by applying acombination of Hooke's Law, Lame's Equations
and some form of yield criteria. This isreferred to as Triaxial
Stress Analysis.
The forces affecting casing design are outlined in section
7.1.
-
ARPO
ENI S.p.A.Agip Division
IDENTIFICATION CODE PAGE 42 OF 134
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
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 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
ENI S.p.A.Agip Division
IDENTIFICATION CODE PAGE 44 OF 134
REVISION
STAP-P-1-M-6110 0
7.2.1. Company Design Factors
The following table gives the DFs are Eni-Agips specified design
factors used in casingdesign calculations:
Casing Grade Burst Collapse Tension
H 40 1.05 1.10 1.7
J 55 1.05 1.10 1.7
K 55 1.05 1.10 1.7
C 75 1.10 1.10 1.7
L 80 1.10 1.10 1.7
N 80 1.10 1.10 1.7
C 90 1.10 1.10 1.7
C 95 1.10 1.10 1.7
P 110 1.10 1.10 1.8
Q 125 1.20 1.10 1.8
Table 7.A - Eni-Agip Design Factors
Note: The tensile DF on grade C 95 and below is 1.7, and higher
than C 95 is 1.8.
Note: The tensile DF must be considerably higher than the
previous factors toavoid exceeding the elastic limit and, therefore
invalidating the criteriaon which burst and collapse resistances
are calculated.
-
ARPO
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 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
ENI S.p.A.Agip Division
IDENTIFICATION CODE PAGE 46 OF 134
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
ENI S.p.A.Agip Division
IDENTIFICATION CODE PAGE 47 OF 134
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
ENI S.p.A.Agip Division
IDENTIFICATION CODE PAGE 48 OF 134
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
a) Internal Pressure
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.
b) External 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
ENI S.p.A.Agip Division
IDENTIFICATION CODE PAGE 49 OF 134
REVISION
STAP-P-1-M-6110 0
a) Internal Pressure
1) The wellhead burst limit is obtained as the difference
between the pore pressureof the reservoir fluid and the hydrostatic
pressure produced by a colum of fluidwhich is usually gas (density
= 0.3kg/dm3).
2) Actual gas/oil gradients can be used if information on these
are known andavailable.
3) The bottom-hole pressure burst limit is obtained by adding
the wellhead pressureburst limit to the annulus hydrostatic
pressure exerted by the completion fluid.Generally the completion
fluid density is equal to, or close to, the mud weight inwhich
casing is installed.
Note: It is usually assumed that the completion fluid and mud on
the outside ofthe casing remains homogeneous and retains the
original density valueshowever this is not actually the case,
particularly with heavy fluids, but it isalso assumed that the two
fluids will degrade similarly under the sameconditions of pressure
and temperature.
4) Connect the wellhead and bottomhole burst pressure limits
with a straight line toobtain the maximum internal burst
pressures.
Note: If it is foreseen that future stimulation or hydraulic
fracturing operationsmay be necessary, assume: at the perforation
depth the fracture pressureat that point and at the wellhead the
fracture pressure at the perforationdepth minus the hydrostatic
head in the casing plus a safety margin of70kg/cm2 (1,000psi).
b) External Pressure
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
ENI S.p.A.Agip Division
IDENTIFICATION CODE PAGE 50 OF 134
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.
8.2.1. Company Design Procedure
The design of a string of casing in collapse mode consists of
selecting the lowest cost pipethat has sufficient strength to meet
with the desired design criteria and design factor.
If, when making a selection, a choice exists between a lower
grade heavy pipe and a highergrade but lighter pipe, both of which
provide adequate strength at similar cost, the highergrade
(lighter) pipe should be chosen due to the reduction of tension
loading.
Note : The reduced collapse resistance under biaxial stress
(tension/collapse)should be considered.
Note : No allowance is given to increased collapse resistance
due to cementing.
-
ARPO
ENI S.p.A.Agip Division
IDENTIFICATION CODE PAGE 51 OF 134
REVISION
STAP-P-1-M-6110 0
Surface Casing
a) Internal Pressure
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.
b) External Pressure
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
a) Internal Pressure
The worst case collapse loading occurs when a loss of
circulation is encountered whiledrilling the next hole section with
the maximum allowable mud weight. This results in themud level
inside the casing dropping to an equilibrium level where the mud
hydrostaticequals the pore pressure of the thief zone. Consequently
it will be assumed the casingis empty to the height (H) calculated
as follows:
(Hloss-H) x dm = H loss x GpH = H loss (dm - Gp)/dm
If Gp = 1.03 (kg/cm2/10m)
Then H = H loss (dm - 1.03)/dm
where:
Hloss = depth at which circulation loss is expected (m)
dm = mud density expected at Hloss (kg/dm2)
Gp = pore pressure of thief zone (kg/cm2/10m) - usually normally
pressuredwith 1.03 as gradient.
-
ARPO
ENI S.p.A.Agip Division
IDENTIFICATION CODE PAGE 52 OF 134
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.
b) External Pressure
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.
c) Net Collapse Pressure
The effective collapse line is obtained by subtracting the
internal pressure from externalat each depth.
-
ARPO
ENI S.p.A.Agip Division
IDENTIFICATION CODE PAGE 53 OF 134
REVISION
STAP-P-1-M-6110 0
Production Casing
a) Internal Pressure
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.
b) External Pressure
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.
c) Net Collapse Pressure
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
ENI S.p.A.Agip Division
IDENTIFICATION CODE PAGE 54 OF 134
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
ENI S.p.A.Agip Division
IDENTIFICATION CODE PAGE 55 OF 134
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
ENI S.p.A.Agip Division
IDENTIFICATION CODE PAGE 56 OF 134
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