Casing/Tubing design manual october 2005 Chevron
Подождите немного. Документ загружается.
6
6 Tube Loads
6.1 Introduction ......................................................................................................................6-1
6.2 Tube Load Conditions......................................................................................................6-1
6.2.1 Pre-Installation Calculations........................................................................................6-1
6.2.2 Installation Calculations...............................................................................................6-2
6.2.3 Subsequent Load Conditions ......................................................................................6-2
6.3 Environmental Changes...................................................................................................6-3
6.3.1 Axial Load on Exposed Shoulders...............................................................................6-4
6.3.2 Temperature Change ..................................................................................................6-4
6.3.3 Pressure Change with Poisson’s Effect.......................................................................6-4
6.3.4 Helical Buckling...........................................................................................................6-5
6.4 Tube Load Definitions ......................................................................................................6-5
6.4.1 Initial Condition............................................................................................................6-5
6.4.2 Collapse Condition ......................................................................................................6-6
6.4.3 Burst Condition............................................................................................................6-6
6.4.4 Tension/Compression Condition..................................................................................6-6
6.4.5 Yield Condition ............................................................................................................6-7
6.4.6 Multiple Checks...........................................................................................................6-7
6.5 Integrity with Cement........................................................................................................6-7
6.6 Tube Basic Loads ............................................................................................................6-7
6.6.1 Production Tubing .......................................................................................................6-7
6.6.2 Production Casing.......................................................................................................6-9
6.6.3 Intermediate Casing ..................................................................................................6-12
6.7 Surface Casing...............................................................................................................6-13
6.7.1 Notes.........................................................................................................................6-15
6.8 References.....................................................................................................................6-15
6.1 Introduction
Tube design consists of a comparison of reasonable load scenarios to the
resistance of the tube. Chapters 3, 4, and 5 have reviewed the tube material,
performance of the tube, and tube connection. The purpose of this chapter is to
define typical casing and tubing load scenarios for the various applications.
6.2 Tube Load Conditions
The following are the loads recommended to check the integrity of a known
tubular string for its anticipated life history.
6.2.1 Pre-Installation Calculations
Before being set in cement or a packer, the tubular may undergo several load
conditions severe enough to warrant a separate check. Some load conditions are
listed below.
Casing/Tubing Design Manual 6-1
October 2005
• Running: The connection, in particular, should be checked for sufficient
capacity during the time the tubular is run into the wellbore. It is usually
sufficient to check each connection at the time it is uppermost in the
string (i.e. immediately following assembly). Severe local curvature,
however, may render lower sections of the wellbore more critical to joint
integrity.
In addition, if a tubular string is being floated into a hole, and particularly if
the tube outside diameter is large, check for external differential pressures
approaching the tube body collapse rating.
• Pressure Testing: Particularly with tubing work strings, but also to test
the cementing float equipment; it is common practice to impose an
internal pressure on an assembled tubular string before final installation.
Both joint strength and tube body yield should be checked. They should
be checked under the combined additional loads of internal differential
pressure and axial load induced by the internal differential pressure
acting on the lower end of the string.
6.2.2 Installation Calculations
A well-defined initial state should be established using the fluid, surface pressure,
and temperature environment in existence immediately prior to the instant the
tubular is fixed in the wellbore. It is this state to which all incremental loads
associated with changes to the fluid/pressure/temperature environment will be
added. Important variables defining the initial state include:
• Internal surface pressure and internal fluid densities and depths
• External surface pressure and external fluid densities and depths
• Temperature profile in the tube coincident with the pressure environment
• The type of end constraints at the top and bottom of the tubular string
It is possible for a tubular string to buckle under installation conditions. Check this
possibility so that future helically buckled configurations are properly modeled (in
increments) from this initial state.
Although landing practices, such as pull or slackoff, occur immediately following
installation, they are not part of the initial condition. Rather, the landing condition
should be considered an integral part of each and every subsequent load
condition.
6.2.3 Subsequent Load Conditions
A list of all significant subsequent states should be compiled. Important variables
defining these subsequent states include:
• Internal surface pressure and internal fluid densities and depths.
• External surface pressure and external fluid densities and depths.
• Temperature profile in the tube coincident with the pressure
environment.
6-2 Casing/Tubing Design Manual
October 2005
• Landing force. As this occurs immediately following installation, the
landing force is almost always the same for all subsequent load
conditions.
• Changes to the axial load, such as hanging weights of inner tubular
strings.
Following the application of these loads and calculation of the altered stress
state, the following integrity checks should be made:
• Collapse
• Burst
• Yield: Note that typically a multi-dimensional yield criterion includes the
conventional burst check. However, to maintain continuity with industry
practice, the burst integrity is reported separate from the body yield.
• Tension/joint strength
• Joint leak resistance
• Sulfide resistance versus the lowest temperature profile anticipated in
the life of the string
• Buckling
6.3 Environmental Changes
The act of cementing casing or, equivalently, setting a tubing packer, marks the
beginning of the life of a tubular string. To be sure, loads adversely affecting the
integrity of a tubular can occur during installation. For example, dynamic loads
during the final stages of a cementing operation when the plug is bumped, can
be particularly hazardous to large diameter, clearance connections.
Nevertheless, according to the philosophy of this text, the inception of the tubular
string coincides with the end of its installation.
Setting installation as the beginning of a tubular string’s life emphasizes the
importance of considering the effects of changes in the temperature, pressure,
and axial load environment on string integrity. Often the incremental loads
associated with these changes are sufficient to invalidate an otherwise safe
design. In this sense, there is actually no such thing as a single design load.
Each set of loads must be accompanied by an initial state, so that not only the
present load magnitudes, but also their values vis-à-vis the initial state are
properly considered.
Temperature and pressure changes are normally addressed in terms of their
effect on the axial force. However, in some important exceptional cases
1
, it may
be necessary to consider the effect of these changes in the radial and
circumferential directions. Fortunately, inasmuch as most tubular analysis is
elastic, such effects are readily superimposed on the results of the more
conventional axial displacement analysis.
1
For example, the pressure build up in a confined annulus that accompanies a
temperature increase.
Casing/Tubing Design Manual 6-3
October 2005
One acceptable means of measuring the relative impact of an environmental
change on the axial load is to consider the length change that would occur if only
one end of the tubular string were fixed in the axial direction. Consider a section
of a tubular string in a vertical wellbore over which the temperature and pressure
gradients and tube geometry are constant. The following length changes would
occur in any environment that differs from the initial state.
6.3.1 Axial Load on Exposed Shoulders
Typical exposed shoulders in a tubular string include:
• The locations of a change in either inner or outer diameter in a tapered
string.
• The bottom of a tubing string installed with a packer. Although an axial
force is generated at the bottom of a casing string during installation, an
incremental shoulder force does not usually exist at the cement top as
any loads at the bottom of a casing string are absorbed by the
intervening cement sheath.
Let
δ
F
z
be the incremental force caused by a change in the (primarily pressure)
environment at an exposed shoulder. Then, the length change induced by
δ
F
z
is,
E
A
LF
L
z
sh
δ
δ
=
, (6-1)
where
L
is the length of the section,
E
is Young’s modulus, and
A
is the cross-
sectional area of the tube.
6.3.2 Temperature Change
The axial length change associated with an average temperature change,
δ
T
ave
is,
(
)
δαδ
LLT
te ave
=
, (6-2)
where
α
is the coefficient of thermal expansion.
6.3.3 Pressure Change with Poisson’s Effect
Let and be the average changes in internal pressure and
external pressure, respectively, over a length of tube. Because of Poisson’s
effect, these pressure changes will induce a length change,
()
δ
p
i
ave
()
δ
p
o
ave
(
)
(
)
δ
µ
δδ
L
E
pr pr
rr
L
pr
i
ave
io
ave
o
oi
=−
−
−
2
22
22
, (6-3)
where
r
and
r
are the inner and outer radii of the tube, respectively, and
i o
µ
is
Poisson’s ratio. Because this length change is associated with radial
6-4 Casing/Tubing Design Manual
October 2005
expansion/contraction of the tube body, it is sometimes referred to as the
ballooning effect.
6.3.4 Helical Buckling
If the effective axial force, , at the bottom of a tube segment is negative,
F
e
(
FF pApA
ez iioo
=− − <0
)
, then the length change associated with helical
buckling is,
δ
L
rF
EIw
bu
ce
e
=−
22
8
, (6-4)
where
r
is the radial clearance between the tube and its confining hole,
c
I
is
moment of inertia, and
(
)
ww A A
esiioo
=+ −
γγ
is the effective weight of the tube
in its internal and external confining fluids whose weight densities are
γ
i
and
γ
o
, respectively. The above equation assumes that the distance to the neutral
point,
δ
z
F
w
n
e
e
=−
, is within the segment. If
δ
z
n
is greater than,
L
, the above
length change must be modified.
δδ
δδ
LL
L
z
L
z
bu bu
nn
'
=−
⎛
⎝
⎜
⎞
⎠
⎟
2 .(6-5)
The length change because of helical buckling is not so much a length change as
it is a displacement of the free end of the tube because the tube axis moves from
a straight to a helical configuration.
6.4 Tube Load Definitions
A load condition lists the pressures and temperatures constituting the
environment to which a tubular is subjected at a particular instant in its history. It
is important that the load condition definition refer to only a single point in time.
The pressure from one occurrence and temperature from another may present a
severe, conservative load definition. However, if there is no chance of those two
arrays existing simultaneously in the wellbore, subjecting the design string to
such loads is unreasonable.
The load condition names used below are arbitrary, and have been selected
merely to convey the type of load environment checked. Under any
nomenclature, however, every tubular string should be checked for excess
internal pressure, excess external pressure, and excess tension. With a few
exceptions to be noted later, an independent check of column stability should
also be performed.
6.4.1 Initial Condition
The initial condition defines those fluids/pressures/temperatures in the wellbore
at the time the tubular string is installed. For casing, the initial condition
Casing/Tubing Design Manual 6-5
October 2005
corresponds to having the cement in place but not set. Surface pressures used to
test or check equipment, but released before the cement/packer sets, should not
be included.
The initial condition has the primary function of setting the initial state for
subsequent history analysis. As such, the initial condition should be defined by
the conditions that exist immediately prior to the time the tubular is “fixed.”
6.4.2 Collapse Condition
Collapse fluids/pressures/temperatures should represent the worst external
pressure conditions to be expected during the life of the well. For surface and
intermediate casing, this condition usually corresponds to a condition of lost
circulation in which the internal fluid column may unexpectedly drop to reach
hydrostatic equilibrium with an exposed formation. In addition, surface casing
should also be checked for collapse during cement displacement (the initial
condition should define this case.)
For production casing and tubing, the worst collapse condition is usually
associated with near evacuation.
6.4.3 Burst Condition
The burst fluids/pressures/temperatures should represent the worst internal
pressure conditions to be expected during the life of the well. For surface and
intermediate casing, this condition usually corresponds to a gas kick.
For production casing, burst conditions are usually associated with a tubing leak,
resulting in tubing pressure, from production shut-in or stimulation treatment on
top of the completion fluid.
For tubing, burst conditions are associated with a shut in condition or, possibly, a
treatment such as hydraulic fracturing or acidizing.
6.4.4 Tension/Compression Condition
Running in hole (pre-installation) with an overpull of 10,000 pounds should
represent a basic tension-load condition. Tension load is calculated by using the
buoyant weight of the tubular. The pump cement-plug needs also to be checked
as it imposes an internal differential pressure acting on the lower end of the
string.
For production casing/liner, higher tension load under subsequent load
conditions (cold fracturing) may be produced and needs to be checked.
Axial compression load needs to be checked for special load conditions, such as
steam injection design, to control tube body compression yield and connection
integrity.
6-6 Casing/Tubing Design Manual
October 2005
6.4.5 Yield Condition
The burst fluids/pressures/temperatures should represent the worst yield
conditions to be expected during the life of the well. Yield condition under the
collapse fluids/pressures/temperatures should not be considered; as such yield is
less risky than tube collapse under the conditions.
6.4.6 Multiple Checks
It is often not obvious from an examination of the loads which of two competing
load conditions may be the most deleterious, for example, two different burst
scenarios. The only remedy for such situations is to test each of the load
conditions separately.
6.5 Integrity with Cement
In portions of a casing string opposite the cement, the beneficial effects of the
cement as a pressure seal should not be credited to the integrity of the string.
Cement placement may not proceed as planned, thus leaving the cement sheath
either wholly or partially absent. Further, even if the desired interval is covered, a
microannulus or subsequent cracking of the cement sheath may permit formation
fluids from contacting the casing outer surface.
6.6 Tube Basic Loads
In this section, the tube basic load condition is listed for tube design by the types
of tubes in on-land wells. It includes the internal and external pressures and
temperature for tube design on burst, collapse, tension/compression, and triaxial
yield. The initial condition is also listed for calculating the effect of load change on
tube design. More details on tube loads for design will be found in the next
chapter.
6.6.1 Production Tubing
Production tubing is any tubular string through which reservoir fluids are
conveyed to the surface. If reservoir fluid production occurs in the annulus
between two tubular strings, both tubular strings are considered production
tubing for the purpose of design load definition.
Table 6-1. Production Tubing Basic Load
Load
Condition
Internal Fluids/
Pressures
External
Fluids/
Pressures
Axial Load Temperature
Profile
Initial Surface: 0
Fluids:
Completion
fluid
Surface: 0
Fluids:
Completion
fluid
Initial axial load Undisturbed
geothermal
Collapse Surface: 0
Fluids:
Surface: 0
Fluids:
Completion
Initial axial load
plus load
Undisturbed
geothermal
Casing/Tubing Design Manual 6-7
October 2005
Load
Condition
Internal Fluids/
Pressures
External
Fluids/
Pressures
Axial Load Temperature
Profile
Evacuated fluid change
Burst Surface:
Production
shut-in
pressure
Fluids:
Methane
Surface: 0
Fluids:
Completion
fluid
Initial axial load
plus load
change
Production
temperature
Tension Surface: 0
Fluids: packer
fluid
Surface: 0
Fluids: packer
fluid
Tubing buoyant
weight with
10,000 lb
overpull
Undisturbed
geothermal
Stability Surface:
Reservoir
pressure at
perforations,
less methane
gradient to
surface
Fluids:
Methane
Surface: 0
Fluids:
Completion
fluid
Initial axial load
plus load
change
Production
temperature
The load definitions for production tubing are intended to represent the following:
• Collapse: Possible completion with nitrogen or, alternately, the actual
pressure interior to the tubing late in the life of the reservoir
• Burst: Well shut-in early in the life of the reservoir
• Tension: Workover tension is calculated using the buoyant weight of
the string plus overpull of 10,000 lb
• Stability: Nominal production. In lieu of actually performing a multi-
phase flow analysis of reservoir fluid production, the flowing conditions
are taken conservatively to be identical to shut-in conditions.
6-8 Casing/Tubing Design Manual
October 2005
Figure 6-1. Production Tubing Basic Load
6.6.2 Production Casing
The tubular string that encloses the production tubing is the production casing
string. In case of annular reservoir fluid production, the next outer casing string
not contributing to the annulus is considered the production casing for the
purpose of design load definition.
Table 6-2. Production Casing Basic Load
Load
Condition
Internal
Fluids/
Pressures
External
Fluids/
Pressures
Axial Load Temperature
Profile
Initial Surface: 0
Fluids: Mud
density at
casing point
Surface: 0
Fluids: Mud
density to
cement top,
cement to
casing point
Initial axial load Undisturbed
geothermal
Collapse Surface: 0
Fluids:
Evacuated
Surface: 0
Fluids: Mud
density at
casing point
Initial axial load
plus load
change
Undisturbed
geothermal
Burst Surface:
Maximum of
(1) reservoir
pressure at
perforations,
less methane
gradient to
Surface: 0
Fluids: Pore
pressure
Initial axial load
plus load
change
Flowing
temperature
Casing/Tubing Design Manual 6-9
October 2005
Load
Condition
Internal
Fluids/
Pressures
External
Fluids/
Pressures
Axial Load Temperature
Profile
surface, (2)
surface treating
pressure or (3)
kill surface
pressure
Fluids:
completion
fluid
Tension Surface: 0
Fluids: Mud
density at
casing point
Surface: 0
Fluids: Mud
density at
casing point
Casing
buoyant weight
plus 10,000 lb
overpull
Undisturbed
geothermal
gradient
Stability Surface:
Maximum of
(1) reservoir
pressure at
perforations,
less methane
gradient to
surface, (2)
surface treating
pressure or (3)
kill surface
pressure
Fluids:
completion
fluid
Surface: 0
Fluids: Pore
pressure
Initial axial load
plus load
change
Flowing
temperature
6-10 Casing/Tubing Design Manual
October 2005