Casing (2) casing setting depth casing string

Casing Design
Theory and Practice
Dr. Ibrahim Salahudin Mohamed
Upstream Oil and Gas Business Consultant

Casing Design Philosophy
In practice, it would be much cheaper to drill a single
size hole to total depth (TD), probably with a small
diameter drill bit, and then to case the hole from the
surface to the TD.
Do you agree on that?

Two wells have the same
total depth, but with two
different casing setting
depths and profiles
Why?

FUNDAMENTAL ASPECTS OF CASING
At a certain stage during the
drilling of oil and gas wells, it
becomes necessary to line the
walls of a borehole with steel
pipe which is called casing.

Typical Casing Strings
ØConductor Casing
ØSurface Casing
ØIntermediate casing (Protective)
ØProduction Casing
ØLiner

Drive or Conductor
Ø Conductor pipe is run from
the surface to some
shallow depth, typically, 20
to 300 feet deep )
Ø May be drilled, hammered,
or jetted.

Drive or Conductor
Ø Conductor pipe is used to:
ü Hold back the unconsolidated surface formations and
prevent them from falling into the hole
ü To protect near-surface unconsolidated formations from washout.
ü Supports weight of other casing strings.
ü Provide a circuit for the drilling mud to elevated mud tanks
ü Provides protection against shallow gas flows by installing the
diverter system.

Surface Casing
ØThe surface casing is run after the conductor casing
ØThe surface casing is used to :
ü Protect fresh water from contamination from drilling fluids
ü The surface casing also serves to provide protection against shallow
blowouts as drilling progresses, hence BOPs are connected to the top of
this string
ü Support the weight of subsequent casing strings
ü Prevent caving of weak formations that are encountered at shallow
depths

Surface Casing
ØThis casing should be set in
competent rocks such as hard
limestone.
ØThis will ensure that the
formations at the casing shoe will
not fracture at high hydrostatic
pressures which may be used later.

Intermediate Casing (Protective Casing)
ØThe main reason for setting intermediate casing is to case off
the formations that prevent the well from being drilled to the
total depth.
Ø Troublesome zones encountered include those with:
ü Abnormal formation pressures,
ü lost circulation,
ü Unstable and sloughing shales and
ü Salt sections.

Production Casing
ØProduction string represents the last casing string.
Ø It is run to:
ü Isolate producing zones.
ü Permit selective production in multizone production
ü Acts as the conduit or a host for production fluid tubing (The
production tubing fits inside the production string)
ü To provide reservoir fluid control and protecting the
environment in the event of failure of the tubing string
during production operations

Production Casing
ØSize is highly dependent on
ü Production tubing size
ü Completion equipment
ü Artificial lift constraints

Liner
Ø Liners are the pipes that do not
usually reach the surface but are
suspended from the bottom of
the next largest casing string.
Ø Usually, they are set to :
Ø Seal off troublesome sections of
the well
Ø Through the producing zones for
economic reasons.
In liner completions, both the liner and the
intermediate casing act as the production string.

Types of liner
ØDrilling liners :
Used to isolate lost circulation or abnormally pressured zones to permit
deeper drilling.
ØProduction liners:
Run instead of a full casing to provide isolation across the producing or
injection zones.

Types of liner
ØThe scab liner
üA section of casing that does not reach the surface. It is used to repair existing
damaged casing.
üIt is normally sealed with packers at top and bottom and in some cases is also
cemented
ØThe tie-back liner:
A section of casing extending upwards from the top of an existing liner to the
surface or well head.
ØThe scab tie-back liner
A section of casing extending from the top of an existing liner but does not reach
the surface.

Liner casing
ØNeeds an overlap with previous
string of 300 to 500 feet
Ø Liners are hung on the previous
casing, by use of a suitable
arrangement of a packer and
slips called a liner hanger.

Principles of Casing Design
Casing
Setting Depth
Casing Size Casing Grade

Casing Setting Depth
When we make a determination of the setting depths for the various
casing strings in our well, there are several parameters that we must
consider:
ü Experience in an area
ü Pore pressure (formation fluid pressure)
ü Fracture pressure
ü Borehole stability problems
ü Corrosive zones
ü Environmental considerations and Government Regulations
ü Company policy

The experience parameter
Ø Successful experience in an area with previous wells is the most
reliable of all
Ø It should never be skipped out of hand in order to try something
else thought to be more “technologically advanced” or more “cost
effective.”
Ø The most important question is “ Why such profile is successful?”
Ø Too often, blind use of such experience without understanding, can
result in something going wrong when least expected.
Ø In brief, you should understand why such profile is successful.

Pressure Terms Definition
ØSome important terms should be understood first:
ØPore Pressure or Formation Pressure
ØFracture Pressure
ØOverburden Pressure
ØNormal Pressure
ØAbnormal Pressure
ØSubnormal Pressure

Pore Pressure- Formation Pressure
ØThe magnitude of the pressure in the pores of a formation.
Ø If the pore throats through the sediment are interconnecting all the
way to surface, the pressure of the fluid at any depth in the sediment
will be same.
ØThe pressure in the fluid in the pores of the sediment will only be
dependent on the density of the fluid in the pore space and the depth
of the pressure measurement
ØIt will be independent of the pore size or pore throat geometry

Pressure Calculations
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144
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Normal (Hydrostatic) Pore Pressure Gradient
Ø Most of the fluids found in the pore space of sedimentary
formations contain a proportion of salt and are known as brines.
Ø The dissolved salt content may vary from 0 to over 200,000 ppm.
Ø Correspondingly, the pore pressure gradient ranges from 0.433
psi/ft (pure water) to about 0.50 psi/ft.
Ø In most geographical areas, the pore pressure gradient is
approximately 0.465 psi/ft (assumes 80,000 ppm salt content).

Overburden Pressure- Geostatic Pressure
Ø The vertical pressure at any point in the earth is known as the
overburden pressure or geostatic pressure.
Ø The overburden pressure at any point is a function of the mass of
rock and fluid above the point of interest.
Ø In order to calculate the overburden pressure at any point, the
average density of the material (rock and fluids) above the point of
interest must be determined.

Overburden Pressure- Geostatic Pressure
Ø Since the matrix material (rock type), porosity, and fluid content vary
with depth, the bulk density will also vary with depth.
Ø The overburden pressure at any point is therefore the integral of the
bulk density from surface down to the point of interest.
Ø On average, it is assumed that the maximum bulk density
encountered is around 2.3 g/cc. this would result in overburden
gradient of 1 psi/ft

Abnormal Pressure Vs. Subnormal Pressure
If the pore pressure is higher
than the normal pressure
(0.465 psi/ft)
Abnormal Pressure or
Over-Pressured
If the pore pressure is less
than the normal pressure
(0.465 psi/ft)
Sub normal or under-
Pressured Zone

Abnormal Pressure Mechanism
ØIf the overburden is increased (e.g. due to more sediments being laid
down) the extra load must be borne by the matrix and the pore fluid.
ØIf the fluid is prevented from leaving the pore space the fluid
pressure must increase above the hydrostatic value.
ØSuch a formation can be described as over-pressured i.e. part of the
overburden stress is being supported by the fluid in the pore space
and not the matrix.
ØSince the water is effectively incompressible the overburden is almost
totally supported by the pore fluid and the grain-to-grain contact
stress is not increased.

In a formation where the fluids are free to move (drainage path open), the increased
load must be taken by the matrix, while the fluid pressure remains constant. Under such
circumstances the pore pressure can be described as Normal, and is proportional to
depth and fluid density

Abnormal Pressure Conditions
ØIn order for abnormal pressures to exist the pressure in the pores of a rock
must be sealed in place i.e. the pores are not interconnecting.
ØThe seal prevents equalization of the pressures which occur within the
geological sequence.
ØThe seal is formed by a permeability barrier resulting from physical or
chemical action.
ØA physical seal may be formed by gravity faulting during deposition or the
deposition of a fine-grained material (shale)
ØThe chemical seal may be due to calcium carbonate being deposited, thus
restricting permeability.

TRANSITION ZONE
Ø It can be seen that the pore pressures in the shallower formations are
“normal”. That is that they correspond to a hydrostatic fluid gradient.
Ø There is then an increase in pressure with depth until the “over-pressured”
formation is entered.
Ø The zone between the normally pressured zone and the over-pressured
zone is known as the transition zone
Ø The pressures in both the transition and over-pressured zone is quite
clearly above the hydrostatic pressure gradient line.
Ø The transition zone is therefore the seal or caprock on the over-pressured
formation

Formation Fracture Pressure
ØFormation fracture pressure is the pressure at which the formation
will frac.
ØThe well operations can then be designed such that the pressures in
the borehole will always lie between the formation pore pressure and
the fracture pressure.
ØIf the pressure in the borehole falls below the pore pressure then an
influx of formation fluids into the wellbore may occur.
ØIf the pressure in the borehole exceeds the fracture pressure then the
formations will fracture and losses of drilling fluid will occur

Fracture Mechanism
ØThe stress within a rock can be resolved into
three principal stresses
ØA formation will fracture when the pressure
in the borehole exceeds the least of the
stresses within the rock structure.
ØNormally, these fractures will propagate in a
direction perpendicular to the least principal
stress

The Leak-Off Test- Formation Integrity test FIT
ØIn practice, formation fracture pressures or, as they are commonly
called, formation breakdown pressures are determined in leak-off
tests.
ØThese tests are normally performed at the start of each new hole
section, just after drilling out of a casing shoe of the previous hole
section.

Leak off Test
ØThe procedure is as follows:
1. Drill to 5 - 10 ft below the casing shoe
2. Close the BOPs at surface
3. Raise the surface pressure in increments and record the volume
pumped and the pressure in the system at each volume increment (4.
4. Stop pumping when the pressure in the well does not increase linearly
for an increase in the volume of fluid pumped into the well
The operation is generally stopped at the first point which deviates from the
straight line portion of the plot

Maximum Mud Weight
ØGiven the leak-off test pressure just below the casing shoe, the maximum
mud weight that can be used at that depth, and below can be calculated
from
ØUsually, a safety factor of o.5 ppg (0.026 psi/ft) is subtracted from the
allowable mud-weight.

Quiz
While performing a leak off test the surface pressure bled off at 940 psi.
The casing shoe was at a true vertical depth of 5010 ft and a mud
weight of 10.2 ppg was used to conduct the test.
What is the maximum mud weight that can be used during drilling the
subsequent section

Calculating the Fracture Pressure of a
Formation
Ø The leak-off test pressure described above can only be determined
after the formations to be considered have been penetrated.
Ø It is however necessary, in order to ensure a safe operation and to
optimize the design of the well, to have an estimate of the fracture
pressure of the formations to be drilled before the drilling operation
has been commenced.
Ø In practice the fracture pressure of the formations are estimated
from leak-off tests on nearby (offset) wells.

Estimating of Fracture Pressure
ØWhen planning exploration or wildcat wells, where there is little or
no reliable offset well data, the fracture gradient can be estimated
using various predictive techniques.
Ø It is usually assumed that the fracture gradient at the casing shoe is
the lowest within the open hole section.
ØFracture gradient estimates made whilst drilling are normally the
responsibility of the mud logging contractor.

Hubbert and Willis method
ØAccording to the Hubbert and Willis method, the total injection (or
fracturing) pressure, FP, required to keep open and extend a fracture
is given by:

Eaton method
ØThe Eaton method is the most widely used in the oil industry.
For sedimentary rocks, the Passion's
ratio is assumed to be 0.4 unless it is
measured

Casing Setting Depth - Conductor
ØConductor casing may require the
drilling of a hole in the ground and
cementing in place or it may be driven
into the ground with a diesel pile-
driving hammer.
ØOn the simple side, we want the
conductor deep enough to prevent
washing out under the rig or platform
while drilling the surface hole

Casing Setting Depth - Conductor
Ø For many shallow wells with hard surface soils the conductor may
be set at depths of 50 ft or so, sometimes 100 ft.
Ø On the other hand, in areas where the surface soils (or ocean
bottom) are extremely soft it may be necessary to set the
conductor 200-500 ft below the surface (or ocean bottom) just to
drill the hole for the surface casing
Ø The setting depth of conductor in many cases must be determined
by soil bearing tests and coring.

Setting Depths Using Pore and Fracture
Pressure

Pressure Plots
In drilling engineering, it is convenient to report the pressures i.e ( mud
pressure, formation and fracture pressure) in terms of gradient or more
practically in density units.

Differential Pressure- Overbalance
ØIf the mud pressure in the
well is higher than the pore
pressure, the differential
pressure is called
overbalance
ØIf the mud pressure is less
than the pore pressure then
the differential is known as
the underbalance pressure.

Pore
Pressure
Fracture
Pressure
Data Given

Safety Margins (Trip Margin)
ØThe mud density must be slightly higher than the formation pressure to
prevent formation fluids from entering the borehole
ØEspecially when making trips because the action of pulling the pipe tends
to cause a negative pressure (Swap effect) or a reduction in the hydrostatic
pressure while the pipe is in motion.
ØThis margin is referred as a trip margin.

Safety Margins (Kick Margin)
ØAt the same time the density must be less than the fracture pressure
so that the drilling fluid does not fracture and enter the formations,
ØEspecially, during running the drill string into the hole causes positive
pressures (surge effect).
ØThis margin is called as frac margin or kick margin.

Trip margin
Kick
margin
A mount of the margin
depends on the company
policy, but in general may
be up to 200 psi, 0.06
specific gravity, or 0.5 ppg

According to me, it may not be safe to drill approximately 10000 ft with out any
protection, even if all the conditions are okay
Optional for safety

Assume that the overburden gradient is 1 psi/ft and the
passion ratio is 0.4 calculate the casing setting depth

I. From the given pore pressure, we calculate the mud weight by
adding 200 psi overbalance.
II. Then calculate the pore pressure gradient and the mud
gradient by dividing the proposed pressures by the depth.
III. Calculate the fracture pressure gradient using the overburden
gradient and the passion’s ratio.
IV. Then subtract .06 or 0.5 ppg as a kick margin
Solution

Casing Size Selection
ØAfter determining the number of casing strings required and the
setting depths the next step in the design procedure is to select the
sizes of casing required.
Ø What size casing and what size bits do we require?
ØThe two important things to know about selection of casing size are
as follows:
ü Hole size determines casing size
ü Hole size at any point in the well except the surface is
determined by the previous string of casing

Casing Size Selection
ØIn selecting casing size, we usually start
with the casing size at the bottom of the
hole and work to the top.
ØThe size of the last string of casing run in
a well is generally determined by the type
of completion that will be employed.
ØThat decision is usually the function of an
interdisciplinary team of reservoir,
production, and drilling personnel

Casing Size Selection Workflow
ØOnce we know the diameter of the final string of casing or liner, the
process proceeds like this:
ü Determine the hole size (bit size) for the final string of casing.
ü Determine what diameter casing will allow that size bit to pass
through it. That is the size of the next string of casing.
ü Repeat the procedure until all of the hole sizes and casing sizes
have been determined.

Borehole size selection- Role of Thumb
ØThere are no formulas for determining the ideal borehole size.
ü A borehole must be large enough for the casing to pass freely with
little chance of getting stuck.
ü There should be enough clearance around the casing to allow for a
good cement job.
ü In general, the bigger the borehole the more costly it is to drill
ü Do not forget to check your inventory for the available casing sizes.

Borehole size selection- Role of Thumb
ØSelecting the borehole size is primarily based on current practices in
the area or areas with similar lithology.
ØThere are a number of charts and tables in the literature, some good
for some areas, but greatly lacking for other areas.
ØThe best advice we can offer is to use what is common practice in the
area unless there is good reason to do otherwise.
Ø No matter what specific charts we suggest here, they going to be
wrong for some particular locale or application.

Hard Formations Soft Unconsolidated Formations

Exercise Example:
ØAssume that we have determined the following casing depths:
ØSurface casing: 3000 ft
ØIntermediate casing: 10,500 ft
ØProduction casing: 14,000 ft
ØThe production engineers tell us they will require a production casing
diameter of 7 in., Assume that the well is in an area of unconsolidated
formations.
ØDetermine the optimum casing sizes for this well.

7 “ Production Casing
8.75 “ Bit (Production hole)
9 5/8” Intermediate Casing
12 ¼ “ Bit (Intermediate Hole)
13 3/8 Surface Casing
17 ½ “ Bit (Surface Hole)
20” Conductor Casing

ØFor the previous example, if the bore hole not stable and we have a
serious well bore stability problem, the operator may elect to use
large dimeters to account for.
ØUnder such conditions, the experience in the area should be respected.

Casing Loads
ØTo determine the strength of the casing needed, we must now
consider the types and magnitudes of the loads the casing must safely
bear.
ØThree basic types of loads commonly are considered:
ü Collapse loads
ü Burst loads
ü Axial loads

Casing Loads
ØCollapse loads: are differential pressure loads in which the outside
pressure exceeds the inside pressure, tending to cause the casing to
collapse.
ØBurst loads: are differential pressure loads in which the inside pressure
exceeds the outside pressure, tending to cause the casing to rupture or
burst
ØAxial loads: are tension or compression loads mostly caused by
gravitational and frictional forces on the pipe, but they can also be caused
by pressure and temperature changes as well as bending in curved
wellbores

Casing Loads
ØThe collapse and the burst loads:
ü Dictated by well conditions and anticipated operations in the well.
ü They are functions of formation pore pressures, fracture pressures,
drilling fluid pressures, and cement pressures.
ØThe axial load:
ü A function of the casing selection process itself; in other words, the
ü Axial load is a function of the weight of the casing selected.

Design Philosophy for Load Calculations-1
Ø We almost always are able to determine loads if all is perfect,
Ø we can almost always determine the type of loading that would take
place if things go totally worse, but between those two situations is a
great unknown.
Ø Hence, our most logical approach is to assume the worst case that can
happen, and that is the one we typically use for our casing design.
Ø W do not concern ourselves with the probability of such loading
occurring.
Ø Always assume the worst situation will happen.

Design Philosophy for Load Calculations
The thing that we have to always keep in mind is that we
can not change our designed casing string once it is in
the ground and cemented. If that “unlikely” worst case
should occur, it is too late to change our design

Types of pressure loads under the worst case
• Collapse Loading
ü Minimum internal pressures
ü Maximum external pressures
• Burst Loading
ü Maximum internal pressures
ü Minimum external pressures

Sources of pressure loads
Formation fluids
Ø Water (fresh or salty)
ØOil
ØGas
Drilling fluids
ØWhole mud
ØMud filtrate
Un-set cement
ØWhole cement
ØCement filtrate
ØStimulation fluids
ØOcean or surface water
ØAtmosphere
Other Sources

The Design Philosophy -2
Ø It is relatively easy to ascertain the internal pressures for design purposes
because we almost always know the internal fluids, at least in the design
stages.
Ø The difficulty is that we seldom know the external fluids and pressures
once the casing is in the ground and cemented.
Ø The most common approach is to consider the worst case, not the most
likely case
Ø All we can do is make some reasonable assumptions, and what is
reasonable to one engineer may not be reasonable to another
Ø Casing design is too subjective depending on your boundary conditions.

Gas Pressure Loads
ØAssuming the encountered formation contains Methane (16 MW)

Collapse Load Determination
In the case of collapse loading, our task
is to determine the minimum amount
of pressure the casing will have inside
and the maximum amount of pressure
the casing will have on the outside
(simultaneously at any given stage in
the operations).
Maximum External
Pressure
Minimum Internal
Pressure

Collapse Loads- Internal Loads
ØSources of internal loads:
ü Evacuated casing (fully or partially)
ü Gas
ü Oil
ü Freshwater
ü Field saltwater
ü stimulation fluids
ü Drilling or workover fluids
ü Combinations and partial columns of these

Collapse Loads
ØSources of External Pressure:
ü Freshwater
ü Saltwater
ü Formation pressure
ü Drilling fluid
ü Cement (un-set)
Ø The internal and external loads depend on our assumptions for the
worst case during our design process

Load Cases
ØWe categorize the loading cases by the operational stages into:
ü Running and installation
ü Drilling stage of the next hole
ü Production Phase.
ØWe further breakdown the operations into different events and
possible occurrences that may take place within those three
operational stages.

Installation Stage- Collapse Load
ØThe installation stage includes:
ü Running the casing in the well and
ü Cementing of the casing string.
Ø During running the casing string, we have only one collapse scenario
in which the casing is run empty or partially empty.
Ø During the cementing phase, the collapse may occur because the
cement density in the annulus is greater than the density of the
fluids inside the casing string

Drilling Stage – Collapse Loads
ØCollapse during drilling is almost always
caused by loss of internal pressure from lost
circulation.
ØIn some cases, it can be severe enough to
completely evacuate the casing

Complete Evacuation
Partial Evacuation

Drilling—lost circulation, evacuated
ØComplete evacuation occurs when a very weak zone below the casing
fractures and allows the drilling mud to enter
ØThe hydrostatic head is reduced and the mud level in the well drops.
ØContinued pumping only pumps more mud into the fractured zone
and does nothing to keep the mud level above a static equilibrium
with the fractured zone
ØIn some severe cases, the casing string may be completely evacuated.
ØComplete evacuation is usually happens when drilling below the
surface casing .

Collapse Load- Lost of Circulation
ØFor surface casing, we usually design for a fully evacuated string, but
ØFor intermediate casing, we seldom see a fully evacuated string and to
design for such, might seem a bit too conservative.
ØIn intermediate casing design, we prefer to assume that the well will
be full with fresh water ( never keep the well empty, pump something )

Production stage—collapse loads
ØThis case applies primarily to the production casing.
ØOne may not think of collapse as a possibility during the
producing life of a well.
ØBut to the contrary, it is a very real possibility, perhaps not in
the early stages but definitely in the later life of the well

Production stage—collapse loads
ØProduction casing can be collapsed during the production
phase for some common reasons like:
ØProduction Evacuation
ØArtificial Lift
ØStimulation and Squeezing

Production—evacuation
ØHow can a production string be evacuated? More
easily than many might suspect.

Production Evacuation- Examples
Ø For example, a packer in a gas well develops a slow leak, and the
packer fluid is “produced” along with the gas until it is exhausted. Or,
Ø The perforations sand up below the packer and the flowing gas well
bleeds to atmospheric pressure (casing collapse below the packer).
Ø Or another, a well is stimulated and coiled tubing is run to jet the
well with nitrogen. The jetting removes all the fluid but the
perforations are plugged. The nitrogen flow is stopped and bled to
zero. The casing collapses below the packer.

Production—Artificial lift
Ø Artificial lift poses similar hazards as evacuation.
Ø It is common to bleed off the gas pressure from casing prior to a
workover in a gas-lift well.
Ø Depending on the liquid level in the casing a collapse situation might
arise.
Ø A submersible pump could pump a well “dry” if the perforations
should plug

Production—stimulation, squeeze
ØWhen a well is stimulated or squeeze cemented through perforations,
the formation must be fractured to initiate pump in.
ØThe collapse problem arises from the fact that whenever we fracture
a formation through perforations we have no idea where the fluid is
going in the annulus.
ØIf there is a channel such that the casing above the packer
experiences the fracture pressure it is possible that the casing could
collapse above the treatment packer or retainer.

Production—stimulation, squeeze cementing

Burst loading
ØFor burst loading, we seek to find the
maximum internal pressure and the
minimum external pressure occurring
simultaneously at any given stage of
operations

Burst loading
ØIn burst loading, the external pressure is the
resisting load, and the external loading in a
burst situation normally is taken to be the
lowest possible pressure externally.
ØAt the surface of the string, that pressure
(external ) is taken to be zero or
atmospheric pressure.
Ø In a subsea casing string, it would be the
seawater pressure at the wellhead

External loads, burst
ØWe can assume any external pressure loads in the annulus between
the casing string and the well. Such as :
ü Atmospheric pressure (at surface of string)
ü Seawater pressure (at surface of string)
ü Freshwater
ü Saltwater
ü Formation pressure
ü Drilling fluid

Internal loads, burst
ØWe have different sources for the internal pressure that may cause
casing to burst. Such as :
ü Gas
ü Oil
ü Water
ü Combinations of gas and liquids
ü Cement (liquid)
ü Pump pressure (plug bump, test pressure, stimulations)

Burst Loads- Important Note
ØIt is never acceptable to assume that hardened cement will give us
support in burst, even though it will.
Ø The problem with cement is that we have to design our string before
the well is cemented.
ØIf our cement job is near perfect, then we have additional support in
those sections covered by cement.

Burst Loads- Important Note
ØIf there is even a small interval where
the cement is poor, then we have no
support at that interval, and there is
nothing we can reasonably do to
change that.
ØHence, we can never safely assume
that the hardened cement gives us any
benefit when we are in the design
stage

Burst load cases
ØBurst loading can occur in all stages of well construction and
production.
ØCasing burst may happen during:
ü Installing the casing
ü Drilling the next casing section
ü Production phase

Installation—plugged float or annular bridge
ØDuring cementing, there is always the
possibility that a float could plug or the
annulus could bridge while displacing the
cement.
ØSuch an unanticipated event would likely
be accompanied by a significant increase
in pump pressure before the cementer
could become aware and shut off the
pump

Installation—plug bump
ØWhen the top wiper plug (on top of the cement)
contacts the top float, it stops the displacement
circulation and an increase in pressure occurs.
ØThis is an anticipated event and the cementer
applies a predetermined additional pressure
above the displacement pressure before
stopping the pump. This is referred to as the
plug-bump pressure

Installation—plug bump
ØIts purpose is to assure that the plug is indeed seated on top of the
float. Assuming the float valve is failed, and because the cement is
almost always more dense than the displacement fluid, the maximum
differential pressure occurs when all the cement is displaced.
ØThe magnitude of this pressure is a matter of preference, company
policy, and so forth, but it is generally on the order of 500-1500 psi
depending on the casing and well conditions

Installation—pressure test
ØCasing should be pressure tested once it is in place.
ØMany operators legitimately claim that the plug-bump pressure is the
best test. If the casing holds pressure then there is no reason for it to
leak later.
Ø That is valid, but unfortunately, many regulations require a pressure
test be performed later before drilling out the floats and proceeding
to drill deeper

Installation—pressure test
Ø Pressure tests are done after the cement has been placed and
supposedly cured.
Ø Our only question is, what is the fluid in the annulus? Simply put, we
do not know.
Ø About the best we can come up with is that in the worst case, it is
the same as the mud the casing was run in.
Ø Assuming the displacement fluid in the casing is the same density as
original mud, then this case will give a uniform differential pressure
test to the entire casing string.

Drilling stage—burst loads
ØThere are only two general cases of burst loads that occur in
the drilling stage of well construction. They are:
ü The maximum mud density used in the casing before
the next casing string is set and
ü The pressure from a kick
Again, Do not assume any support from the cement behind the
casing string

Drilling—maximum mud density
Ø We always know, the maximum mud density we will use in drilling below a
casing string to reach the next casing point.
Ø What we never know is the fluid in the annulus. So again we take a worst
case scenario that is within reason.
Ø For surface casing we generally assume something like freshwater for
surface casing and maybe saltwater for intermediate casing.
Ø Some would assume the mud the casing was run in and others might
assume formation pressure.
Ø For simplicity (and lack of data), most use freshwater or saltwater in basic
design

Drilling—well kick
ØThere are three fluids involved in kicks: gas, oil, and saltwater.
ØOf these, gas is the most severe and dangerous
ØWe normally assume that the kick originates at the highest pressure
zone below the casing string, and that in the worst case we have a
solid column of the formation fluid (gas, oil, or saltwater) all the way
to the surface.
ØAll well-control methods are designed to prevent that, but it happens,
and when it does, it is too late to change the casing design

Drilling—well kick
ØThere are two approaches to determine the pressure inside the casing:
Ø If the pressure of the column of fluid does not exceed the least fracture
pressure in the open hole (usually near the shoe ) then the pressure of
that column is calculated from the kick source zone to the surface, or
Ø If the pressure of the kick fluid column exceeds the formation fracture
anywhere in the open hole, we assume the kick fluid is flowing into that
formation, and we calculate the pressures in the casing using that fracture
pressure as the source zone pressure and assume a solid column of the
kick fluid from there to the surface.

Production stage—burst loads
ØIn the production stage of operations, the only affected string is the
production casing string.
ØThe exception to that would be a well that has a production liner and
utilizes the intermediate string as part of the production string.
ØIn that case, the intermediate string must meet the design criteria of
both intermediate and production casing.

Production—Tubing Backup
ØThe production casing is a pressure backup for the tubing string.
ØTubing leaks may happen and the casing should contain the
formation pressure or the tubing string may be pulled out during the
workover operations
ØWhat is the backup fluid in the annulus?
ØSimply we do not know but you can assume fresh water or salt water.

Production—tubing leak
ØOne of the most severe burst loadings in a gas well results from a
near-surface tubing leak.
ØThese leaks are common in gas wells
ØNear-surface tubing corrosion from freshwater condensation mixed
with CO2 to form carbonic acid is quite common in many gas wells.
ØThe result is that wellhead gas pressure is applied to the top of a full
column of weighted packer fluid, and the differential pressures on the
casing can be very high near the packer.

Production—stimulations, squeeze
ØA production string must be able to withstand stimulation and squeeze
pressures.
ØWhen such treatments are performed below a retrievable packer or a
drillable retainer, only the portion of casing below that tool experiences the
treatment burst pressures.
ØOn the other extreme hydraulic fracture treatments performed without
tubing in the well, subject the entire production string to the treatment
pressures.
ØThe pressures for high-rate hydraulic fracture treatments can be quite high
and are often the critical case for burst design.

Industry Design Good Practice- Surface Casing

Surface casing collapse loads
ØThe collapse load for surface casing depends on the worst-case
scenario anticipated, in which the pressure outside the casing
exceeds the internal pressure
Ø There are a number of possibilities, but the most commonly
accepted situation assumes:
ü Cementing collapse
ü Severe lost circulation (assuming complete evacuation and the
mud pressure exits in the annulus)

Surface casing burst loads
ØThe worst case burst load on the surface casing is based on the maximum
anticipated internal pressure and the minimum anticipated external pressure
ØThe typical design situations include:
ü Float valve plugging while cement is inside the casing and the mud outside
ü The plug pump situation in which displacement fluid inside with the pump
plug pressure and the cement slurry outside
ü The pressure of the maximum mud density used to drill the next section.
ü The kick from the lower zone which may or may not frac the shoe at the
casing setting depth. Assuming the fresh water exiting in the annulus.

Intermediate casing Loads
ØThe intermediate casing loading often is straightforward, like the
surface casing, except that the magnitude of the loads generally is
greater.
ØFor collapse Loads , we assume that the in case of lost of circulation
the casing is not completely evacuated like the surface casing, but the
well id full with fresh water in order to continue in the drilling
operation.
ØFor burst loads are the same as the surface casing string.

Production casing collapse load
ØThe most common collapse situation that should be considered
during the collapse load of the production casing includes:
Ø The casing conventional cementing assuming cement slurry out side
the casing and the displacement fluid inside the casing
Ø Casing production evacuation and mud column exits in the annulus
Ø Stimulation or squeezing operations in which the pressure the
pressure inside the casing will equal the formation pressure and
outside the casing will be equal to the formation fracture pressure.

Production casing burst loads
ØIn addition to the burst loads (float valve failure, plug pump), the
casing should designed to :
ü Hold the formation pressure as aback up for the tubing,
ü To withstand any loads because of the gas leaks near the surface.

Example well- Surface casing example

Any pore pressure, mud
pressure, formation fracture
pressure are calculated from
the casing setting depth chart

Surface Casing Collapse Loads
Ø Let's agree that for any differential pressure calculations we will
assume that the differential pressure will be the internal pressure
minus the external pressure.
Ø The differential pressure is calculated at the surface and the
bottom of each casing and each node or point of change either
internal or external

Installation—conventional cementing (Post
Plug)

Drilling—lost circulation
We will always assume then that
the fluid pressure in the annulus
after the cement has set is equal
to the hydrostatic pressure of the
mud it was run in.

Installation—cementing
Ø We have specified our cement volumes in terms of column length in
the annulus of the wellbore, so it is necessary to calculate the column
length inside the casing.
ØIn other words , the cement volume is calculated according to the
annulus volume but we need to determine the equivalent cement
height inside the casing string.

Ki/o is the ratio between the inside height to the outside height
So the cement equivalent height inside the casing string
= the annulus height* Ki/o

Ø The lead slurry is multiplied by 1.5 as we use 50% excess in the
lead slurry
Ø The point here is that the equivalent length of the lead slurry
is more than the casing setting depth this means the casing is
completely filled with the lead slurry when we start the
displacement process
Ø During cement pumping the displacement pressure at the
surface can be calculated as U tube return

ØAgain, we have no idea what the annular pressure is but a worst
case assumption might again be a freshwater channel from top to
bottom.

Drilling—gas kick
ØFirst, we will determine if gas from the formation at 10,500ft will
fracture the formation at the casing shoe.
ØOur maximum formation pressure at 10,500ft is 1.36 SG equivalent,
and our fracture pressure at the shoe at 3000 ft is 1.88 SG equivalent

Formation Fracture Pressure @3000
Gas Pressure @ 10500
Gas Pressure @ 3000 csg shoe.

Cement/fracture check
Øif the hole were perfectly in-gauge (exactly 12-1/4 in. diameter), and
the excess cement would increase the column length of the lead
slurry by 50%.
ØSo instead of a 7000-ft column, we would have 1.5(7000) = 10, 500 ft,
which would fill the annulus by itself.
ØSo if we have a 1000 ft of tail slurry, the maximum length of the lead
slurry would be 10500 − 1000 = 9500 ft. We now calculate the
pressures.

Intermediate casing collapse loads

Drilling—lost circulation
ØWe will assume here that in the event of lost circulation, the casing
will be kept full of water to avoid a kick.
ØAgain we do not know what the outside pressure is, but we may
conservatively assume it is a mud channel (which is slightly greater
than formation pressures).

Intermediate casing burst loads

Installation—conventional cementing
Cement
Spacer
Mud

ØWith the mud ahead, spacer, lead slurry, and tail slurry just into the
pipe and 1000 psi additional pressure before the pump can be
stopped we have

Here we used the mud hydrostatic pressure rather than the fresh water in the annulus.
At the end, it is your assumptions and company policy

Drilling—gas kick
The gas pressure is higher than the frac pressure at the shoe, so for the worst case we will
use the fracture pressure

Here, we assumed freshwater mud behind the casing string.

Cement/fracture check
This part includes both the spacer and the mud

Production—evacuation
Here, we selected the mud in which the casing was run

Installation—conventional cementing

Axial loads and design plot
ØThere are four sources of axial load (tension or compression) in a
casing string:
Ø • Gravitational forces (weight and buoyancy)
Ø • Borehole friction
Ø • Bending
Ø • Temperature changes

Casing (2) casing setting depth casing string

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