2. Casing Sitting depth selection
Selection of the number of casing strings and their respective setting depths is based
on many following factors or purposes:
➢ Hole problems:
• To cover severe lost circulation zones.
• Isolation from weak shallow zones.
• To prevent differential pipe sticking problems or perhaps a
decrease in formation pore pressure.
• In deep wells, primary consideration is either given to the
control of abnormal pressure formation pressures, and
hole caving problems etc.
• To control of salt beds which will tend to flow plastically.
➢ protection of fresh-water aquifers.
➢ Geological condition (formation pressure, fracture gradients, unconsolidated
formations etc.). For the purpose of control the pore pressure and fracture gradient of the
formation to be penetrated.
3. The selection of Conductor setting depth is usually determined by drilling
problems and the protection of water aquifers at shallow depths. Severe lost
circulation zones are often encountered in the interval between 100 and 1,000 ft
and are overcome by covering the weak formations or unconsolidated formations
with conductor pipes.
Conductor Pipe:
Surface Casing String:
The surface casing string is often subjected to abnormal pressures due to a kick
arising from the deepest section of the hole. If a kick occurs and the shut-in casing
pressure plus the drilling fluid hydrostatic pressure exceeds the fracture resistance
pressure of the formation at the casing shoe, fracturing can occur. The setting depth for
surface casing should, therefore, be selected so as to contain a kick-imposed
pressure.
Casing Sitting depth selection
Another factor that may influence the selection of surface casing setting depth is the
protection of fresh-water aquifers. Drilling fluids can contaminate fresh- water aquifers
and to prevent this from occurring the casing seat must be below the aquifer.
4. It is essential to choose a casing seat that can withstand the maximum pressures to
which the wellbore will be subjected during the drilling of the next hole section.
Accurate knowledge of pore pressure and fracture gradient plays a major role in the
selection of proper casing seats that allow the drilling of each successive hole section
without fracturing.
The pressure which the formation at the casing seat must be able to
withstand is the greater of:
II. The maximum pressure exerted at the casing seat when circulating out gas influx from
the total depth (TD) of the next hole section.
I. The hydrostatic pressure of the mud used to drill the next section.
Casing Sitting depth selection
Once this information is available, casing setting depth should be determined for the
deepest string to be run in the well.
Design of successive setting depths can be followed from the bottom string
to the surface.
5. For exploration wells, it is preferable to use offset well data to select casing seats for
the well under consideration. If this data is not available, then the casing seat depth may
be determined using the following methods:
1. The Formation Breakdown Pressure (FBP) or Fracture
gradient data together with pore pressure and mud weight
should be plotted against depth.
Casing seat selection Based on
Mud weights
2. The FBP or fracture gradient data together with pore
pressure and kick (Influx) circulation pressure should be
plotted against depth.
Casing seat selection based on
Gas influx pressures
The selected casing setting depth is then the deeper
of the two depths arrived under items 1 and 2 above. Depth
Casing Sitting depth selection
o The shallowest casing setting depth is point X.
o The shallowest casing setting depth is point Y.
6. Casing Seat selection
Sample relationship among casing setting depth, formation pore
pressure gradient, and fracture gradient
8. When a drilling engineer has to design a set of casings for a well, there are quite a
few considerations to be made.
It is necessary to predict all the physical forces that each casing may be subjected
to throughout the life of the well (from starting drilling until the well is finally abandoned).
1. The selection of the casing sizes and setting depths;
3. The calculation of the magnitude of these loads and selection of an appropriate
weight and grade of casing.
2. The definition of the operational scenarios which will result in burst, collapse and
tension loads.
The casing design process involves three distinct operations:
What is the Casing design?
Casing design involves the determination of factors which influence the failure of
casing and the selection of the most suitable casing grades and weights for a specific
operation, both safely and economically.
The criteria which must be considered when carrying out detailed casing design are:
I. Burst pressure.
II. Collapse pressure.
III. Tension Load.
VI. BIAXIAL reductions in burst and collapse
resistance caused by compression and tension loads.
V. Other or Special loading conditions.
9. The burst loads on the casing must be evaluated to ensure that internal yield
resistance of the pipe is not exceeded. The loads are normally caused by mud
hydrostatic pressure inside the casing and perhaps some surface pressure. Fluids on
the outside of the casing, called backup fluids, supply a hydrostatic pressure that helps
resist pipe burst. The resulting, effective burst pressure is the internal pipe load/
pressure minus any external pressure. This net burst pressure is termed the resultant.
Burst pressure should be calculated as follows:
Burst pressure = Internal pressure – External pressure
Typical relationships among burst
load, backup, and resultant
10. The primary Collapse loads are supplied by the column of fluids on the outside of the
casing. These fluids are usually the mud and possibly the cement in which the casing
was set. The back up fluids are generally considered negligible, (a) resulting from
complete loss or evacuation of the mud inside the pipe. Or (b) partial supportive, resulting
from some loss of internal mud.
Two common concepts for collapse loading
(a) Dry inside and (b) partially dry inside
Since the hydrostatic pressure of a column of
mud increase with depth, collapse pressure is
highest at the bottom and zero at the top.
When a casing is subjected to a collapse
pressure due to mud Or cement hydrostatic
pressure from outside, it is called collapse load.
The internal pressure is called back-up. The
difference between the collapse and internal
pressure is termed as resultant.
Collapse pressure = External pressure – internal pressure.
The Drilling engineer should ensure that the collapse pressure never exceeds the
collapse resistance of the casing.
11. The design tensile load is the weight of the steel in the casing below the depth for
which the casing is being designed (the tension will therefore increase from the bottom to
the top). The backup is the buoyancy of the casing below the point.
The uppermost joint of the string is considered the weakest in tension, as it has to
carry the total weight of the casing string.
Tension. Most axial tension loads arises from the weight of the casing itself.
Compression effects occur in casing due to temperature
effects in landed casing and because of the weight of other inner
casing strings which are supported by the outer strings.
If the outer casing is cemented to the surface it will be able to
support all the expected compression loads. If however, it is not
cemented to surface, then there is a danger of buckling due to the
compressive load.
12. ✓ Burst design The maximum burst loading occurs when a kick is taken and the
annulus contains both gas and mud. The casing must be able to withstand
(1) kick pressures from the mud and gas, (2) injection pressure at the bottom
of the string, and (3) maximum surface pressure at the top of the string.
✓ Collapse design the collapse loading is supplied by the mud weight that the casing
was set in and the annular cement. The load will be a cement hydrostatic pressure in
areas where cement for intermediate pipe is circulated to the surface.
✓ Tension design Occasionally, the biaxial effects of tension on burst and collapse will
allow the use of pipe that appears to be underdesigned during the tentative pipe
selection process. However, after the biaxial effects are considered, the pipe is
satisfactory.
The backup fluids for the burst design are considered equal in
industry to formation fluids.
The collapse backup fluids is computed as a column of the heaviest mud used
below the intermediate casing that has a hydrostatic pressure equal to a native fluid
fracture gradient.
13. ✓ Burst design Production casing may be expected to bottom-hole pressure (BHP) if a
tubing leak develops. The worst case occurs when a small leak at the bottom of the
tubing allows gas to enter the packer fluids annulus and migrate to the surface.
✓ Collapse design the collapse load line is computed with the mud that the pipe was set in
and the annular.
✓ Tension design procedures are identical to previously described procedures. A tension
design factor of 1.8 and a 100,000 Ib overpull value are used.
The backup is provided by native formation fluids.
The collapse backup is considered “dry” when gas lift operation are expected.
14. The maximum load concept is perhaps the most widely used casing design procedure
in the drilling industry. This method versions, analyzes expected drilling problems.
To properly evaluate the loads imposed on different types of designs, each type
should be considered separately. (1) Surface casing, (2) Intermediate casing, (3)
Production casing.
The loading for Burst should be considered first, since burst will dictate the design
for most of the string. And the least-expensive pipe that will satisfy the burst load is
tentatively selected.
Subsequently, the collapse loads are defined and the tentative selection is evaluated for
collapse resistance. The string sections can be upgraded as necessary.
Once the weights, grads and section lengths have been determined to satisfy burst and collapse
loadings, the tension load can be evaluated. The string sections can be upgraded as necessary, and
coupling types determined.
Final step is a check on BIAXIAL reductions in burst and collapse resistance caused by
compression and tension loads, respectively. The string sections can be upgraded as necessary.
Generally, the following steps are taken: (1) Determine maximum load, (2)
Determine minimum back-up, (3) Determine resultant load, (4) Determine design load, (5)
Select casing grade and weight , etc., (6) Adjust against bi-axial load.
15. Casing design is not an exact technique, because of the uncertainties in
determining the actual loading and also because of the change in casing properties
with time, resulting from corrosion and wear.
A Safety Factor (SF) is used to allow for such uncertinties in the casing design and
to ensure that the rated performance of the casing is always greater than any expected
loading.
First we predict the burst, collapse, and tension that we anticipate, and multiply the
anticipated numbers by the SF to determine the stresses that the casing must be able to
withstand.
Design
Safety Factor
Loads
Type of load
11,000 psi
1.1
10,000 psi
Burst
11,250 psi
1.125
10,000 psi
Collapse
180,000 Ibf
1.8
100,000 Ibf
Tension
Each operating company uses its own SF for specific situations. Usual
safety factors are:
essure
Burst
g
Ca
of
ce
resis
Burst
SF
Pr
sin
tan
=
The SF in burst is given by:
16. ✓ Corrosion. When acidic gases such as hydrogen sulfide (H2S) or carbon
dioxide (CO2) are present with water, steel components can become
seriously corroded. This is worse with high temperatures; corrosion rates
roughly double for every 32°C increase in temperature. It is also worse with
higher pressures and with higher concentrations of corrosive agents.
Special steels containing nickel or chromium can be used, but these
are much more expensive than plain carbon steels.
Unfortunately, a standard set of casing design guidelines cannot be used
for every string of pipe run into a well. Various drilling and geological conditions
require modification to the pipe design guidelines. In many cases, the drilling
engineer must evaluate the specific circumstances before selecting a design
procedure.
17. ✓ Connections. Most failures in casing (around 90%) occur at the connection
the part that screws two joints together. This should not be surprising; an
extruded steel pipe is pretty strong, whereas a pipe that has a thread cut on it
must have decreased strength against some, if not all, forces.
Particular strain is placed on a connection where the casing is placed in a
curved section of wellbore. High tension combined with bending forces and also
internal forces place great strength requirements on the connection threads.
✓ Salt. bedded salt under formation temperature often acts as a flowing fluid. It
can shear casing because it supports the overburden stress of the upper
sediments. Pipe designed for bedded salt should consider the collapse load
fluids as approximately 19.3 Ib/gal mud. Which is equal to overburden stress.
20. ▪ Briefly write principle method for determining the Surface casing
Burst design for the following scenario
o. Gas kick has filled the surface pipe and the uncased borehole below the
casing shoe with high pressure gas.
o. Cement is not considered as providing any burst support.
