Casing
Casing has several important functions during the drilling and completing of a well. It is used to prevent the borehole from caving in during the drilling of the well, to provide a means of controlling fluids encountered while drilling, to prevent contamination of fluids to be produced, and to protect or isolate certain formations during the course of a well. Casing is also one of the most expensive parts of a well, around 20% of the cost of a completed well.
Casing is usually divided into five basic types.
Conductor Casing
Conductor pipe or drive pipe if it is hammer-driven to depth, is the first string of casing to be used. The setting depth can vary from 10 ft to around 300 ft. The normal size range for conductor pipe is from 16 to 36 inches (outside diameter). The conductor pipe must be large enough to allow the other casing strings to be run through it. Purposes of conductor pipe are to:
Surface Casing
- The amount of surface casing used will depend on the depth of the unconsolidated formations. Surface casing is usually set in the first competent formation. Normal size for surface casing is between 20 inch and 13-3/8 inch (outside diameter). Since temperature, pressure and corrosive fluids tend to increase with depth, different grades of casing will be required to handle the different well conditions. Purposes of surface casing are to:
- protect fresh water formations
- seal off unconsolidated formations and lost circulation zones
- provide a place to install the B.O.P.’s
- protect “build” sections on deviated wells
- provide for a sufficient “leak-off” test to be conducted
Intermediate Casing
Intermediate casing is set after surface casing, normally to seal off a problem formation. The size of intermediate casing, will depend on the size of the surface casing and the grade required to withstand the subsurface conditions. Normal sizes are between 9 5/8 and 13 3/8 inch (outside diameter)
Production Casing
Production casing is usually the last full string of pipe set in a well. These strings are run to isolate producing formations and provide for selective production in multi-zone production areas. The size of production casing will depend on the expected production rate, the higher the barrel per day production rate, the larger the inside diameter of the pipe. Common sizes are between 3 and 7 inch (outside diameter).
Liner
A liner is a string of casing that does not reach the surface. They are usually “hung” (attached to the intermediate casing using an arrangement of packers and slips) from the base of the intermediate casing and reach to the bottom of the hole. The major advantage of a liner is the cost of the string is reduced, as are running and cementing times. During the course of the well, if the liner has to be extended to the surface (making it another string of casing), the string attaching the liner to the surface is known as a “tie-back” string.
Casing Standards
The American Petroleum Institute (api) has developed certain standards and specifications for oil-field related casing and tubing. One of the more common standards is weight per unit length. There are three “weights” used:
- Nominal Weight: Based on the theoretical calculated weight per foot for a 20 ft length of threaded and coupled casing joint.
- Plain End Weight: The weight of the joint of casing without the threads and couplings.
- Threaded and Coupled Weight: The weight of a casing joint with threads on both ends and a coupling at one end.
The Plain End Weight, and the Threaded and Coupled Weight are calculated using API formulas. These can be found in API Bulletin 5C3.
API standards include three length ranges, which are: - R-1: Joint length must be within the range of 16 to 25 feet, and 95% must have lengths greater than 18 feet
- R-2: Joint length must be within the range of 25 to 34 feet, and 95% must have lengths greater than 28 feet
- R-3: Joint length must be over 34 feet, and 95% must have lengths greater than 36 feet.
The API grade of casing denotes the steel properties of the casing. The grade has a letter, which designates the grade, and a number, which designates the minimum yield strength in thousands of psi. A table of API casing grades and properties are listed below:
Table 2-1:
| API Grade | Yield Strength (min), psi | Tensile Strength (min), psi |
| H-40 | 40,000 | 60,000 |
| J-55 | 55,000 | 75,000 |
| K-55 | 55,000 | 95,000 |
| C-75 | 75,000 | 95,000 |
| L-80 | 80,000 | 1,00,000 |
| N-80 | 80,000 | 1,00,000 |
| C-90 | 90,000 | 1,05,000 |
| C-95 | 95,000 | 1,05,000 |
| P-110 | 1,10,000 | 1,25,000 |
Casing properties are defined as:
- Yield Strength: The tensile stress required to produce a total elongation of 0.5% per unit length
- Collapse Strength: The maximum external pressure or force required to collapse the casing joint
- Burst Strength: The maximum internal pressure required to cause a casing joint to yield
Casing dimensions are specified by its outside diameter (OD) and nominal wall thickness. Normal wellsite conventions specify casing by its OD and weight per foot. As stated earlier, one should specify which weight one is referring to, though most often it is the nominal weight. - Casing Couplings
Couplings are short pieces of casing used to connect the individual joints. They are normally made of the same grade of steel as the casing. Through their strength can be different than the casing. The API has specifications
for four types of couplings.
- Short round threads and couplings (CSG)
- Long round threads and couplings (LCSG)
- Buttress threads and couplings (BCSG)
- Extremeline threads (XCSG)
The CSG and LCSG have the same basic thread design. The threads have a rounded shape, with eight threads per inch. These threads are generally referred to as API 8-round. The only difference between the two is that the LCSG has a longer thread run-out, which offers more strength for the connection. LCSG are very common couplings.
Buttress (BCSG) threads are more square, with five threads per inch. They are also longer couplings, with corresponding longer thread run-out.
The XCSG (Extremeline) couplings are different from the other three connectors in that they are integral connectors, meaning the coupling has both box and pin ends.
Coupling threads are cut on a taper, causing stress to build up as the threads are made up. A loose connection can result in a leaking joint. An over-tight connection will result in galling, which again, will cause leaking. Proper make-up is monitored using torque make-up tables and the number of required turns.
A special thread compound (pipe dope) is used on casing couplings, each type of coupling having its own special compound.
Many companies have their own couplings, in addition to the API standards, which offer additional features not available on the API couplings.
Casing Design Criteria:
Casing design itself is an optimization process to find the cheapest casing string that is strong enough to withstand the occurring loads over time. The design itself is therefore depended on:
- Loading conditions during life of well (drilling phase, completion procedures, work over operations, and operation phase),
- strength of the formation at the casing shoe (assumed fracture pressure during planning and verified by the formation integrity test),
- availability and real price of individual casing strings,
- expected deterioration of the casing due to production and expected completion fluid settlement.
It should be noted that the loading conditions are subjective and based on company policies, governmental regulations and best practices. Regarding real casing prices, casing types currently on stock and general availability (purchase of manufacturing lot) can have a major selection implication.
Similar to the drill string, casings are normally designed for burst, collapse, tension, shock loads and biaxial stresses. Different safety margins or safety factors are demanded by company policies or government regulations and have to be satisfied.
To calculate the burst and collapse pressure the casing has to be designed for, the differential pressure (outside pressure – inside pressure) is determined for the worst case to appear.
For burst pressure, the maximum formation pressure anticipated while drilling the next section is assumed. Thus the highest burst pressure is expected to be at the top of the casing and least at the casing shoe (hydrostatic pressure at annulus to counterbalance). When the production tubing is assumed to leak gas to the casing, this burst pressure profile is reversed.
For collapse pressure, it is assumed that the mud inside the casing is lost to a weak or fractured formation below. Thus the collapse pressure is due to the hydrostatic pressure of the fluid outside the casing and therefore maximum at the casing shoe and zero at the casing top. In this way the collapse pressure can be calculated with:
pc = 0.052.ρout.D
The tensile forces acting on the casing are due to its weight, bending forces and shock loading at landing. It should be noted that at highly deviated wells, landing the casing is only possible when run partly or totally empty. This is also called “floating the casing in”. Here the casing, when run, is closed at the shoe and its inside is not filled with mud. This causes a buoyancy to such an extend that the casing may has to be forced into the well. The casing dimensions where the buoyancy counterbalances the casing weight is given by:
For tensile loading, the topmost joint is considered as the weakest one since it carries all the casing weight.
When casings have to carry inner strings as well (conductor, surface and intermediate casing), they are subjective to compression loads. Thus production casings and casings where liners are below are free from these loads.
Since the casing is in general subjected to a combination of external pressures and its own weight, they are under a biaxial stress regime. This will reduce the collapse resistance of the casing. The amount of collapse resistance reduction can be calculated with the methods described for drillstring calculation.
In addition to the general casing loads discussed above, casings are also subjected to bending with tongs, slip crushing, wear due to rotation of the drillstring and running tools into the hole as well as corrosion and fatigue.
As mentioned above, the actual loadings of the casings have to be lower than the individual casing strengths. This is often expressed with safety factors. Applying propper safety factors account for the uncertainty in estimation the real loadings as well as the change of casing properties over the lifetime of the well. Commonly chosen safety factors are:
Collapse strength: 0.85 – 1.125
Joint strength: 1.60 – 1.80
Plain-end yield strength: 1.25
Internal yield pressure: 1.0
In practice, sophisticated casing design computer programs are available in companies that allow complex casing loading scenarios and the design of casing strings with various casing pipes (different grades) as well as variable diameters for one casing string. Such casings are generally referred to as “combination string”.
Graphical Method for Casing Design
The graphical method to select casings with the suitable grades, weights and section lengths is the most often applied one. Here, the individual loads (burst, collapse and tensions) are represented as graphs on a pressure vs. depth diagram. The minimum strength values of the individual casing sections are drawn as vertical lines where the suitable ones have to be to the right of the respective loads (stronger). In this way, the depth where the minimum safety (load and casing minimum strength are closest) can be easily spotted and the respective factors calculated.
To construct the diagram, following procedures can be applied:
Burst line:
- Calculate the external pressure due to an assumed fluid column of 0.465 [psi/ft] (salt- saturated completion fluid),
- Calculate the internal pressure due to the maximum anticipated pressures when drilling the next section,
- Calculate the burst pressure pb as the difference between the external and the internal pressures,
where:
pf [ft] … maximum anticipated formation pressure to drill next section
TD [ft] … total depth (TVD)
CSD [ft] … casing setting depth (TVD)
Gf [psi/ft] … formation fluid gradient
ρm [ppg … mud density
pb =pf −(TD−CSD).Gf −0.053.ρm.CSD
In this way the burst pressure at the surface is calculated as:
pb =pf −TD.Gf
- On the pressure vs. depth graph draw a stright line between the maximum Burst pressure
at the casing top and the minimum burst pressure at the casing shoe, - Select from tables 8.6 through 8.21 casings with burst resistance above the burst loading line,
- Draw the vertical lines of the casings with the individual grades,
- The individual intersections of the burst loading line and the casing burst resistances deter- mine the depths from which upwards the casing grades can be used.
Collapse line:
- Calculate the external and internal pressure due to the mud columns outside and inside the casing,
- Calculate the collapse pressure pc as the difference between the external and the internal pressures,
- On the pressure vs. depth graph draw a stright line between the maximum collapse pressure at the casing shoe and the zero at the casing top,
- Select casings with collapse resistance above the collapse loading line,
- Draw the vertical lines of the casings with the individual grades,
- The individual intersections of the collapse loading line and the casing collapse resistances determine the depths up to the casing grades can be used.
Tensile line:
- Calculate the weight of the casing string in air,
- Calculate the buoyancy force,
- Calculate the bending force with equation 8.26 when designing the casing for a deviated hole,
where:
BF = 63.doWcs.θ
BF [lbf] … bending force
θ [◦]… change of angle in deviation
Wcs [lb/ft]… nominal weight of casing Wcs = 3.46.Acs
- Calculate shock loads due to setting of the casing using equation 6.18 by replacing Wdp with Wcs ,
- Draw tensile loading on the pressure vs. depth graph,
- Select casings from table x that have higher body yield strength than the tensile loading,
Having drawn all three major design criteria within one plot, a combined casing sting that is strong enough at all depth can be selected. Finally check that the joint strengths are larger the the calculated tensile loading.
Note that this procedure for casing design considers strength criteria only and is not optimized for real casing costs. Thus a stronger casing might be preferred since it is cheaper (availability, etc.) than a weaker one.
Graphical design of casing string
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