Introduction to the Casing Design Process
The casing design process involves three distinct operations: the selection of the casing sizes and setting depths; the definition of the operational scenarios which will result in burst, collapse and axial loads being applied to the casing; and finally the calculation of the magnitude of these loads and selection of an appropriate weight and grade of casing. The steps in the casing design process are shown in Figure 13.
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Figure 13 Casing design process |
1.12.1 Design Casing Scheme Configuration — Select Casing sizes and Setting Depths
The casing setting depths are selected on the basis of an assessment of the conditions to be encountered when drilling the subsequent hole section or, in the case of production casing, the completion design.
The first step in deciding upon the setting depth for the surface and intermediate casing strings is to calculate the maximum pressures that could be encountered in the hole section below the string in question. These pressures must not exceed the formation strength at any point in the hole and in particular at the casing shoe. The highest pressure that will be encountered in the open hole section will occur when circulating out a gas influx (see chapter on Well Control). The formation strength can be estimated from nearby well data or by calculation (see chapter on Formation pressures and fracture strength). The procedure for establishing the acceptable setting depth is illustrated in Figure 14:
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1. start at Total Depth (TD) of the Well
2. Determine the formation fracture pressure at all points in the well
3. Calculate the borehole pressure profile when circulating out a gas influx from
TD
4. plot the formation fracture pressure and the wellbore pressure when circulating out an influx, on the same axes
5. The casing must be set at least at the depth where the two plots cross i. e. this is the shallowest depth at which the casing can be safely set. If the casing is set any shallower when drilling this hole section then the formation will fracture if an influx occurs.
6. Repeat steps 2 to 5 moving up the well, with each subsequent string starting at the casing setting depth for each string.
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Pressure, psi |
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Figure 14 Casing setting depth determination |
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1 |
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T Borehole Pressure Profile . Less Than Fracture Pressure Influx Depth N |
Depth, ft.
The setting depth of the casing will also be determined by a range of other considerations such as: the need to isolate weak formations from high mudweights; isolate lost circulation zones; and to isolate troublesome formations, such as shales, which can cause hole problems whilst drilling subsequent formations.
The casing sizes and string configuration are dictated by the size of the smallest casing string to be run in hole. Once the smallest casing size is known all subsequent casing sizes (and hole sizes) are selected from figure 3. The smallest casing size is selected on the basis of operational considerations such as: the size and configuration of the completion string or well testing and/or the size of the logging tools to be run through the casing. The drilling engineer will collate this information from the geology, reservoir engineering and production engineering departments. The objective of the drilling engineer is to use the smallest casing sizes possible. It can be readily appreciated that if it is acceptable to use a 4” casing string as the production casing then the next string will be 7”, the next 9 5/8” and so forth. Hence, if only three casing strings are required then the surface string can be 9 5/8”. This slimhole design will result in considerable savings in drilling and equipment costs.
1.12.2 Define the Operational Scenarios and Consequent Loads on the Casing
The loads to which the casing will be exposed during the life of the well will depend on the operations to be conducted: whilst running the casing; drilling the subsequent hole section; and during the producing life of the well. These operations will result in radial (burst and collapse) and axial (tensile and compressive) loads on the casing strings. Since the operations conducted inside any particular string (e. g. the surface string) will differ from those inside the other strings (e. g. the production string) the load scenarios and consequent loads will be specific to a particular string. The definition of the operational scenarios to be considered is one of the most important steps in the casing design process and they will therefore generally be established as a company policy.
1.12.3 Calculate the Loads on the Casing and Select the Appropriate Weight and Grade of Casing
Having defined the size and setting depth for the casing strings, and defined the operational scenarios to be considered, the loads to which the casing will be exposed can be computed. The particular weight and grade of casing required to withstand these loads can then be determined.
The uniaxial loads to which the casing is exposed are:
Collapse Load
The casing will experience a net collapse loading if the external radial load exceeds the internal radial load (Figure 15). The greatest collapse load on the casing will occur if the casing is evacuated (empty) for any reason. The collapse load, pc at any point along the casing can be calculated from:
Pc = Pe — Pi
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Figure 15 Radial loads on casing |
Burst Load
The casing will experience a net burst loading if the internal radial load exceeds the external radial load. The burst load, pb at any point along the casing can be calculated from:
In designing the casing to resist burst loading the pressure rating of the wellhead and BOp stack should be considered since the casing is part of the well control system.
The internal, pi and external, pe loads which are used in the determination of the burst and collapse loads on the casing are derived from an analysis of operational scenarios.
External Loads, Pe:
The following issues are considered when deciding upon the external load to which the casing will be subjected:
(a.) The pore pressure in the formation (pore pressure)
If the engineer is satisfied that it will be possible to displace all of the mud from the annulus between the casing and borehole during the cementing operation, and that a satisfactory cement sheath can be achieved, the formation pore pressure is generally used to determine the load acting on the casing below the top of cement in the annulus, after the cement has hardened.
(b.) The weight of the mud in which the casing was run.
If a poor cement bond between the casing and cement or cement and borehole is anticipated then the pressure due to a colom of mud in the annulus is generally used to determine the load acting on the casing below the top of cement in the annulus, after the cement has hardened. If the mud has been in place for more than 1 year the weighting material will probably have settled out and therefore the pressure experienced by the casing will be due to a colom of mud mixwater (water or base-oil).
(c.) The pressure from a colom of cement mixwater
The pressure due to the cement mixwater is often used to determine the external load on the casing during the producing life of the well. This pressure is equal to the density of fresh or seawater in the case of water-based mud and base oil in the case of oil based mud. The assumption is that the weighting material in the mud (generally Barite) has settled from suspension.
(d.) The pressure due to a colom of cement slurry
The pressure exerted by a colom of cement slurry will be experienced by the casing until the cement sets. It is assumed that hardened cement does not exert a hydrostatic pressure on the casing.
(e.) Blockage in the annulus
If a blockage of the annulus occurs during a stinger cement operations (generally performed on a conductor casing). The excess pumping pressure on the cement
will be transmitted to the annulus but not to the inside of the casing. This will result in an additional external load during stinger cementing. In the case of conventional cementing operations a blockage in the annulus will result in an equal and opposite pressures inside and outside the casing.
It is commonplace to consider the internal loads due to the following:
(a.) Mud to Surface:
This will be the predominant internal pressure during drilling operations. The casing designer must consider the possibility that the density of the drilling fluid may change during the drilling operation, due to for instance lost circulation or an influx.
(b.) Pressure due to influx
The worst case scenario which can arise, from the point of view of burst loading, is if an influx of hydrocarbons occurs, that the well is completely evacuated to gas and simultaneously closed in at the BOP stack.
(c.) Full Evacuation
The worst case scenario which can arise, from the point of view of collapse loading, is if the casing is completely evacuated.
(d.) Production Tubing Leak
In the case of production casing specifically a leak in the production tubing will result in the tubing pressure being exposed to the casing. The closed in tubing pressure is used as the basis of determining the pressure on the casing. This is calculated on the basis of a colom of gas against the formation pressure.
The pressure below surface is based on the combined effect of the tubing head pressure and the hydrostatic pressure due to a colom of packer fluid (if there is any in the annulus).
(e.) Fracture Pressure of Open Formations
When considering the internal loads on a casing string the fracture pressure in any formations open to the internal pressures must be considered. The pressure in the open hole section cannot exceed the fracture pressure of the weakest formation. Hence, the pressures in the remaining portion of the borehole and the casing will be controlled by this fracture pressure. The formation just below the casing shoe is generally considered to be the weakest formation in the open hole section.