Casing String Design - Deviated Wells
The basic difference in casing design for a deviated well is the magnitude of the loads encountered in the deviated or angle build section. This requires bending and torque considerations. Greenip offers three major points for consideration:
1. Axial and torque loads can be estimated by analyzing separate sections.
2. Relationships can be developed for various parameters in casing string design.
3. The pickup, set down, and neutral states produce sufficiently different loads and magnitudes to analyze each separately.
First, divide the string into three segments, (1) the extension or reach interval, (2) the build interval (containing the deviation) and (3) the vertical interval, Figure 2.20. As with conventional casing design, the casing in a horizontal well is designed from the bottom up. Interval (2), the build interval, is simplified by assuming the angle is constant. Interval (l), the extension or reach portion is assumed to be a constant inclination. An example of the magnitude of the forces at pickup, neutral and set down are shown in Figure 2.21.
A liner is a casing string that does not extend back to surface. Liners may be permanent or temporary and run for a variety of reason^:^*^^^
1. Wear protection of the permanent casing string from rotating drill pipe or frequent tubing movement, especially in a deviated section.
2. Correction of hole difficulty such as doglegs, Key seats, or ledges.
3. Zone isolation of a high pressure zone or a lost circulation zone.
4. As an economical alternative to a full casing string.
5. To allow adequate room above the liner top for a large diameter pump.
6. To reduce casing tension loads in deep wells or to allow use of an available, low strength connection.
7. For repair of leaks or buckled casing.
8. For casing strengthening in earth shift zones.
Most reasons for liner design incorporate the cost reduction factor of not running casing back to surface. Liners have drawbacks as well, including several problems related to liner cementing. From a design standpoint, perhaps the biggest concern is that the intermediate string or the last full string becomes the top part of the liner and must handle the burst force generated by the zones crossed by the liner. Before a decision is made on use of a liner, the strength of the top part of the last full string must be checked against the new maximum expected surface pressure. Unless proven otherwise by cement bond evaluation tools, the upper pipe strength alone (no assistance from the cement sheath) must be capable of withstanding the pressure. If the upper section will not withstand the forces, it should be protected by running a full string, or, the string should be run before perforating the well.
The first approach liner design is the same as for full casing strings. The collapse, burst, and tension safety factors and design equations are the same. The basic differences between liner and casing design come to light in the design of liners for deep wells, hot environments, and very high pressure zones.
Burst failure of liners is usually caused by kicks while drilling below a liner,39p40 pressure when fracture stimulating, or a tubing leak while producing a deep, high pressure zone. All these factors are made worse by a poor cement job. Since filling the casing/openhole annulus with cement significantly strengthens and supports the pipe, a good cement job over high pressure or earth movement zones is a requirement in any deep well.
An illustration of the complications caused by a poor cement job 39*40 is illustrated in Figure 2.22. After a primary cement job on the 9-5/8 in. string, the 6-518 in. liner is run and a circulation cement job is initiated. The low pressure zone at 13,800 breaks down while cementing, returns are lost and the cement top peaks at 13,400 (Figure 2.23a). A top squeeze with cement seals the top of the liner but leaves an uncemented zone from 13,120 ft to 13,400 ft (Figure 2.23b). While drilling near TD to test a deep structure, the temperature of the mud goes from 270" (temp. of the zone at 15,400 ft) to the bottomhole temperature (at 18,500 ft) of 345°F. Since both ends of the liner are cemented, stress will be induced by the temperature rise
Although the liner completion described in Figure 2.22 may be used only as a liner, there are some conditions when the liner may be run back to surface. This liner tie-back may be temporary, to protect
permanent casing strings from wear during drilling4' or permanently, with cement, to strengthen the casing string through a high pressure zone or isolate and stop a casing leak38 or a leaking liner top.42 To allow a tie-back, most liners are equipped with a liner tie-back receptacle. The receptacle is an internally polished receiver that will accept the seal assembly of the tie-back liner. The tie-back liner usually incorporates some type of cement port or sliding sleeve and seat that will allow cement to be circulated through to the annulus and up the annulus to surface. The seat, float equipment andlor plugs used in the cementing operation are of drillable material.
The basic difference in casing design for a deviated well is the magnitude of the loads encountered in the deviated or angle build section. This requires bending and torque considerations. Greenip offers three major points for consideration:
1. Axial and torque loads can be estimated by analyzing separate sections.
2. Relationships can be developed for various parameters in casing string design.
3. The pickup, set down, and neutral states produce sufficiently different loads and magnitudes to analyze each separately.
First, divide the string into three segments, (1) the extension or reach interval, (2) the build interval (containing the deviation) and (3) the vertical interval, Figure 2.20. As with conventional casing design, the casing in a horizontal well is designed from the bottom up. Interval (2), the build interval, is simplified by assuming the angle is constant. Interval (l), the extension or reach portion is assumed to be a constant inclination. An example of the magnitude of the forces at pickup, neutral and set down are shown in Figure 2.21.
Liner Design
1. Wear protection of the permanent casing string from rotating drill pipe or frequent tubing movement, especially in a deviated section.
2. Correction of hole difficulty such as doglegs, Key seats, or ledges.
3. Zone isolation of a high pressure zone or a lost circulation zone.
4. As an economical alternative to a full casing string.
5. To allow adequate room above the liner top for a large diameter pump.
6. To reduce casing tension loads in deep wells or to allow use of an available, low strength connection.
7. For repair of leaks or buckled casing.
8. For casing strengthening in earth shift zones.
Most reasons for liner design incorporate the cost reduction factor of not running casing back to surface. Liners have drawbacks as well, including several problems related to liner cementing. From a design standpoint, perhaps the biggest concern is that the intermediate string or the last full string becomes the top part of the liner and must handle the burst force generated by the zones crossed by the liner. Before a decision is made on use of a liner, the strength of the top part of the last full string must be checked against the new maximum expected surface pressure. Unless proven otherwise by cement bond evaluation tools, the upper pipe strength alone (no assistance from the cement sheath) must be capable of withstanding the pressure. If the upper section will not withstand the forces, it should be protected by running a full string, or, the string should be run before perforating the well.
The first approach liner design is the same as for full casing strings. The collapse, burst, and tension safety factors and design equations are the same. The basic differences between liner and casing design come to light in the design of liners for deep wells, hot environments, and very high pressure zones.
Burst failure of liners is usually caused by kicks while drilling below a liner,39p40 pressure when fracture stimulating, or a tubing leak while producing a deep, high pressure zone. All these factors are made worse by a poor cement job. Since filling the casing/openhole annulus with cement significantly strengthens and supports the pipe, a good cement job over high pressure or earth movement zones is a requirement in any deep well.
An illustration of the complications caused by a poor cement job 39*40 is illustrated in Figure 2.22. After a primary cement job on the 9-5/8 in. string, the 6-518 in. liner is run and a circulation cement job is initiated. The low pressure zone at 13,800 breaks down while cementing, returns are lost and the cement top peaks at 13,400 (Figure 2.23a). A top squeeze with cement seals the top of the liner but leaves an uncemented zone from 13,120 ft to 13,400 ft (Figure 2.23b). While drilling near TD to test a deep structure, the temperature of the mud goes from 270" (temp. of the zone at 15,400 ft) to the bottomhole temperature (at 18,500 ft) of 345°F. Since both ends of the liner are cemented, stress will be induced by the temperature rise
Liner Tie-Backs
Although the liner completion described in Figure 2.22 may be used only as a liner, there are some conditions when the liner may be run back to surface. This liner tie-back may be temporary, to protect
permanent casing strings from wear during drilling4' or permanently, with cement, to strengthen the casing string through a high pressure zone or isolate and stop a casing leak38 or a leaking liner top.42 To allow a tie-back, most liners are equipped with a liner tie-back receptacle. The receptacle is an internally polished receiver that will accept the seal assembly of the tie-back liner. The tie-back liner usually incorporates some type of cement port or sliding sleeve and seat that will allow cement to be circulated through to the annulus and up the annulus to surface. The seat, float equipment andlor plugs used in the cementing operation are of drillable material.