Conductor systems suitable for deepwater and harsh-environment jackups must account for increased wave and current loading, greater casing weights and the influence of jackup movement.

Until recently, the majority of wells drilled using jackups in the UK North Sea were in relatively shallow waters, and many of the wells had no tension applied to the conductors. Use of jackups has expanded from simple wells in shallow waters to depths of 330 ft (100 m) or greater with more complex well configurations. Such operations demand more exhaustive conductor system design.
General analytical concerns
For a well drilled by a jackup, the main loads of interest are axial and bending loads.
The axial loads are generated by any surface equipment, the internal casings hanging from the surface wellhead or drill pipe from the blowout preventer (BOP) and the tension applied by the jackup to the well system.
For analysis purposes, these axial loads can be split into internal and external loads. External axial load can cause a system to buckle, whereas an internal load cannot. However, an internal load will reduce the system's ability to withstand external buckling loads.
Similarly, external bending loads are generated by the environment (waves and currents) and relative deflection or movement of the jackup or platform, whereas internal bending loads are generated by internal casings hanging in an eccentric manner inside the conductor.
For wells where the conductor system is in tension, buckling instability is not of concern. Instead, only the acceptability of the system from a strength standpoint need be checked.
If all or part of the system is in compression, a buckling check must be performed. The industry standard approach for this is the Baur and Stahl technique developed at Amoco in the 1980s1 and refined by Imm2 and Manley.3
This technique is described in the new Institute of Petroleum (IP) publication "Guidelines for the analysis of jackup and fixed platform conductor systems."4
Conventional wells
Conventional wells generally consist of a separate tensioned outer conductor and surface casing supporting the surface wellhead and BOP. The conductor typically is tensioned using a hydraulic conductor tensioning unit (CTU) pushing upward from the Texas deck onto a load ring, which is typically clamped to the conductor. The surface casing is tensioned using a conventional overhead (secondary) tensioning system, applying load to the surface equipment. A mudline suspension system typically is used to support the casing weights below the mud line.
The maximum bending moment within the conductor usually occurs at the lower end, at the conductor-soil interface. In deepwater wells, this bending moment may be of a magnitude where an increase in steel yield strength or pipe diameter may be required.
It is likely that tensions applied to the conductor to obtain acceptable bending moment levels during the 50-year storm conditions will be large - in many deepwater cases about 600 kips. This may have operational impacts as not all jackups have the capability to apply primary tensions of this order. However, it does have the benefit that the conductor will be in full tension and thus cannot buckle.
If the starter head is placed on the surface casing, the surface casing will have to support the full weight of any surface equipment along with the loads generated by the internal casings.
Because the weight of the BOPs on most deepwater jackups is large, it is unlikely a standard 20-in. surface casing would be able to support this weight without buckling inside the conductor. Therefore, tension usually is applied to support the surface equipment weight. Any residual tension may begin to overcome the distributed mass of the surface casing and internal casings. It is possible that the surface casing will have to be checked for acceptability from a buckling standpoint.
In most cases, it is likely the loading from internal casings is not excessive as the wells may have a mudline suspension (MLS) system to allow re-entry.
In the majority of deepwater jackups, the tensioning system keeps the conductor and diverter vertically aligned as the CTU is constrained from horizontal movement. When the conductor deflects, the conductor rotates at the CTU elevation. The surface casing also deflects because it is inside the conductor; therefore it is no longer vertical as it exits the conductor at some point above the CTU.
However, due to the location of the diverter, the surface casing, wellhead and BOP must bend back in an opposite direction to the conductor. As the BOP and wellhead are generally much stiffer than the surface casing, it is the surface casing that has to accommodate the majority of the resulting curvature (Figure 1). The surface casing's deflected shape causes it to potentially contact the inside of the conductor, which could lead to wear or local damage, reducing its pressure capacity and structural integrity.
Contact can be avoided by placing a centralizer on the surface casing to provide a rigid standoff between it and the conductor. However, if the centralizer is placed too close to the top of the surface casing, the length of casing left to accommodate the curvature may be too short and lead to a stress overload. If the distance is too long, contact occurs between the surface casing and conductor. Solving these mutually conflicting requirements is one of the key problems for this type of well.
Another concern for a conventional deepwater jackup well is fatigue, particularly if the well is to be tied back later. The bending loads generated by waves tend to be focused around the lower fixity of the conductor and the upper end of the surface casing around the uppermost internal centralizer, or the surface wellhead.
In addition to wave-induced fatigue, it is possible that a tensioned conductor system will be sensitive to vortex-induced vibration (VIV). If VIV occurs, some form of suppression device such as a strake may be required, but that would increase the drag loading on the conductor significantly, and this would have to be accounted for in the main structural analysis.
High-pressure riser system
A single-string, high-pressure jackup riser system usually is combined with a conventional subsea wellhead, therefore it would require a minimum bore of 181/2 in. to allow casing hangers and seals to be run into the subsea wellhead. A surface wellhead usually is placed directly on top of the riser, with the pressure control equipment (usually an 181/2-in. BOP) placed on top of that. Tension usually is provided to the riser, either by using a hydraulic CTU pushing upward from the Texas deck to a load ring clamped to the conductor or a more conventional overhead tensioning system to apply load to the riser.
Unlike the conventional well system, where the pressurized strings usually are distinct from the strings subjected to the axial and bending loads, a high-pressure riser string must support pressure and bending loads. However, no internal casing loads will be present. Therefore, provided that the tension applied by the jackup is at least equal to the weight of the riser and surface equipment, the well cannot buckle and only a strength failure is possible.
As the minimum bore in a riser that will provide full-bore access to a conventional subsea wellhead is 181/2 in., the stresses induced by internal pressure can be large. To maintain an acceptable weight for a 40-ft (12-m) joint by limiting the wall thickness, the maximum working pressure of such a steel riser is about 5,000 psi to 6,000 psi.
The high-pressure riser is similar to the conventional well in that high bending loads are generated at the lower fixity and at the upper end, where the riser system interfaces with the surface wellhead. As for a conventional well, high tensions may be required to reduce the bending loads to acceptable values.
It also is likely the bending loads at the upper and lower end of the riser will be large enough that some form of stress joints will be required. As the bending load can be far lower toward the middle of the riser string, it is more economic to use high-strength "stress joints" at the riser terminations rather than construct the entire riser out of high-grade material.
High bending loads at the upper end require careful selection of surface equipment. Experience has shown that 10,000-psi or 15,000-psi subsea and surface equipment may be required - even though the riser system is limited to 5,000 psi - to withstand the bending loads placed upon it.
A high-pressure riser system can suffer from the same VIV and fatigue issues as a conventional jackup, with the interface between the riser and the surface equipment being susceptible to fatigue damage depending upon the type of tensioning system used.
Cantilever mode
Wells drilled in cantilever mode usually take the form of a 30-in. or smaller conductor containing a surface casing, with the starter head, wellhead and BOP placed on either the conductor or surface casing. The system usually is untensioned, relying on the conductor guides in the platform jacket to provide support.
Of the three well configurations discussed, this is the most analytically complex. As the conductor and possibly the surface casing are placed in compression by the surface equipment and internal casings, the acceptability of the conductor system in both strength and stability must be determined.
If the conductor is acting as the main structural member, it will be supporting the full weight of any surface equipment and the internal casings. In underbalanced drilling operations, the surface equipment weight can be considerable - two to three times the weight of a standard surface BOP stack. Similarly, for some high-pressure, high-temperature wells, the weight of the internal casing strings may be high.
The conductor usually is not tensioned in this well configuration and relies instead on support from the platform guides to provide stability. If the platform design is at the conceptual stage, there is a possibility that the platform can be modified to suit the optimum well design. In most cases the platform design is fixed, or indeed the platform is in place and the well must be designed to suit the platform. In these situations, the old rule of thumb that a conductor pipe can tolerate about 1 m of span between conductor guides for each inch of pipe diameter is a good starting point.
The other possible layout for this well type is with the surface casing freestanding inside the conductor and the starter head on the surface casing. With this layout, it must be demonstrated that the internal and external axial plus bending loads will not cause the surface casing to buckle inside the conductor, and that the combined system is also stable.
The surface casing usually can be stabilized by fitting one centralizer to each joint of casing to give an effective free span of 40 ft (12 m). However, even with the surface casing stable, the system can still buckle, even if there is no direct axial link between the conductor and surface casing. This composite conductor/surface casing section also must be sufficiently stable, a requirement that is sometimes forgotten.
Regardless of the location of the starter head, this well configuration probably will require the use of internal centralizers on the surface casing and production casing.
In addition to buckling, bending is a prime concern for a well drilled in cantilever mode. Bending can be caused by deflections of the jackup or platform relative to one another.
For the majority of cases, it is difficult to predict accurately the motion that will occur in a jackup. If the additional complexity of hydrodynamic loading of a platform in close proximity is added, the task becomes nearly impossible under normal time and cost constraints.
The normal analytical approach has been to apply a series of relative deflections, up to a value in excess of the anticipated maximum, and assess the implications. At each value of relative deflection, key areas within the conductor system are checked to ensure they are not overloaded.
Usually, these checks are performed on the conductor and surface casing and associated connectors, the surface wellhead and the interface between the BOP overshot and diverter.
For these checks it is important to consider the full load history when the well is being drilled and capture cases where large internal pressures or thermal loads may be present.
The overshot-diverter interface needs to be checked, as it demonstrates a change of state when relative deflection occurs. At low deflections, the overshot acts as a pinned connection with the mandrel rotating inside the diverter. At higher values of relative deflection, the overshot-diverter assembly locks up and acts as a rigid connection, potentially generating a large level of bending load along the surface equipment (Figure 2).
Once each key area has been checked, the limiting allowable offset of each component can be determined. Once this is known, the actual relative deflection can be monitored, and if critical values are approached, the conductor system can be disconnected from the jackup, removing the potential for relative deflection.
Separating the conductor system from the jackup, however, also removes the lateral support provided by the jackup. Therefore, a temporary support will have to be supplied to the conductor system (near the BOP) to ensure stability while the system is disconnected from the jackup.
This configuration also can suffer from VIV, but it is generally unlikely as the natural frequencies of a platform conductor system usually are distant from the values that will cause excitation. However, it is an area that should be reviewed nonetheless.
The fatigue endurance of this setup is usually good. However, the cyclic bending load resulting from the relative deflection must be accounted for in any fatigue analysis performed, as this can be more significant than the long-term fatigue damage caused by wave loading. This is particularly true with regard to surface equipment components and the wellhead-to-conductor interface.
It is clear that deepwater jackup wells require detailed, case-specific analyses that consider the well's full life cycle.
The input data questionnaires published in the IP's guideline document are helpful in this regard.4
References
1. Stahl and Baur: "Design Methodology for Offshore Platform Conductors," Paper OTC 3902, published by Society of Petroleum Engineers.
2. Imm and Stahl: "Design of Concentric Tubular Members," Paper OTC 5836, published by Society of Petroleum Engineers (1988).
3. Manley: "Design Methodology for Offshore Platform Tieback Conductors," Paper OTC 5049, published by Society of Petroleum Engineers.
4. Institute of Petroleum: "Guidelines for the Analysis of Jackup and Fixed Platform Well Conductor Systems," (2001).

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