The success of an oil- or gas-field development rests on the performance of numerous crucial items of equipment. But if asked to select one for special mention, there are good arguments for nominating the well conductor. Why? Because it forms the principal foundation for the well and performs a series of cardinal roles throughout its life. It stabilizes and protects the subsurface during initial top-hole drilling operations. It supports, at least initially, the weight of the subsequent casing string (the surface casing). It bears the axial tensile loads, the shear loads and the bending moments that stem from the drilling riser, and which are transmitted through the blowout preventer, while the remaining sections of the well are being drilled. Finally, during production, it has to withstand the operational loads associated with subsea trees, production risers and other seabed equipment.

Structural integrity

Because of its important role, setting the conductor firmly in place before drilling a well is paramount. Here, we outline some of the methods used to ensure the structural integrity of subsea conductors, first in shallow water and then in the deepwater areas under development around the world.

Operators have traditionally used one of two methods to set conductors in shallow water: It is possible to drill and cement the conductor in place, or to drive the pipe into the seabed using a hammer. Drilling and cementing is the favored option where sandstone, limestone or consolidated sand is likely to be encountered. This is a well-established technique and can give excellent results.

Various factors affect the quality of the job and, therefore, the final structural integrity of the conductor, not least keeping the drilled hole as slim as possible (where good control of wash-out is important) and then ensuring thorough circulation of the cement from the bottom of the conductor back to the mud line. Meeting these objectives cannot always be guaranteed, and so UWG (a partner of CIS's within Acteon) has developed a novel top-up cement system to inject additional cement down the outside of a conductor to fill the region from the mud line to about 66 ft (20 m) below the seabed. This cost-effective, simple process has been used by several operators to provide security against inadequate cementing. For example, Total has used the technique to good effect in several wells in its Elgin and Franklin fields in the UK North Sea.

Geohazards

No amount of drilling and cementing best practice can fully protect drilling operations from shallow geohazards such as unstable formations or water or gas flows. These can cause channels or cavities to form around the conductor as it is being drilled and that will adversely affect the quality of the cementing process. If you add to these potential pitfalls the drawbacks of openhole drilling (the increased likelihood of hole collapse as depth increases, and seabed contamination by the drilling cuttings), it is easy to see why operators might be amenable to alternative conductor installation techniques.

Where seabed conditions permit - that is in predominantly clay-based soils - driving the conductor into place offers many advantages. It is generally possible to force the conductor farther into the seabed than by drilling. Furthermore, because subsurface disruption is minimized, high structural integrities can be achieved as soon as the conductor is installed. Crucially, this may lead to a reduction in the number of casing strings needed in the well, which lowers construction costs or enables a greater total depth to be reached.

In addition, shallow geohazards generally pose fewer problems when a conductor is driven (assuming it is closed-ended), and seabed contamination is reduced compared with openhole drilling. If you add the possibility of driving conductors from low-cost vessels, then the technique becomes very powerful.

It is not all good news. Geological uncertainty is more of a worry when conductors are driven. Unforeseen sand layers can be difficult to penetrate, and in weaker structures the conductor may go into free fall - a major headache if a mud-line suspension system is planned and the conductor needs to be precisely positioned.

Comparing the two techniques in isolation has limited value, of course, since the geological conditions surrounding individual wells will have a sizeable impact on the techniques' relative suitabilities. However, both options have their strengths and weaknesses, and decision-making must be based on careful judgement.

Deeper water

Conductor installation in deeper water presents greater challenges. Drilling and cementing is established, although in the soft sediments often found in deep water, jetting conductors into place is also favored, especially in the Gulf of Mexico.

Jetting is generally faster than drilling and cementing and results in good structural integrity in normally consolidated clay-based sediments - once the surrounding subsurface has had time to reconsolidate. It is this reconsolidation that presents the main risk with jetting. Careful control and monitoring of the jetting operation are important to avoid excessive disturbance of the subsurface, especially if shallow geohazards or weak structures are encountered, or if the conductor becomes temporarily stuck. Furthermore, the reduced ability of the subsurface to reconsolidate as you go deeper typically limits the conductor's depth of penetration to about 262 ft (80 m).

Given the nature of the deepwater sediments, driving conductors to depth seems to offer a reasonable way forward. To date, however, the technique has not been widely adopted. The principal hurdle has been the availability of a hammer that can be deployed at the seabed in deep water which, crucially, depends on moving away from traditional designs that rely on hydraulic operation.

Hammer

A subsidiary of the company has devoted considerable research and development to this area and has developed a hammer that employs a gas-lift mechanism to create the driving force and that has a compact, built-in electric power supply. This hammer has already been used for a range of deepwater pile-driving projects. Good examples are a series of 96-in. mooring piles driven in 2,625 ft (800 m) of water for the Genesis spar platform, and several 84-in. mooring piles driven for the Magnolia tension-leg platform in 4,659 ft (1,420 m) of water, both in the Gulf of Mexico. These projects used a 500-kJ hammer to drive the piles more than 328 ft (100 m) into the seabed.

So far, the subsidiary has carried out two driven conductor projects in deep water, a 36-in. conductor in the Ursa field in 3,937 ft (1,200 m) of water in the Gulf of Mexico and a 30-in. conductor in the West Seno field in 3,363 ft (1,025 m) of water offshore Kalimantan, Indonesia. The penetrations obtained were about 98 ft to 131 ft (30 m to 40 m) using a 200-kJ hammer to top-drive the pipe in one complete section. Concerns about possible buckling of conductors under these installation conditions have limited this type of application, but technical work continues.

The goal is to develop a system of driving conductors from a low-cost vessel to about 820 ft (250 m), a typical casing depth in water deeper than 6,562 ft (2,000 m). In addition to further developing its existing underwater hammer, engineers are investigating toe-driving (as opposed to top-driving) the pipes and the use of friction-reducing coatings to bring down the force needed to drive the conductors through the subsurface.

Challenges

And these are not the only issues to be resolved. Ways of dealing with sand layers, which are extremely difficult to penetrate, are also being examined. Pipe handling also needs to be addressed - whether to use single lengths of pipe, when the potential for buckling is high, or to install the conductor in sections, when the main challenge is making the pipe connections at the seabed.

The challenges to be overcome in driving conductors should not be underestimated, but neither should the advantages of being able to drive conductors to substantial penetrations in deep water. Speed, fewer problems from shallow geohazards, the elimination of cuttings on the seabed, the high structural integrity that gives greater opportunity to optimize casing strings, and the possibility of working from a low-cost vessel all make the technique worthy of attention.

At the start of this article it was argued that the conductor was possibly the most influential item of equipment in an oil- or gas-field development. Everyone will have his or her own view on this, but ensuring a strong foundation for high-performance wells will undoubtedly continue to provide challenges for operators as well as potential opportunities for the more creative companies in the service sector.

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