Considering the danger of shallow steam or gas zones requires unique well control considerations. Whenever the necessary casing shoe integrity cannot be obtained due to the shallowness of the zones (before encountering pressure), a kick will need to be diverted because it cannot be shut-in. For this situation, a diverter shown in Figure 1 is a mandatory equipment to divert the undesirable flow to allow personal to have proceed the next plan; i.e., evacuation and/or dynamically kill a well.
By directing the flow from an unloading well, diverting allows physical damage to be limited to all equipment and rig personnel. With specialized procedures and equipment, the idea is to impose limited back pressure on the weak downhole formations. Although not strictly a well control procedure, diverting successfully will allow the well to be dynamically killed, to bridge over, or be depleted (without losing equipment or life).
Wherever possible, diverting needs to be avoided. In an ideal situation, if full shut-in will with a strong casing shoe should be chosen instead of a diverter. On conductor casing shoes, leak-off tests need to be performed to assess the likelihood of successfulness of shutting the well in. Any flow from the formation is likely to reach the surface in quick time since the gas is shallow and, therefore, the time available to detect the kick and then divert or shut-in is extremely small.
Purpose of Diverter System
A certain amount of protection can be provided by the diverter system before the rig can install the BOP onto the well. By design, diverter systems will direct the flow to a safe location by packing off around the drill string, Kelly, or casing. For the valves, they allow the well flow to be directed whenever the diverter has been actuated.
Diverter systems are often defined as a low pressure annular. As the name suggests, the flow cannot be stopped or shut-in with a diverter; the only goal is to direct the flow to a safe location away from the rig. To effectively remove the flow and well debris, the system must equip with a large internal diameter with sufficiently sized vent lines.
High Risk Operation
Associated with shallow gas, diverting presents serious risks. For the drilling industry, many incidents shows that shallow gas divert operations are more dangerous well control hazards than any other. Whether successful technically or not, all divert events are classified as blowouts by the US Minerals Management Service (MMS) because the very definition of a divert involves formation fluids in an uncontrolled flow. For the technical success of the diverting operation, the inherent risk needs to be managed carefully; the best management stance to risk will always be to avoid diverting at all costs.
How can diverting be prevented? Firstly, by not drilling through shallow gas. While seismic data can provide some help in avoiding shallow gas zones, drilling only where potential for shallow gas is non-existent is incredibly difficult. If drilling in this environment is entirely necessary, and the casing program cannot be designed to shut-in after kicks, not taking shallow kicks will be the only diverting avoidance technique possible.
While swabbed kicks are considered ‘avoidable’ kicks, hydrostatic imbalances that cause drilled kicks can be unavoidable with even the best planning. To reach technical success in these circumstances, an effective response plan needs to be in place and all elements of this plan need to be ready; this includes equipment, technique, people, and training.
For subsea and surface diverting, ‘Recommended Practices for Diverter Systems Equipment and Operations’ (Recommended Practice 64) is a reference document provided by the American Petroleum Institute (API). Considered the ‘API RP 64’, this is a useful resource for such events.
Criteria for Diverter or BOP
At the shoe, well integrity is often an issue with shallow casing strings and, in some cases, shutting in the well can cause too much pressure. Whenever a well with little/no shoe integrity is closed-in, this can cause formation fluids to broach to the surface or it can cause a shoe breakdown. When the shoe broaches, a bottom supported rig can be put into danger (along with its crew), including platform, jack-up, and land rig, but it won’t considered as dangerous for a floating vessel. When inadequate casing is present and a shallow gas kick is encountered in a bottom supported rig, diverting is the best alternative to shutting in.
To allow time for remedial action and potential evacuation, and to reduce the risk of damage, the flow needs to be directed as the well begins to unload. When shallow gas potential is seen, a BOP or modified BOP system should be installed before penetrating the formation. By doing this, proven well control procedures can be used. This can only occur when formation integrity will allow for the well to be killed (through the application of back pressure and/or shutting in).
When considering a diverter system over a BOP stack, there are two main considerations;
• Diverting will be preferred when insufficient formation integrity means shut-in pressure would cause damage (when drilling below conductor). If the well were to be shut-in after a kick, the formation fluids would broach the casing shoe in this scenario.
• When drilling below drive or structural pipe, diverting will be the chosen method.
As mentioned previously, wherever possible, a shut-in will always be the preferred method.
On the vent line, diverter systems should offer a full opening hydraulic valve. This valve can be opened automatically as the diverter closes when the control system is plumbed correctly, or it will add value to the closing diverter. According to industry best practices, hydraulic ball valves are the suggested types with full bore to the vent line and outlet.
API also recommend always testing upon installation; from opposite panel, a function test can occur every 24 hours. When installed, any valves and the diverter should be actuated as well as doing so at ‘appropriate times’ to ensure the system is working as expected. To ensure the lines aren’t plugged, fluid should also be pumped through the diverter lines during operation.
Diverting Operations and Equipment – Installation and Equipment Requirements
Below the mud line, a short string of drive pipe or large diameter casing can normally be installed when commencing a well in the water. On land locations, at a shallow depth, casing string can be set and cemented. With the casing or drive pipe in place, it acts as a seal to support the hydrostatic head of the fluid column – between the flow line outlet and the base of the casing. With the diverter installation occurring at the casing or drive pipe, either a low-pressure diverter is required or an annular preventer; if the latter, it requires sufficient internal bore to pass the tools used for drilling operation.
With the vent lines recommended by API RP 64, these extend between the outlets underneath the diverter and a safe space away from the well. The chosen location should allow for proper disposal of the fluid flowing from the well.
In place of proper diverters, some have previously used rotating heads or annular blowout preventers. This being said, it’s now possible to acquire special low pressure diverters in various sizes. In terms of the working pressure of the vent lines and the diverter, this isn’t too important because they’re actually sized to minimize well bore back pressure while diverting well fluids. For land and offshore uses, many Operator Companies will recommend a minimum ID of 10” for vent lines while a diameter is 12” is recommended for floaters.
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