Mike Churchill
Churchill Drilling Tools
A comprehensive, compliant downhole barrier implementation strategy is paramount for any well operation. This is even more critical indeepwater, where the risk factors and complexity are often multiplied many times over. Within the confines of both external and internal regulatory controls the operator has to choose the most appropriate way to protect the rig and crew from the gas in the formation. Installing non-return valves (NRVs), commonly referred to as floats, in deepwater drillstrings has delivered significant time and cost savings without compromising the fundamentals of well control.
When the string is in open hole various protection barriers are normally in play aside from mud weight and the BOPs at surface. Floats placed inside the drillstring, often just above the bit for maximum bit-plugging protection, should close out any risk of influx from the formation when the pumps are off (the most common arrangement for making and breaking connections). However, if a major situation arises, pumping may either be impossible or undesirable. In this case the loss of the circulation as a barrier makes it vital that the floats are in working order. No intervention will be required from the crew, the floats should shut the instant there is any reverse flow and hold any influx at bay. Typically, a pair of floats will be installed for insurance against the potential failure of one.
Whenever the string is being lowered into hole, the operator will see that the floats are working by correct displacement of annular fluid from the hole. This should occur at a volume equal to the volume of pipe being inserted into the hole. However, while this is a useful positive indicator there is also a significant downside. When running into hole (RIH) “fully floated” the pipe is prevented from self-filling, leading to a void of air at the top of the string that becomes longer and deeper with each stand that is run in. Unless the pipe is filled from the top, the hydrostatic differential pressure on the pipe, with air on the inside but mud at great depth on the outside, will crush the pipe.
Top-filling the pipe is analogous to trying to pour water into a drinking straw – perfectly possible, but very slow and messy depending on the technique. Mud spillage on the rig floor adds cost and risk, but more significantly, the slow filling of the pipe can add many hours to the RIH process, especially in deepwater.
One option is to use ported floats, containing a small bleed-hole that allows a slow equalization of pressure and gradual filling of the pipe. However, by definition ported floats are not proper barriers and in any case, even assuming the ports do not plug with cuttings from the hole, the fill rate is unlikely to be fast enough to remove the need to top fill completely. So while floats offer invaluable protection they also introduce additional complexity, time and cost, especially to the RIH process.
Contingency scenarios
For operators drilling deepwater and HP/HT wells, heightened safety concerns have increased the requirement for running floats outside cased hole in any phase exposed to the formation. This has extended to contingency scenarios and even perhaps contingency-on-contingency scenarios. For example, there might be a secondary flow path into the bottomhole assembly (BHA) bypassing the installed floats. This could be the opening of a bypass valve above the floats to cure losses, for example. A risk assessment may conclude that floats should be placed above the valve in certain situations.
A drop in check valve (DICV) is a standard piece of well control contingency equipment which is also a non-return valve. However, unlike the conventional float that is permanently installed in the sub, the DICV is dropped into a landing sub only when the added barrier is actually needed. The landing sub would typically be placed above the BHA and any conceivable leak path. But although effective in an emergency, it is costly to use because once dropped it restricts access to tools in the BHA and restricts pumping at full flow until it is fished back out. Deployment of the DICV is therefore to be avoided if possible.
Middle: Self-filling float in flapper configuration.
Bottom: Self-filling float in poppet configuration.
An example of a multiple-contingency scenario is stuck pipe that could not be freed, requiring severance of a lower part of the drillstring with the consequent loss of the float protection in it. The fact that there might be no float between the rig and the formation would also be a major concern in the planning stages.
Another driver for float demand is the narrow pressure windows that are commonly addressed via techniques such as under- balanced and managed pressure drilling. Where the barrier of mud weight over balance is removed, maintaining a rigorous float regime becomes even more critical to protect against deviations in the pressure that might lead to problems.
Self-filling float solution
Non-pump-able, self-filling floats have been available for some time. Essentially the float is dormant during RIH but when pumping begins the hold-open mechanism is dislodged and the float becomes active. One drawback is that shallow-hole testing of the MWD, for example, is not possible because pumping to test the MWD at the beginning of the RIH would activate the float and prevent any further self-filling from taking place. The inability to pump and test can be extremely costly if it means set-up issues are only discovered when on bottom, particularly in deepwater.
In 2012,Churchill Drilling Tools introduced the first dart-activated self-filling float. This was designed to overcome the previous hold-open limitation by providing full pumping capability. When approaching activation depth, a dart dropped and pumped into the sub would shear out and activate the system. Previously, the floats would be placed just above the bit, but in this new configuration they must be above the MWD to give the dart a thru-bore to reach the sub.
Although the industry broadly welcomed this development at the time, uptake initially was fairly limited, based partly on the perceived costs and risks of procedural changes in a $100/bbl environment. Four years later, however, a completely different environment has emerged, with demand growing strongly for this simple technology in deepwater operations, underlining the cost benefit of making the change in procedure. Across 10 different deployments self-filling RIH has been performed down to measured depths ranging from 13,000-21,000 ft (3,962-6,401 m). This has meant that RIH to the casing shoe or to the completion is being performed at full speed, with activation of the float only taking place just before the permanent barrier is about to be removed.
In these runs, versions of the tool deployed included 6¾-in., 8¼-in. and 9½-in. sizes, at angles up to 40° and activation shear-out pressures in the 600-700 psi (41.4-48 bar) range. A typical sequence of top-filling every 10 stands or 1,000 ft (305 m) of pipe RIH might take up to 20 minutes depending on the top-filling methodology. By mid-September, with median activation at depths around 18,000 ft (5,486 m), time savings for this year’s deployments have been up to 6 hours per RIH. In each case the operator selected the flapper float format.
An alternative version of the system is the more rugged, poppet type format, where centrally mounted high strength closing springs and tungsten carbide pistons with a ceramic seal interface provide a robust design. In the majority of cases, however operators prefer the flexibility of thru-bore access offered by the flapper type format.
A new development is a large bore version of the self-filling float, known as the DURA (double upper reserve activating) drill float. This allows a dormant flapper float to be run even higher up the string within the drill pipe for potentially critical contingencies. One of these is as a back-up to the primary floats, which if damaged during drilling may require a trip for replacement. Activating the DURA drill float could save a replacement trip or enable allow a much safer exit from the hole. Another scenario is where the primary floats have become bypassed by a flow path into the string above them. This could be due to circulation bypass, tool failure, twist-off, or in an extreme case, stuck-pipe severance. In all of these contingency scenarios the DURA drill float will provide the option to recover to floated state without losing pumping capability.
