Putting HSE in MPD

There’s a growing acceptance of MPD in offshore operations, but are all options being considered? Jerry Lee examines the RFC-HSE variation.

AFGlobal’s riser gas handling system is integrated with the drilling riser to mitigate the breakout of formation gas and enable an easy transition to MPD.Photo from AFGlobal.

North America was the largest market for managed pressured drilling (MPD) in 2015, due to its extensive use in the Gulf of Mexico (GoM), according to an April 2016 report by research firm MarketsandMarkets. The firm sees the trend continuing to 2021, when it expects the global MPD services market to reach a sizable US$4.6 billion.

The GoM has benefited from MPD technology, but to realize MPD’s full potential, all applicable variations must be considered. Constant bottomhole pressure (CBHP) and dual gradient drilling (DGD) have dominated the MPD conversation, due to their ability to drill “undrillable” wells. These methods have done well for pressure sensitive situations. However, the returns flow control variation for health, safety, and the environment (RFC-HSE) may be more applicable. Unlike CBHP and DGD, RFC-HSE is only used with conventional (overbalanced) mud, which means conventional drilling operations can take advantage of MPD benefits.

MPD

Rig owned buffer manifold allow for the integration of MPD and Riser Gas Handling systems. Photo from SafeKick.

Well control methodologies have minimally evolved since the early 1900’s, relying solely on hydrostatic pressure [derived from the annular fluid column during static (non-flowing)] condition, and – to a certain extent – annular frictional pressure [derived from a surface resisting flow during dynamic (flowing)] conditions, to keep formation pressures at bay. Normally, when hydrostatic pressure is insufficient, issues arise (e.g. non-productive time, stuck pipe, gas kicks, narrow fracture margins, loss of well, etc.), however, now these issues may be mitigated with MPD.

MPD creates a closed-loop system and enables the driller to manipulate surface back pressure (SBP) to manage the annular hydraulic pressure profile. The minimum equipment required is a rotating control device (RCD), a choke manifold, and at least two drill string non-return valves. Positioned above the blowout preventer (BOP), the RCD can isolate the annulus between the wellbore and pipe, creating a closed-loop system, while allowing the pipe to be rotated and reciprocated. When the annulus is closed, the returning fluid is diverted to the choke manifold at the outlet of the well. The choke can then be adjusted to create and manipulated SBP, giving the driller more precise control over equivalent mud weight (EMW) – the hydrostatic equivalent to the total pressure created in the wellbore.

RFC-HSE

Unlike other variations, RFC-HSE is specifically used to enhance process safety while drilling with conventional fluids. RFC-HSE allows drilling to occur in a closed-loop system; diverts returning fluids to the choke manifold; enables early kick/loss detection; limits the size of kicks/losses; allows the driller to perform dynamic formation integrity tests and leak-off tests; and provides riser gas mitigation capability.

To apply this MPD variation in the GoM, rigs will require the basic MPD equipment mentioned above as well as Coriolis flow meters. For convenience, a programmable logic controlled choke system and associated software, such as SafeKick’s SafeVision rig package, will automate the choke system and allow for more precise control of annular pressure, at any depth in the well. In that situation, the choke control software serves as the system’s interface, allowing the driller to control the MPD system and model annular conditions. The Coriolis flow meters, located at the inlet and outlet of the system, are sensitive to variations in fluid density and temperature. By inputting data from the Coriolis flow meters into the control software, real-time wellbore analysis and control (including EMW) is enabled.

Process safety

When the RCD is closed, a closed-loop system is created, like a pressure vessel, giving the driller better control over the annular pressure profile than an open-to-atmosphere system would. The closed RCD also diverts the returning fluids to the choke manifold, away from the drill floor where rig hands are working.

If there are changes in mud flowing into or out of the well, the Coriolis flow meter will immediately recognize and display the change: more volume flowing out of the system than in may represent a kick; more volume flowing into the system than out may represent losses. This deviation acts as an early kick/loss indicator, allowing the driller to react to the event quickly and in real-time. In response to the volume flow deviation, the driller would only need to increase the choke pressure – increasing the SBP and EMW – to stop or minimize the kick, or decrease the choke pressure – decreasing the SBP and EMW – to stop or minimize flow into the formation, resulting in a smaller kick or loss size that the crew needs to manage.

In comparison, conventional methods require visible changes in mud tank for kicks/losses to be identified, which would be in barrels, rather than the gallons it would take an MPD system to identify.

Furthermore, because SBP can be manipulated while the system is flowing, dynamic pore pressure tests, dynamic formation integrity tests and leak-off tests can be performed. With these capabilities, the driller can ascertain more information about the well, decreasing uncertainty and risk.

Rig owned MPD choke and meter manifolds. Complete with duel 3in and 6in chokes and duel 8in Coriolis meters. Photo from SafeKick.

Riser gas mitigation

Riser gas can be troubling for any drilling operation using subsea BOPs. If gas gets into the riser, it can quickly come out of solution, expand, and lead to an unloading event, which can cause a blowout, collapse of the riser, or environmental and legal issues, says Bo Anderson, vice president, advanced drilling systems, AFGlobal. However, with a riser gas handling system (RGH) installed in the riser string, the risk can be greatly mitigated.

An RGH system is comprised of a drillstring isolation tool (DSIT), a flowspool, and riser crossover joints.

Integrated into the riser using the crossover joints, the DSIT can close the annulus between the riser and drillstring and redirect the returning fluids through the flowspool. The flowspool, which has two exiting lines, can then divert the flow to the rig’s mud gas separator or to a choke, allowing control over the pressure seen at surface. With this system, the driller is given the capability to control the amount of flow from the riser. Additionally, if is sized properly, the RGH is the key component that enables MPD to be deployed on a floating rig, says Mark Mitchell, president, oil and gas, AFGlobal.

Rig owned MPD choke and meter manifolds. Complete with duel 3in and 6in chokes and duel 8in Coriolis meters. Photo from SafeKick.

“Our riser gas handling system is the essential building block for MPD in deepwater,” Mitchell says. “From an equipment standpoint, it gives you the platform to install the RCD, the flowpath needed for MPD, as well as serving the function as a riser gas management tool.”

With an RGH installed in the riser, an RCD can be integrated into the riser string, above the DSIT. Then, when the RCD bearings need to be replaced, the DSIT will isolate the RCD and the flowspool will redirect the returning fluid.

These necessities not only result in an inherent riser gas mitigation capability, but when combined with the flowmeters, like those used in RFC-HSE MPD, the driller also has a riser gas management tool. With the flowmeters providing early kick detection, influxes can be seen early, allowing the driller to start thinking about and making accommodations for handling them, Anderson says.

“Riser gas management then changes from a reactive solution to a proactive solution,” Mitchell adds.

There are additional benefits available with RFC-HSE, such as well breathing identification, ability to circulate out small influxes at drilling flow rates, the ability to monitor tripping operations, mitigation of wellbore instability issues, and the ability to provide managed pressure wellbore strengthening and managed pressure cementing.

BSEE well control rules

New well control rules from the US Bureau of Safety and Environmental Enforcement went into effect July 2016. These rules are intended to increase offshore safety. Although, some rules may inhibit some drilling operations. One such rule, Section 250.414(c), requires the implementation of a 0.5ppg drilling margin – unless the operator can justify deviating from the drilling margin through supplemental data and other documentation – which could result in previously drillable wells becoming “undrillable.” However, regulators specifically changed the 0.5ppg margin from static mud weight, to EMW, which seems to invite the use of MPD.

This is good news for US GoM operators, however, because CBHP and DGD operations are still only approved on a case-by-case basis. On the other hand, since RFC-HSE is used to augment conventional drilling programs, it would not require pre-approval, allowing drilling contractors to freely utilize this technique to operate more safely, and potentially use some of the fringe benefits of MPD.

Rigs equipped for RFC-HSE MPD could capitalize on the 0.5ppg EMW drill margin, drilling wells closer to balanced pressure, which improves drilling efficiencies. In addition, if an influx occurs the driller’s response could then be based on the real-time information about the mud weight, rather than relying on old pre-drill estimates. Applying SBP would increase EMW above the formation pressure, which would not only stop the influx, but would also allow the actual formation pressure to be determined.