Use of Managed-Pressure Drilling Requires Adjustments To Bridge Gap to Well Control
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Managed-pressure drilling (MPD) challenges the conventional drilling paradigm, along with drilling-contractor and operator policies and standards. Conventional drilling practices for connections, flow checks, tripping, and well control have been long understood and standardized both onshore and offshore. The addition of an MPD system to a drilling operation, inclusive of the recommended practices, requires bridging the gap between conventional policies and standards and those of MPD.
Often, an MPD bridging document that supplements the standard drilling-contractor and operator bridging document is seen as an operational requirement. The drilling contractor remains responsible for well control and well monitoring. The driller will continue to monitor the well at all times, using standard operating procedures while observing key drilling parameters.
The MPD system provides enhanced well-control-event-detection methods in addition to standard downhole-event-detection methods. In addition, it allows rapid and accurate control of bottomhole pressure (BHP), but it does not replace standard drilling-contractor or operator procedures during well-control events.
Depending on the MPD-system availability and capabilities and the actual well conditions, most operators use several MPD techniques on the same well. The techniques may include conventional drilling with riser-gas-handling capabilities, dual-gradient dynamic-mud-cap drilling, pressurized-mud-cap drilling, floating-mud-cap drilling, or applied-surface-backpressure MPD. All of these fall into the group of techniques now referred to in the industry as MPD.
Depending on the technique used, the mud density might be statically overbalanced, meaning that the hydrostatic pressure alone exceeds the highest formation pore pressure exposed, or it might be statically underbalanced, meaning that hydrostatic pressure alone may be less than the highest formation pore pressure exposed and the well is kept overbalanced by applying backpressure at surface.
Well-established corporate policies have guided conventional drilling practices with respect to operational issues such as kick-indicator response, frequency of equipment testing, fingerprinting, and proactive kick-minimization techniques. Although MPD serves the same purpose as conventional drilling—to drill a section safely overbalanced—its use requires procedures that deviate from established policies.
Conventional Drilling. For conventional drilling techniques, a minimum of two independent and tested barriers must be in place at all times. Upon failure of a barrier, normal operations must cease and not resume until a two-barrier position has been restored.
Barriers are called operational, or secondary, barriers if they require human recognition and response to intervene and stop the flow once formation fluid enters the wellbore.
MPD. The addition of MPD equipment on a rig is meant to enhance the primary-barrier envelope while remaining independent of secondary-barrier equipment. The basic difference between MPD and conventional drilling is the introduction of a closed-loop circulation system to the rig equipment in contrast to a standard rig’s open-loop, or atmospheric, system.
During MPD operations, the primary barrier includes all elements that allow a downhole pressure greater than the pore pressure of the exposed formations.
Pressure and flow fluctuations that exceed the design limits of the primary-barrier equipment imply that the envelope has been compromised, and subsequent actions would require the use of secondary-barrier equipment. These subsequent operations are commonly referred to as “well control.”
Guidance regarding the handover from normal MPD operations to well control should be included in an MPD-operations matrix or influx-management envelope. In compliance with local regulatory standards, the number of barriers during MPD and their testing should be established by the operator.
Use of Riser-Booster Pumps
Conventional Drilling. Often, drilling policies during connections and while tripping preclude the use of the riser-booster pump when drilling into new formations. One reason not to boost the riser when drilling into a new reservoir is to be able to maintain proper control of hole volume when potentially permeable formations are encountered.
MPD. In MPD applications with a surface blowout-preventer (BOP) stack, a separate backpressure pump (often called an MPD auxiliary pump) often is used during drillpipe connections to maintain constant BHP. The system compensates for the loss of annular friction during a pumps-off event, replacing it with friction through the choke restriction while circulation at the surface is maintained. The pump takes fluids from a suction tank and discharges upstream of the MPD choke. The combination of flow rate and choke opening creates the additional backpressure required to maintain a constant BHP.
The same method can be implemented by using the booster pump instead of an auxiliary pump to maintain BHP control.
Response to Kick Indicators and Kill Method
Conventional Drilling. In conventional systems, the primary response to a kick indicator is to shut in the well immediately and limit the volume of formation fluids in the well.
MPD. For pressurized systems, the primary response to an influx will be to increase the applied surface backpressure immediately with the MPD system to stop or minimize the formation-fluid influx and bring the well back to being overbalanced.
If the kick size is below the matrix limits but the option to circulate dynamically through MPD equipment was not fully agreed on (between the operator, drilling contractor, and service company), the MPD system can be used to perform an assisted shut-in, further increasing the applied backpressure to compensate for the loss of equivalent circulating density (ECD), which can minimize the kick size during pumps-off operations.
Conventional Drilling. Conventional connections are relatively straightforward procedures. Pump rates are rapidly brought to a full stop, and time is allowed for the flowback from the sand traps and shakers and draining of flowlines to cease and reach static condition. The reduction of BHP because of the absence of ECD increases the chance to observe influxes while performing connections.
MPD. Performing connections with the MPD system mandates that surface backpressure be added to the system to compensate for the loss in ECD as pump rates are reduced. Most of the existing systems are able to perform such transitions automatically; however, the pump rates must be reduced slowly, allowing time for the choke to react while maintaining constant BHP.
Another aspect of MPD connections is that the annulus and riser will be under pressure, even with the pumps off, so the rig cannot perform a conventional static flow check on each connection. In this case, the flow check can be performed dynamically, maintaining the backpressure-pump or riser-booster-pump circulation into the annulus, taking returns to the surface MPD system. The Coriolis measurements of flow in and flow out are not affected by the flowback of the surface lines seen during conventional operations, which provides another benefit of MPD.
Modified Kill Procedures
Conventional Drilling. Conventional well control starts from the premise that the well is designed with statically overbalanced mud and any influx will be controlled using the driller’s method.
The driller’s method states that, once the well is shut in, the shut-in drillpipe pressure (SIDPP) and shut-in casing pressure are recorded. The well should then be circulated, keeping the standpipe pressure constant, using a reduced pump speed to circulate out the influx. The initial SIDPP is an indicator of the degree of underbalance and is used to determine the new mud kill weight.
MPD. In MPD operations, the use of a statically underbalanced mud is one of the main approaches in cases with a narrow operational window. Pore pressure is balanced continuously with variables other than mud weight, such as surface backpressure and friction. A well designed to be drilled using MPD might not accept the use of mud weight that will set the well in an overbalanced condition without the aid of surface backpressure.
In this case, the conventional method for killing the well at the second circulation of the driller’s method is neither desirable nor possible. The solution is to evaluate the degree of underbalance that will accommodate the limitations of the pressure envelope and design a new mud weight—still statically underbalanced—that will reduce that degree to a comfortable level and safety margin.
Testing of BOPs
Conventional Drilling. BOP pressure and function tests are the most important methods of verifying barrier integrity. Experience shows that a system of multiple barriers, when correctly installed, maintained, and tested, can provide a high degree of reliability. The continuous monitoring of physical barriers and the availability of appropriate operational barriers can maintain safe rig operations.
Pressure tests on the well-control equipment should be conducted on a routine basis. The legal requirements of the country shall apply whenever they are stricter than company policies.
MPD. The BOP tests in MPD operations follow the same criteria as in conventional drilling. As the primary barrier, all MPD surface equipment should be pressure tested, at a minimum, to the maximum allowable operational pressure.
During commissioning, the new surface equipment must be pressure tested and function tested at the wellsite in conformance with procedures approved by the operating company, drilling contractor, and service company.
Unique to deepwater MPD operations, the riser pressure test is included as part of the MPD tests. A riser analysis under MPD conditions should be completed during the planning stages. The riser-load analysis must consider the maximum surface annular pressure expected when drilling in MPD mode.
The use of MPD has been shown to provide numerous benefits, particularly in environments with narrow pressure margins and in high-pressure/high-temperature and deepwater operations. To obtain the full benefit of MPD and allow the safe implementation of the technology, all parties must understand where MPD operations might present a challenge to operator and drilling-contractor policies and procedures.
This is particularly critical in cases where conventional policies and procedures are not possible during MPD operations. A shift in practice from conventional drilling needs to be captured at the policy and procedural level.
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