MPD Methods: Pros and Cons of CML vs SBP

Do you want to control bottom-hole pressure (BHP) with MPD, but are unsure which method to choose? 

There are three main MPD categories and several techniques. What they all have in common is the ability to control and adjust the annular pressure. 

In this article, we look at the advantages and limitations of two MPD methods - Controlled Mud Level (CML) and Surface Back Pressure (SBP), to help you choose what best suits your operation.

What is SBP and CML?

The SBP method uses a surface choke to apply back-pressure on the well. To create a closed-loop system, a Rotating Control Device (RCD) seals around the drillpipe in the well, with a dedicated return line leading back to the flowline.

A common drilling approach with SBP is using a lower fluid density to achieve the desired Equivalent Circulating Density (ECD) profile, and then compensate for reduced friction during non-circulating periods by applying pressure using the surface choke. 

The CML method uses a Subsea Pump Module (SPM), which is connected to an outlet in the riser, with a separate Fluid Return Line (FRL) back to the rig. The SPM adjusts the fluid level in the Riser to create the desired pressure in the well.

A common approach with CML is using a higher fluid density to remain overbalanced during non-circulating periods and then compensate for friction while circulating by lowering the fluid level in the riser.

Generic comparison of pressure profiles for Controlled Mud Level (CML) and Surface Back Pressure (SBP). SBP typically creates higher shallow pressures, while CML provides a more favorable dual-gradient pressure profile.

Read more: How Does CML MPD work?

Pros and cons of SBP and CML

To choose the method best suited for your operation, you need to understand the strengths and limitations of each. Let’s look at the pros and cons of SBP and CML.

Pros of SBP:

• Can be used across all environments, both onshore, shallow water and deepwater. 
• Can be used on all rig types.
• Can circulate out an influx within defined limits.
• Can perform riser gas handling.
  
  

Cons of SBP:

• Creates pressure profiles with higher pressures at shallow depths.
• When running in hole, SBP cannot adjust bottom-hole pressure for casings, or liners longer than the water depth, or in areas where active BOP use is restricted.
• Requires the use of separate fluids; drilling fluid, tripping fluid, and in some cases cementing fluid.
• Increased rig time, with reduced tripping speeds and regular displacements .
• In case of losses, it is challenging to reduce the (BHP) unless planned for by drilling with extra low MW and applied back pressure before losses occur.
• SBP has a large footprint, requiring a choke manifold, buffer manifold, and occasionally a junk catcher, along with additional equipment and lines.
• SBP requires a more extensive rig-up process.
• Requires modifications to equipment and assemblies for operations such as completion and wireline.
  
  

Pros with CML in different situations:

• CML is frequently used across all sections of the well.
• When running in hole, bottom-hole pressure is maintained by lowering the riser level to compensate for the surge effect.
  
• In case of losses, drilling may continue with the same parameters while adjusting the Equivalent Mud Weight with fluid level reduction.
•  
• Has a medium footprint, with the main component placed subsea.
• Managed Pressure Completion can improve production rates and is straightforward to implement.
• Typically requires only a few hours to rig up.
• Enables dual gradient effect, allowing extending sections and improved pressure margins.
• Reduced rig time, primarily through faster and safer tripping.
  
  

Cons of CML:

• Cannot be used on land and has limited ability to control and adjust the bottom-hole pressure in shallow water.
• Can only be used on floaters with a subsea BOP.
• Unless operated together with a riser closure device, it relies on conventional methods for handling influx. 
  
  

Conclusion

To summarize, both CML and SBP methods offer different strengths and limitations that will affect how your operation is planned and executed. Ultimately, the right choice depends on your expected well conditions, environment, and completion requirements. Understanding how each method behaves in practice is key to selecting the approach that fits your operation.