A managed pressure drilling (MPD) project can present a seemingly endless and bewildering array of options, each of which can potentially solve numerous drilling and reservoir problems. How then can drilling engineers or project managers select from the various levels of technology to choose the proper equipment and service level to best meet their objectives?

A tailored approach involving close teamwork between the operator and the service company
 
Figure 1. Sigma Service level with automated choke, nitrogen injection and four-phase separator equipment is shown. (Image courtesy of Halliburton Sperry Drilling Services)  
with an initial focus on problem diagnosis is highly recommended. Decisions on design complexity can only be made once the specific nature of the challenge and the problems that need to be solved have been identified. In many cases, however, the operator lacks the in-house expertise to determine exactly what technology can be used. Early contact with a competent service provider and the creation of a joint project team can bridge this gap, providing an efficient method for planning an MPD project.

The right level of service
In the industry today the majority of MPD offerings can be reduced to four levels of service. Understanding the various levels and applying the appropriate service to the pressure- control difficulties can lead to a successful project without unwarranted cost.  They include Self-Managed Service, Automated Service, Optimized Service and at the highest level of complexity Sigma Service.

Self-Managed Service is the simplest level and generally includes a rotary control device (RCD) and manual choke, which the client manages. A typical operation suited for self-managed service is kick control. Unless requested, the service provider would have no personnel onsite, and the rig crew would need to be trained to monitor well conditions and to maintain equipment.

Self-managed service might also be appropriate in regions where high rock strengths and low permeability result in a low rate of penetration (ROP). A reduction of the confining stress or drilling fluid weight applied to these formations could result in an increase in ROP that could range from linear to exponential depending on the mode of operation.

Full-time supervision of the equipment is not necessary because there would not normally be pressure under the RCD and because the annulus is continually closed for increased safety. With the annulus being controlled by the RCD, the rig floor will not be exposed to any flow or hazardous gases while the blowout preventer stack is being activated. At this service level, conventional well-control methods would be used to circulate out a kick.

Automated Service is intended for situations where the pore pressure and fracture pressure are very close, allowing little room for error. In such cases, conventional drilling operations can create a situation known as “wellbore ballooning” or “wellbore breathing.” This condition occurs when hydrostatic pressure falls below the fracture-opening pressure while bottomhole pressure rises above it. During circulation, fractures open and are charged with drilling fluid; during periods of no circulation, the fractures close, and the drilling fluid returns to the well bore. The result is a cycle of losses and gains resulting in damage to the well bore.

In addition to an RCD and a manual choke, automated control software is used to manage choke manifold pressure. The resulting system is capable of maintaining bottomhole pressures within a very small mud window. Control software included with the service tabulates the various data to compute the actual choke set point and operates the choke manifold automatically to maintain it. The software provides control through communication with the choke’s programmable logic controller which, in turn, regulates a mechanical device that adjusts the choke to the desired position or pressure.

While proper pressure maintenance can be achieved using either manual or automated systems, an automated system can react with consistent speed, minimizing the severity of pressure waves, which are generated by adjusting the choke too quickly and are reflected back down the annulus. An automated system also enables a precision of control that is difficult for most human choke operators to match.

Optimized Service focuses on maximizing the effectiveness of productive time while minimizing non-productive time. To achieve this objective, experienced engineers use a suite of software applications along with surface and downhole measurements to model, measure and optimize results. Pre-drill models are generated to determine the expected conditions and are then verified and updated during drilling with actual measurements. Any differences are analyzed and acted upon if a potential problem is identified. The drilling process is then optimized based on the actual drilling conditions encountered with recommendations to improve drilling performance or eliminate problems.

In order to successfully deal with the different aspects of the drilling process, this service contains three disciplines:
1.    Drillstring integrity focuses on eliminating excessive forces on the drilling assembly while modeling natural frequencies to avoid resonant conditions. It also measures shock and vibrations, identifies any active vibration mechanism and supplies the right corrective actions to eliminate drilling vibration.
2.    Hydraulics management emphasizes controlling wellbore pressures through the use of accurate pre-drill and real-time hydraulics models and surface and downhole pressure measurements. It also addresses hole-cleaning efficiency by using predictive software analysis of annular pressures from downhole tools and by comparing predicted torque and drag trends to those actually encountered.
3.    Finally, wellbore integrity focuses on determining wellbore pressure boundaries, the upper limit of which is the fracture pressure and the lower limit of which is either the pore pressure or wellbore collapse pressure. Accurate pore pressure prediction–which hinges on knowing which of 20 pore-pressure generation mechanisms are active in the area–and knowledge of the rock mechanical properties are essential in determining these limits.
Sigma Service is recommended on wells whose formation pressure has been lowered through production. In these cases, formation pressure can be so low that any liquid-phase drilling fluid is too dense to allow the targeted bottomhole pressure to be reached. When this situation occurs, a two-phase fluid–foam, mist or gas–may be used to lower fluid density. The addition of this gaseous medium will require the installation of an upstream injection system and a downstream separation system.

The resulting rig-up will look exactly the same as if the well is being drilled underbalanced and the techniques will be the same. What then is the difference between underbalanced drilling (UBD) and MPD and why does it matter?

UBD and MPD — the difference

An operation is considered to be underbalanced when the hydrostatic head of
a drilling fluid is intentionally designed to be lower than the formations being drilled. This underbalanced condition is intended to allow the influx of formation fluids that are circulated from the wellbore and controlled at the surface. By definition then, UBD provides the benefit of production during drilling.

MPD, on the other hand, involves drilling with a controlled annulus. Returns to the surface are restricted using an equivalent mud weight and are maintained at or marginally above the formation pressure, generally by manipulating a dedicated choke device. The key point is that unlike UBD, the reservoir fluid is not intended to reach the surface.

For a reservoir or production problem, an underbalanced solution could be the best possible solution or may even be required. However, in a remote location where production cannot be handled safely and effectively or hole instability precludes underbalanced operation, an MPD approach is likely to be a better alternative. And if there are drilling problems involved, an MPD system with the bottomhole pressure targeted to be equal to or greater than the formation pressure is clearly the right approach.

A full range of solutions
MPD techniques give operators a versatile tool for solving many drilling problems through a wide range of pressures. When coupled with a suite of optimization or Sigma Service levels, they can maximize the efficiency of an operation and avoid problems to help provide the maximum return on investment.

But whatever the correct solution or optimal service level, the starting point should be a full collaboration between the operator and service company that begins at the planning stage. Such collaboration allows a full understanding of the project’s challenges and complexities and helps guarantee that the project will be efficiently and effectively executed.