Abstract

The purpose of this paper is to address the key drivers and risks associated with the use of Applied Back Pressure Managed Pressure Drilling. One of the two key issues to understand early on is whether the well can be drilled statically overbalanced or needs to be drilled with a statically underbalanced fluid. The second issue to comprehend is the level of service needed to avoid compromising safety and well objectives. Answering these two questions defines the path to be followed for adequate planning.

Detailed planning aspects, such as flow modeling, crew training, operational procedures, process flow diagrams and HAZID / HAZOPs meetings are also described in this paper. By asking the 'what if' questions prior to operations, it should become apparent what additional surface equipment is required to safely and efficiently drill in MPD mode. Control of the 'what if's should help to keep the planning and rig up both reasonable and cost effective.

Introduction

Managed Pressure Drilling (MPD) in the form of Applied Back Pressure (ABP) or Constant Bottom Hole Pressure (CBHP) is becoming increasing popular as a means of overcoming certain drilling problems. However, its entry into the market has come several years after the adoption of industry best practices and regulations for planning Under Balanced (UB) wells. Because reservoir fluids are typically handled at surface, UB wells require extensive study and planning before being implemented. One problem now confronting our industry is the level of study and planning required for ABP MPD wells drilled overbalanced. By understanding key application aspects, such as the proposed mud weight, required level of service, and company and regulatory policy on the use of well control equipment; it is possible to determine the appropriate amount of planning needed for the project to be successful.

MPD Application Drivers

Before planning an MPD project, the driver for application should first be understood and quantified. This exercise is typically performed by the operator and falls into one or more of the following categories:

  • Minimize overbalance to

    • Increase ROP

    • Avoid differential sticking

    • Prevent lost returns

    • Reduce formation damage

  • Maintain constant BHP to avoid wellbore ballooning

  • Extend the depth between casing setting points

    • Narrow kick tolerances

    • Deplete tight gas zones containing nuisance gas

  • Faster kick detection because of better flow measurements

  • Enable dynamic well control methods

If commercial benefits are difficult to justify, then other factors should be explored before discounting MPD and reverting back to a conventional well with the associated conventional drilling problems. Reviewing offset well data will help quantify the potential Non Productive Time (NPT) likely on the well. By asking the right questions of MPD, it may become apparent that it offers solutions in more than one problematic area.

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