When a well is constructed section by section, during any activity there will exist potential flow paths for the uncontrolled release of formation fluids from the well. It is precisely along these potential flow paths that barriers are required to prevent such an uncontrolled release.
The two-barrier envelope is a fundamental requirement for well integrity. The purpose of the envelope is to ensure that well operations are always conducted with a primary envelope that is 'active' and a secondary envelope that is 'redundant' and comes into play if or when the primary envelope fails. The secondary envelope will maintain integrity on the well until the primary envelope is restored.
The primary and secondary barriers must be independent of each other (two independent barriers as a minimum) to avoid situations where the failure of the primary barrier also affects the secondary barrier leading to a problematic and dangerous situation.
The Barrier Interfaces.
There are two interfaces that generally prevail in a well across which formation and well fluids must flow in an uncontrolled manner to cause a serious well control situation (blowout).
The first interface exists between the formations and the wellbore.
The first step to any serious well integrity situation is the unintended entry of formation fluids into the wellbore. For instance, while drilling, if there is an influx into the well, it means that formation fluids have crossed the first interface.
Primary barriers are established across this interface to ensure that formation fluids do not flow across the first interface unintended. Taking the same example of drilling, the drilling mud with some overbalance is the primary barrier that prevents formation fluids from crossing this interface.
Note: The situation is slightly different during activities such as well testing or production where formation fluids are allowed to flow intentionally into the wellbore and then to surface. In such scenarios, the 'first interface' does not exist between the formation and the wellbore but between the intended downhole flow conduit (test string or production tubing, isolation packers, liners, liner hangers, DHSV, etc) and the rest of the wellbore.
The second interface exists between the wellbore and the external environment (surface) or between the wellbore and another sub-surface zone.
Once formation fluids have crossed the first interface in an uncontrolled manner, they can either continue flowing to surface or enter a weaker zone along the open hole.
Secondary barriers are established along this interface to ensure that the formation fluids are contained within the wellbore until the primary barriers across the first interface are restored.
For example, while drilling, after a kick is taken, the annular BOP is closed (well is shut in) to contain the influx within the well and allow for well killing and restoration of the primary barrier - circulation of a heavier drilling mud to replace the existing drilling mud before opening the well and carrying out subsequent operations.
Although in the 'drilling' example there exists only one primary barrier (the drilling mud), the secondary barriers are several. The annular and ram BOPs are used for well control, the shear rams exist to cut the string and seal the well in a worst case scenario, the previous casing string and the cement behind it isolate weaker zones from the influx, the drill string float prevents the flow of influx through the drill string and the wellhead seals exist to prevent leaks at the surface.
Identification of the appropriate barriers across both interfaces depending upon the well operation is a critical first step in ensuring well integrity.
Identification of Barriers and Barrier Diagrams.
The barriers that comprise the primary and secondary envelopes are not fixed in a well and will vary depending upon the operations or activities being conducted. These well barriers must first be properly identified for every operation that is planned based on potential flow paths through which formation and well fluids can flow in an uncontrolled manner either to a weaker zone along the open hole or to the external environment.
After identification of the barriers that make up the primary and secondary envelopes, precise testing and verification plans for each must be developed and consolidated into a simple document that allows for easy interpretation and flexible modifications whenever necessary - the modifications generally occur during execution where there may be differences from the plan; for instance, revised section TDs and casing depths, contingency hole sections or additional casing / liner.
This document is generally called a well barrier schematic or diagram and is prepared for each activity on a well. The schematics are prepared initially during the 'planning' stage and are usually a part of the well program. During execution, the schematics are updated to reflect the 'actual' status of the barriers with precise information on how they were tested and verified.
Going a step further, a robust well integrity management system (usually involving a software) can manage such schematics for several wells in an asset with the latest status information of all barriers making it very convenient for operators to focus their attention only where required. Such systems can also include models to estimate the 'probability of failure' and 'mean time to failure, MTTF' for well barriers to enable operators to plan in advance for barrier replacement or repairs. This will be discussed further in a different article as it is off topic for this one.
The flow chart illustrates the basic steps to identify well barriers and prepare a well barrier diagram for any well operation.
Good Stuff !