Operators elevate well integrity priority

Endless examples exist where something has been engineered for a pre-determined life span yet it still exists far beyond its intended time. Most aging structures within an oil and gas producing asset will still be operating long after the original design life.

In an aging well stock, a loss in integrity can be difficult to observe. Most problems are subject to diagnosis, or likely inferred. A structural failure on a topside jacket is easily identified, a deep-set liner-hanger failure in a well not so straight forward. Some easily identifiable losses in well integrity occur, but the situation downhole shows a less dramatic example. A gas leak from a conductor on a well more than 20 years old would be an example, and it is easily observable and relatively straight forward to repair.

Well design should ensure that the objectives for which it is being constructed can be met. Clearly, a well needs to be capable of delivering its designed purpose. Equally important is the ability for the integrity of the well to be maintained and to allow remedial actions. A well constructed with fully cemented solid foundations and barriers suggests a sound basis for well design. However, are these attributes particularly favorable for well integrity management purposes? If cement bonds, sealing devices, casing, and formations remain intact, well integrity problems should be largely irrelevant.

In adopting design principles such as these, problems can occur if well integrity is lost at some stage. Quite simply, the space available for dynamic motion (fluids to expand) anywhere other than the inner annulus is very limited in such an example. Options for remedial repair outside of the inner annulus are even more limited.

Well construction

The construction part of the life cycle is the key area where the well integrity can be determined. The best chance of minimizing integrity problems is during the construction phase. Change management is of fundamental importance in applying appropriate control processes during well construction. If the basis of design has determined discrete criteria, any associated change must be highly controlled. Failure to do so may have the ultimate detrimental effect on the long-term integrity status.

Many organizations see significant resources allocated to ongoing well integrity management issues as a result of changes made at the well construction stage. Change management must include basis of design and risk reviews.

Operations

The key difference with aging wells is that failure modes are more likely to occur. (By aging, it is assumed the well is beyond the initial design life.) The escalation scenario for a well integrity situation to get worse in an aging well is far more grim. Annular pressure management is one area where controlled monitoring can allow potential well integrity problems to be identified early on.

While a well is being constructed, there are implicit control processes in place. It is important to understand differences between the construct and operating phases. Using results obtained during the drilling of a well may not be suitable during the operating phase. A drilling maximum allowable annulus surface pressure (MAASP) for a hole-section is not the same as the annuli MAASP to be used during the operating phase. It is uniquely different in derivation and eventual use.

When well construction is complete, providing one knew where the top of cement was for each section, the completion brine/annuli fluid type and density, tubing/casing grades, formation strengths, and associated equipment pressure ratings, a fairly precise MAASP can be derived as a control process for any well.

Well schematic, cemented to surface.

For an aging well, uncertainties when conditions change is the overlying concern when adopting well integrity control processes, such as re-determining MAASPs. It is for this reason that worst-case assumptions are set as the starting point in well integrity control processes. When the pressure changes in annuli in an aging well, it most likely is a consequence of corrosion or cement degradation. In a worst-case scenario, one should assume that cement degradation has occurred to the extent it may have to be disregarded as a pressure containing medium and that the differential fluid hydrostatic pressure supporting the casings is no longer near equal. This condition could occur as a result of a brine or gas influx from an overlying aquifer or deeper producing zone. It could even be a consequence of changing a well’s status from that of a natural producer to artificial lift, specifically that the A-annulus fluid has been replaced from a liquid to a gas.

Some organizations may take assumptions further and create more pessimistic worst-cases. Generally, the more pessimistic the assumptions, the lower the operating boundary of the well when in-service. Evacuated tubing and casing scenarios can be used, more commonly so with tubing. In extreme cases, assuming vacuums are applied may be considered.

In complicated well designs, such as deepwater HP/HT wells, where gas cushions and other precautions may be used, the importance of realistic absolute worst-case scenarios cannot be overstated. Things can change very quickly in these types of wells, especially when gas is the dominant fluid.

There cannot be hard and fast rules in determining well integrity control processes during the production phase. There must be flexibility depending upon associated risk levels. Every well, especially an aging one, should be treated on an individual basis. Appropriate well integrity management is a case of setting a control process (deriving the figures), with sound reasoning, competent engineering judgement, and ensuring all assumptions are clearly implicit from the end result.

You should also undertake independent verification and internal technical assurance. This is the external additional safeguard to assure that the control processes adopted by an organization are sensible and in-line with favorable recognized international standards.

Other assumptions to consider when deriving control include when a field undergoes facilities compression and subsurface compaction (especially in a carbonate environment).

Well abandonment

Abandonment is without doubt the most overlooked stage of a well’s life cycle. Most field development plans (FDPs) are required to address an end-of-field strategy, which should include abandonment. It is, however, often left as “to be confirmed” within the scope of most FDPs. As the focus and profile of well integrity increases, statutory authorities are less likely to accept this. In the future, appropriate abandonment strategies will become a stricter requirement before production licenses are granted in many more countries throughout the world.

The possible recovery of hydrocarbon-bearing formations to virgin pressure should be considered as a given in developing an abandonment strategy, unless it can be categorically proven otherwise.

The deterioration of some well components over time, post-abandonment, may be difficult to quantify, but must somehow be accounted for. Again, setting control processes with sound reasoning, competent engineering judgment, and ensuring assumptions are implicit should ensure that where best practice is adhered to, the principle of reducing risk to as low as reasonably practicable has been achieved.

Acknowledgment

This article is based on a paper presented at the Offshore Middle East Conference & Exhibition, Doha, Qatar, October 2010.

The author

James King is a petroleum/well engineer, with over 25 years of experience in the delivery of various large scale oil and gas field development and abandonment projects, including subsea. He holds professional titles as a chartered physicist, chartered scientist, and chartered engineer. He is a member of the Institute of Physics, and holds a BSc (Hons), and Post Graduate Diploma in Management awards. He has worked for major operators in various petroleum/well engineering roles, and as a field development project manager, wells/reservoir team leader and drilling manager.