There has been renewed interest in the corrosivity of high-density well completion and packer fluids in recent years following a series of failures of Corrosion Resistant Alloy (CRA) tubing strings from the annular side as a result of stress corrosion cracking (SCC). It is now realised that the original corrosion testing carried out on traditional halide-based completion and packer brines may have been too cursory, and missed some important environmental factors that make CRA susceptible to SCC in these fluids. New studies have shown that some CRA become susceptible to SCC in halide brines charged with CO2 and H2S, but there remain some uncertainties about the boundary conditions that trigger the SCC.
The objective of the laboratory experiments described in this paper was to examine how the contamination of high-density brines with oxygen, chlorides and CO2 might influence the susceptibility of CRA to SCC under high temperature-high pressure (HTHP) conditions. Our results highlight the increased risk of SCC occurring in CRA tubular materials when bromide-based completion brines become contaminated with oxygen or CO2 during field use in HTHP wells. Our tests also indicate that similar contamination of formate-based completion brines is less likely to create SCC problems in CRA tubular materials in HTHP wells. We conclude that the current North Sea trend for using formate-based completion fluids in place of bromides may provide better insurance against SCC -related tubing failures.
It is common practice to employ tubular goods fabricated from Corrosion Resistant Alloys (CRA) in deep oil and gas wells, to cope with the corrosive nature of produced fluids and gases under high pressure and high temperature conditions. Likewise it has been commonplace for the past 20 years to use high-density brines in HTHP wells as completion and packer fluids. These fluids can remain in contact with the annular surfaces of CRA goods for considerable periods and it is vital for long-term well integrity that the brines used are compatible with the CRA under HTHP downhole conditions for months if not years. It is also vital that any contamination of brines during use does not compromise the compatibility between the brines and the CRA. Typical accidental contaminants might be oxygen and halides picked up during surface handling, and acid gases (CO2 and H2S) from sub-surface influxes via connection or packer leaks. The addition of oxygen scavengers and various types of corrosion inhibitors to halide brines are examples of deliberate contamination events that could inadvertently introduce new chemistries capable of causing SCC.
Operators involved in HTHP well constructions currently have to choose between two high-density brines systems. The traditional high-density brine system is a blend of calcium bromide and calcium chloride with zinc bromide. These acidic halide brines are corrosive under HPHT conditions and therefore require formulation with corrosion inhibitors. The more benign and less corrosive alternative is a blend of potassium formate and caesium formate brine. The formate brines have the distinct advantage of being capable of formulation into combined HTHP drill-in and completion fluids.[1–5] In the North Sea, where the use of formate brines enables the essentially trouble-free construction of long high-angle HPHT wells fitted with sand screens6, the caesium formate brine systems have just about completely displaced the zinc bromide brines. In other parts of the world the bromide brines are, for now, still the preferred high-density completion fluids for HTHP wells.