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Cesium formate (CsFo) brines have been used as the drilling and/or completion fluids in oil and gas wells in need of high-density fluids.1,2 Multiple studies on corrosion of steels and corrosion resistance alloys (CRA) in formate environments have been reported in the literature.2-8 It was known that the formate brines could undergo significant decomposition to form hydrogen when in contact with catalytic surfaces which CRA can act as. Therefore, there have been concerns that the CRA may catalyze the decomposition of formate brines to accelerate the generation of hydrogen which in turn may embrittle certain CRAs and endanger the relevant well equipment.
Because of hydrogen generation from thermal decomposition of cesium formate, there were concerns that the use of cesium formate in certain applications may induce hydrogen embrittlement to CRA equipment after extensive exposure to elevated temperatures followed by cooling to low temperature under stress. This study focused on evaluating the severity of hydrogen embrittlement of seven nickelbased alloys at room temperature following exposure at elevated temperature to cesium formate of H2S/CO2 acid gases and consequently reduced pH. Unstressed slow strain rate (SSR) test specimens were previously exposed in an autoclave of cesium formate saturated with H2S/CO2 at an elevated temperature of 275 °F for 90 days. After exposure, significant hydrogen uptakes were observed under the tested conditions by measurement of total hydrogen concentration. The hydrogen-charged SSR specimens were then tested in air with 1 x 10-6 in./in./s strain rate at room temperature and compared with performance of the pristine specimens. In addition, three charged CRA alloys were also heated in furnace to release dissolved hydrogen and then tested in air. Two of the seven CRAs were also strained in situ in cesium formate at 275 °F.
Offshore oil production facilities are subject to internal corrosion, potentially leading to human and environmental risk and significant economic losses. Microbiologically influenced corrosion (MIC) and reservoir souring are important factors for corrosion-related maintenance costs in the petroleum industry.1 MIC is caused by sulfate-reducing prokaryotes (SRP), which can be Bacteria (SRB) or Archaea (SRA), with the main focus in literature being on SRB.2–5 The microorganisms most frequently reported in literature to be responsible for MIC are the SRB; Desulfovibrio, Desulfobacter, Desulfomonas, Desulfotomaculum, Desulfobacterium, Desulfobotulus, and Desulfotignum, and methanogens.2,5
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It is fair to say that maintenance in the worldwide oil and gas industry has changed dramatically over the past ten years. Facility owners are more than ever looking to reduce shutdown times, to improve plant efficiency and to extend plant lifetimes. With this comes the increased industry understanding about corrosion under insulation (CUI) with its deleterious impact and the ongoing desire for pragmatic high performance and cost-effective coating solutions.
The In-Situ internal coating is a viable alternative for pipeline rehabilitation of corrode pipe and cost effective compared to replacement with new pipelines.