New Advanced Material and Coating Technique for Trace Hydrogen Sulfide Sampling
- Christopher Jones (Halliburton) | Jimmy Price (Halliburton) | Mickey Pelletier (Halliburton) | William Soltmann (Halliburton) | Darren Gascooke (Halliburton) | Anthony van Zuilekom (Halliburton)
- Document ID
- Society of Petrophysicists and Well-Log Analysts
- SPWLA 60th Annual Logging Symposium, 15-19 June, The Woodlands, Texas, USA
- Publication Date
- Document Type
- Conference Paper
- 2019. held jointly by the Society of Petrophysicists and Well Log Analysts (SPWLA) and the submitting authors
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The presence of hydrogen sulfide (H2S) in a reservoir fluid can significantly impact the economic viability of a petroleum asset. Even in low PPM concentrations, H2S can require special completion materials to mitigate corrosion problems and surface scrubbers to remove H2S prior to transport, both of which significantly increase capital investment. H2S also causes scale, forcing regular flow assurance mitigation which increases operational costs. Yet, it is very difficult to capture representative fluid samples, without which the asset uncertainty increases during formation evaluation. Specifically, H2S adsorbs to the formation tester tool flow line surface, thereby reducing the concentration in captured samples relative to true formation fluid concentrations. This is true even with NACE-compliant materials, which do not react with H2S but do adsorb H2S to their surfaces. Without mitigation, formation tester tools scrub the formation fluid of H2S as a formation fluid passes through the tool, leading to erroneously low characterization.
Minimizing the flow line length helps lower, but does not negate, the effects of adsorption scavenging. Currently, there are specialized coatings applied to the formation tester surface that help but have some drawbacks. In many instances, the coating durability is low. Fundamentally, all current coatings are physically adhered like paint to the tool surface and can peel by chemical attack and flake off, exposing unprotected surfaces for H2S adsorption. Current coatings do not adhere to elastomers, which is a large sink for H2S. Some of the more durable coatings require temperatures in excess of 800°F for application. These coatings are applied to disassembled parts, not to all tool materials, leading to incomplete coverage. For all present coatings, the process is conducted in specialized facilities, negating the possibility of rapid re-application to repair worn coatings for most field locations.
In this study, sapphire has been validated as a new material to mitigate H2S adsorption. Sapphire has a very low adsorption affinity for H2S so that coated materials do not scrub H2S even at low concentrations. Sapphire, being one of the hardest materials next to diamond, is highly scratch resistant and only scraped off if the underlying material is gashed. A new chemical process has been developed to deposit sapphire which binds the coating to the formation tester material at the molecular level. Therefore, this coating does not further peel back from the gashed site. In this study, the coating has also been shown to protect elastomers. The coating process is quick, HSE safe, and applicable at low temperature. Therefore, coatings may be re-applied to assembled field tools prior to sampling. Elastomers may also be treated with this process. Accelerated lifetime testing has shown high durability relative to tool life. Samples containing H2S have been successfully stored in lifetime-worn bottles for weeks with no loss.
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