For several years chemical vendors and oilfield operators have measured H2S presumably generated in situ in oilfield products, specifically corrosion inhibitors and combination scale and corrosion inhibitors. Sometimes when handling oilfield chemicals, a personal H2S monitor will be triggered with the assumption that this response is from H2S. Since the alert is triggered in close proximity to some oilfield chemicals or even while opening the chemical container, the logical conclusion is that the product contains H2S; however, these monitors are likely detecting vapor phase water-soluble, small chain sulfur species like 2-mercapoethanol (2ME) or thioglycolic acid (TGA). Analytical methods used to measure H2S to investigate these phenomena typically use gas chromatography (GC) with high inlet temperatures to evaluate the composition of the product headspace. These high temperatures cause thermal decomposition of water-soluble organosulfur intermediates (OSIs) which can result in a H2S response. The authors have studied several such phenomena associated with oilfield products and have developed methods to investigate these phenomena to determine the cause of H2S alerts. The goal is to allow operators and chemical vendors to make informed health and safety decisions about detection devices as well as chemical products selected for oilfield service. This paper describes the methods needed to determine the true H2S content of an oilfield chemical product as well as the impact of product composition changes on personal monitor false alarms.