Laboratory selection of oilfield corrosion inhibitors used to mitigate carbon dioxide (CO2) and hydrogen sulfide (H2S) corrosion is an essential aspect of every asset integrity program implemented in oil and gas fields. However, many factors increase the complexity of designing a corrosion inhibitor laboratory test program that will deliver reliable results. Several of these factors relate to the challenges of accurately replicating field conditions in the laboratory, including using inhibitor-free crude oil, reproducing pipeline flow regimes and wall shear stress, duplicating the specific form of corrosion that occurs in the field, and simulating inhibitor deliverability and transport in multiphase pipelines. Other elements that increase the difficulty relate to requirements for environmentally acceptable chemistries in certain geographies and the variety of corrosion performance tests and methodologies mandated by different oil companies. After the laboratory testing is complete and a corrosion inhibitor has been selected for field application, optimization of the product in the field should be performed but this is frequently overlooked. If corrosion inhibitor treat rate is not optimized in the field, it can result in overdosing (causing stabilization of emulsions and foaming) or underdosing (which can result in high corrosion rates). This paper discusses the challenges and inconsistencies associated with selecting corrosion inhibitors for use in oil and gas fields. Importantly, this paper discusses how these challenges can be resolved to ensure that the selection of oil and gas corrosion inhibitors follows a reliable process.