Chemicals have been injected into the downhole of the oil wells in an attempt to ensure efficient production.
This measure is a usual oilfield strategy to improve the characteristics of crudes or deal with some flow
assurance problems, such as emulsions, scales, paraffin or asphaltenes deposition, etc. To overcome these
issues, downhole chemical injection systems (DHCI) have been installed in production facilities, in which the
injection of chemicals is controlled by chemical injection valves (CIVs). In this work, it was investigated the
possible causes of the failure of four commercial CIVs from demulsifier injection lines installed in heavy oil
production systems. The analysis consisted of disassembling the CIVs and analyzing their internal elements,
seeking the cause of the failure. A solid material (clogging) was found in some specific parts of the CIVs, which
could be the main cause of the CIVs’ failure. Solubility tests indicated a polar or apolar characteristic,
depending on the CIV. After the analysis, the CIVs were cleaned and reassembled, and tests in a high-pressure
line indicated that all of them got back to work properly. These findings have significant implications for
diagnosing the root causes of CIV failures in demulsifier injection lines, presenting a procedure to recover
obstructed CIVs, and offering preventive measures against future clogging issues.
Tag: clogging
Investigação da Compatibilidade entre Fluidos da Linha de Injeção Química de Desemulsificante em Poço de Petróleo
The chemical injection (CI) lines in oil-producing wells have been plagued by issues related to clogging, hindering the injection of demulsifiers into the oil reservoir, which directly impacts oil productivity. This problem might require stoppages in the oil production for cleaning and/or pigging the line, and even replace downhole equipment (chemical injection valves). Given this scenario, the present study aims to investigate the compatibility of fluids present in the chemical injection line. If these chemicals are not compatible and result in solid formation, it could lead to pipe blockages. To assess this, monoethylene glycol (MEG), commonly used as a flushing fluid and hydrate inhibitor, and an ethoxylated polymeric surfactant, used as a demulsifier, were mixed to observe any physical change in the solution. The tests were conducted at room temperature (30 °C) and 60 °C, for up to 72 h, with visual monitoring during this period. In addition, rheological tests were carried out on pure fluids and their mixtures to evaluate if there were viscoelastic changes. These studies made it possible to detect a whitish gel at the bottom of the test tube formed through contact between the MEG and the demulsifier (phase separation) at both temperatures. This allows us to conclude that physical changes occurred in the mixture (MEG + demulsifier), forming a higher viscosity gel. Importantly, preventing this gel formation could possibly prevent clogging in the CI lines, as the gel could adhere to solid contaminants and contribute to blockages.