Applying Gas Chromatography to Environmental Geochemistry

Jul 24, 2014
Volume 10, Issue 13

In the first of a two-part Q&A The Column spoke to Paul A. Sutton, a research fellow in the Petroleum and Environmental Geochemistry Group (PEGG) at Plymouth University (Plymouth, UK), about the analysis of crude oil and how high temperature gas chromatography can be used to save millions of dollars for the oil industry.

Q: What are your current research interests and what led you to these areas of research?

A. My current research interests fall into two main categories: The application of high temperature gas chromatography (HTGC) techniques to the characterization of organic extracts, and the fundamental analysis of crude oil. Fortunately these research areas have much crossover. GC is amenable to a wide range of compounds in their natural state or derivatized to improve their volatility or demote their interaction with the stationary phase. However, conventional GC is somewhat limited by the thermal stability of the stationary phase, which can readily breakdown at temperatures above 300 °C. This effectively means that GC is limited to the analysis of compounds with <35–40 carbon atoms.

In contrast, HTGC, with oven temperatures up to around 430 °C, can be used for compounds with up to in excess of 100–120 carbon atoms, allowing an extended analytical window. Although not all compounds are stable under HTGC conditions, it has broad applicability and relatively low discrimination when used with flame ionization detection (FID). Developments in column technology have meant that HTGC is now a robust and routine technique that can be operated in the same way as conventional GC. So it is worthwhile screening organic extracts from sediments, for example, using HTGC and comparing the data to that obtained using "conventional" GC.

Q: Why are you interested in the analysis of crude oil specifically?

A. Crude oil is an intriguingly complex mixture of hydrocarbons, polar (N, S, O) compounds, metals, and particulates. Its properties vary geographically, geologically, and throughout its production and processing. The petroleum industry often classifies oils for quality and flow assurance issues based on bulk properties such as total acid number (TAN), total base number (TBN), and specific gravity (API), by their distribution into operationally defined fractions based on solvent solubility such as asphaltenes, or by their separation into bulk chromatographic fractions such as saturates, aromatics, resins, and asphaltenes (SARA). Sometimes these measurements are not sufficiently adequate to identify particular flow assurance issues. The issue of calcium naphthenate (calcium salts of tetracarboxylic acids) deposition is a case in point because it does not appear to be related to TAN. The analysis of crude oil can be academically challenging and I am interested in investigating the development of techniques that can be used to comprehensively characterize crude oils in a more consistent physico-chemical manner.

Q: Why do polycyclic C 80 tetracarboxylic ("ARN") acids represent a concern to the oil industry?

A. The term "ARN" comes from the Norwegian for eagle and reflects their discovery in 2005 by Baugh et al.1 C80 tetracarboxylic acids represent a family of isoprenoid compounds with 80 carbon atoms arranged in an H-shape with terminal carboxylic acid groups at the end of each arm and between 0–8 cyclopentyl rings, which are particularly associated with immature, biodegraded, and heavy crude oils. They represent a problem because they are a pre-indicator of calcium naphthenate deposition.

During oil production, it is often necessary to force oil to the surface using seawater. This can result in a pressure drop towards the surface platform leading to an outgassing of CO2 and a rise in the pH of the fluid. Tetraacids present in crude oil under these conditions congregate at the interface of the aqueous and oil phases. This is because the C80 part of the molecule is extremely hydrophobic, whereas the terminal acid groups are hydrophilic. The rise in fluid pH causes dissociation of the tetraacids and saponification with metal ions in the seawater, with calcium of special importance.

Calcium is divalent and so can link with more than one tetraacid, leading to a cross-linked polymeric-type structure that forms a solid deposit in topside equipment, particularly in the oil/water separator. This calcium salt is termed calcium naphthenate. These deposits can build-up until equipment becomes clogged and production has to be halted, costing millions of dollars. While calcium naphthenate tends to be rich in tetraacids (around 30 wt% of a cleaned deposit), the parent crude oil typically contains low ppm levels of individual or total tetraacids (up to 20 ppm total). If C80 tetracarboxylic acids are detected early enough, then mitigation strategies can be formulated at an early stage before flow assurance issues arise.

Quantification of the tetraacid content of crude oil is therefore of huge benefit to the oil industry. It should also be noted that the presence of C80 tetraacids in a crude oil does not necessarily mean that there will be a flow assurance issue, but calcium naphthenate formation does not proceed without them.

Q: Are there other analogues of C 80 tetracarboxylic acids?

A. Besides the C80 tetraacids, C81 and C82 methylated analogues are usually present in deposits and parent crude oils. However, other carbon number tetraacids (C60–77) have also been reported based on mass spectrometry analysis. C80 tetraacids have been reported to occur in crude oils from across the globe, for example in the North Sea, West Africa, offshore South America, South-East Asia, China, Australia, and the Gulf of Mexico. What is interesting is that we see different distributions of cyclopentyl ring numbers and different C80/81/82 ratios from different locations. Typically, the tetraacid distributions in crude oils and deposits examined so far have been dominated by the C80 compounds with between 4–8 cyclopentyl rings. Usually the 6-ring compound dominates but this is not always the case and we have seen distributions dominated by 7- or 8-ring compounds and by C81 compounds. I expect that alternative distributions will be identified in the future as we examine more samples. So, while the petroleum industry primarily wants to know the tetraacid content of crude oils for potential flow assurance issues, the same information may be useful regarding the depositional setting and thermal history of the oil reservoir. As methods for isolating and measuring tetraacids develop and more crude oils and deposits are tested we may also find additional related compounds. This also suggests that our analytical strategy needs to be specific enough for tetraacids but sufficiently broad to cope with a relatively wide range of carbon numbers.

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