In the oil industry when commingled wells are producing from different reservoirs (different geological layers) or even when production wells are connected to a common flowline, it is often necessary to quantify the fluid origin. This is a way to obtain material balance and to allocate the oil production. Production allocation is particularly important for a better reservoir management (history matching with the reservoir models). Several methods can be used aiming to determine the fluid flow like the Production Logging Test (PLT) or geochemical tools. The geochemical techniques (e.g. molecular fingerprinting of oil) are based on specificities of the oil composition and represent a profitable alternative method (less risk, no well intervention, no production losses, cost savings and higher frequencies) to PLT. The geochemical differences affecting oil composition can be attributed to many reasons: different source rocks, process of migration and filling histories, reservoir communication leading to oil mixture, and several in-reservoir alteration processes. Therefore, chemical differences between the oils are always existing can be used to determine and quantify the contribution of each fluid source.

Molecular fingerprinting using high resolution gas chromatography is a reference technique widely used for geochemical production allocation. This conventional type of techniques allows discriminating very similar fluids even so similar fluids as condensates (Sabatier et al., 2015). Nevertheless alternative techniques should be explored.

In the present work we investigated the possibility to discriminate oils form the same fields according to possible differences in composition of aromatic compounds. Specific geochemical analyses where performed in Doha in a joint Qatar Petroleum – Total project. The analytical approach used was Gas Chromatography coupled with Mass Spectrometry and a typical chromatograph is shown in figure 1.

Figure 1: gas chromatogram of the aromatic fraction of a petroleum sample (m/z 128: Naphtalene, m/z 142: methyl-naphtalenes, m/z 156: dimethyl-naphtalenes, m/z 170: trimethyl-naphtalenes, m/z 184: tetramethyl-naphtalenes, m/z 198: pentamethyl-naphtalenes).

As shown in an example presented in figure 2, the reservoirs from the studied fields coming from all around the world could be discriminated considering the composition in diaromatic hydrocarbons. This discrimination is possible considering both the height of the peaks or their surface.

Figure 2: comparison of the proportion of diaromatic hydrocarbon in the oils from different reservoirs of the same field.

The present study concerns the ability to discriminate oils according dicyclic aromatic hydrocarbons, but the same conclusions applies to tri, tetra and penta aromatic compounds (results not shown).

The results shown in the present study clearly allow envisaging fast analysis techniques based on aromatic hydrocarbons detection. This opens the way for future work focusing on quantifying such kind of compounds (involving quick separation techniques and smart detection methods). Sabatier L., Haidar F., Mahdaoui F., Dessort D., and Philippe Julien, 2015, Gas Reservoir Management: How to improve Gas Production Allocation per Reservoir in commingled Wells using Geochemistry Technology?, Proceedings of the International Petroleum Technology Conference, December 6th to 9th, Doha, Qatar.


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