#23 Characterization of CO2 Rich Fluids

The climate debate has made CO₂ one of the most talked about substances.

In the oil and gas industry, CO₂ has always been important. Most reservoir fluids contain CO₂, some in large concentrations, and CO₂ is an efficient injection gas for EOR purposes.

The properties of the hydrocarbon components are the same in a CO₂ rich fluid as in a fluid with little or no CO₂. The plus fraction is therefore, regardless of the content of CO_2, to be treated as described in the first TechTalk in the series on Reservoir Fluid Characterization.

The challenges for a CO₂ rich fluid are to model the behavior of pure CO₂ and how CO₂ interacts with hydrocarbon components.

Figure 1 shows a phase diagram for CO₂ generated using PVTsim. The boundary line between liquid and solid CO₂ is generated using a new option introduced in PVTsim Nova 6 that enables precipitation of pure inorganic solids to be simulated.

The supercritical region of CO₂ region is often referred to as a dense phase. In this region, CO₂ has a density that is higher than normally seen for supercritical gas components, and the food industry makes use of the high density for extraction purposes. Figure 2 shows the density of CO₂ simulated with the GERG-2008 equation for temperatures between 0 and 150 ^oC and pressures up to 1000 bar. As can be seen, at typical reservoir conditions, CO₂ has densities of the same order of magnitude as reservoir oils.

At reservoir conditions, pure CO₂ would be in a supercritical state. When modeling CO₂ with a classical cubic equation of state it requires a careful choice of binary interaction parameters (k_ij) for component pairs with CO₂. While interaction parameters of zero are appropriate for pairs of hydrocarbons, interaction parameters of the order of 0.1 must be used for CO₂-hydrocarbon pairs.

A component for which non-zero k_ij‘s are used, will tend to create an additional liquid phase with this component as the dominant constituent. This is seen for asphaltenes and also for CO₂.

One such example is given in Figure 3, which shows the phase envelope for a Middle East oil and phase envelopes for the oil with 100, 200 and 300 mol% CO₂ added [1]. On the low temperature side, the phase envelopes of the oil and of the oil with 100 mol% CO₂ added end at low pressure. This is typical for a reservoir fluid dominated by hydrocarbons. With 200 and 300 mol% CO₂ added, the phase envelopes bend upwards at lower temperatures. This is an indication of a liquid-liquid split. With more than 300 mol% CO₂ added, there would no longer be a saturation point at the reservoir temperature. Two immiscible CO₂ rich liquid phases would exist independent of pressure.  

Figure 4 shows a detailed phase diagram for the reservoir oil with 300 mole% CO₂ added. It is generated with the Phase Mapping option in PVTsim Nova and shows that at low pressure and temperatures below ~ 30 ^oC, a gas phase exists in addition to the two liquid phases.

The importance of using k_ij’s > 0 for CO₂ is illustrated in Figure 5. It shows the phase envelope for the reservoir oil with 300 mole% CO₂ added using CO₂ k_ij’s = ~ 0.1 and using CO₂ k_ij‘s = 0, respectively. With k_ij‘s of zero, the simulated phase envelope is similar to phase envelopes seen for reservoir fluids dominated by hydrocarbons. This shows that CO₂ k_ij‘s > 0 are required to model the liquid-liquid split occurring for high CO₂ concentrations as is illustrated in Figure 3. It is, on the other hand, a reminder that k_ij’s of zero should be used for hydrocarbon pairs as k_ij’s > 0 for fluids dominated by hydrocarbons may introduce false simulated liquid-liquid splits. This was emphasized in the first TechTalk in the series on Fluid Characterization.

Reference

[1]        Lindeloff, N. Mogensen, K., Pedersen, K.S., Tybjerg, P., Investigation of Miscibility Behavior OF CO2 rich Hydrocarbon Systems – With Application for Gas Injection EOR, SPE-166270-MS, presented ar SPE ATCE, New Orleans, September 29 – October 3, 2013.