PVT Consulting and Simulation Software

Calsep is a leading provider of PVT simulation services to the oil and gas industry

Calsep has more than 30 years of experience working with the oil industry on projects related to reservoir fluid phase behavior. That allows us to offer knowledge-based PVT simulation software and studies within EoS modeling of all kinds of fluids including natural gases, gas condensates, near critical fluids, black oils, and heavy oils. Calsep undertakes projects with application for reservoir simulation, flow assurance, and process simulation.


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International experts in EOS modeling

Calsep undertakes fluid modeling studies assessing all stages of production. The studies may cover the effect of injection gas in the reservoir for EOR purposes as well as the risk and mitigation of solid precipitation in wells and pipelines. Calsep can deliver fluid property or composition input files for more than 20 different reservoir, flow and process simulators.


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Calsep offers open courses as well as in-house courses to reservoir engineers, process engineers, engineers dealing with flow assurance or multi-phase flow metering, laboratory staff and others needing to apply PVT simulation software in their work.


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PVTsim Nova

A leading PVT simulation software

PVTsim Nova was launched May 2014 as a new generation of the PVTsim software package that has been continuously developed since the first version was released in 1988. Powerful and reliable simulation options wrapped in a user-friendly graphical user interface has made PVTsim the preferred PVT simulation tool of more than 200 companies in oil and gas industry.


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Monthly Tech talk
Monthly Tech talk

January-February 2016: Gas Injection as an Enhanced Recovery Technique for Gas Condensate Reservoir Fluids

Gas injection has for decades been used to enhance oil recovery (EOR). The injected gas keeps the reservoir pressure high and blends with the reservoir fluid to possibly develop a miscible zone that will prevent gas from behind in penetrating and creating a gas break through. The lowest pressure at which a miscible zone can develop is called the minimum miscibility pressure or MMP. The MMP can be measured experimentally by carrying out a slim tube test or it can be simulated using either a slim tube simulator or a multi-component tie-line algorithm (e.g. Orr, 2007).                               

Gas injection as an enhanced recovery technique for gas condensate reservoirs is less common and the theoretical framework is different from that of oil mixtures. The produced fluid is a gas and gas breakthrough not an issue. If a gas condensate fluid is produced by natural depletion, the condensate-gas ratio (CGR) will decrease with time from the point the saturation pressure is reached. Most liquid components will be contained in the condensate that starts forming at the saturation pressure and most of this condensate will stay back in the reservoir. For a gas condensate fluid the purpose of the gas injection is pressure maintenance and revaporization of already condensed liquid.

Calsep was recently engaged in a project with ADCO in Abu Dhabi on evaluating gas injection for EOR purposes for a gas condensate reservoir. Three different injection gases were compared, N2, CO2 and a hydrocarbon (HC) gas. The outcome of the project was presented at the ADIPEC conference in Abu Dhabi 2015 (Kumar et al., 2015). Two key features of the injection gases were studied, revaporization and displacement efficiency. Revaporization is the more important mechanism when the reservoir is depleted. That means the reservoir pressure is below the saturation point when gas injection starts and some liquid condensation has already taken place. If gas injection is started at a pressure above the saturation point (undersaturated reservoir fluid), the displacement efficiency becomes the more important. The displacement efficiency is a measure of how much gas is produced per mole or weight unit of gas injected.

The left hand plot in Figure 1 shows the development in CGR with pressure if the reservoir fluid was produced by natural depletion. The plot has been made assuming the production can be emulated as a constant volume depletion process and all production comes from the gas phase. The right hand plot in Figure 1 shows the percent liquid recovery as a function of pressure assuming production is continued to a reservoir pressure of around 50 bar. Gas injection will only be interesting if the liquid recovery exceeds the recovery obtained with natural depletion, which is a recovery of around as 50%.

 

Figure 1 Gas condensate reservoir fluid produced by natural depletion. The left hand plot shows CGR versus pressure and the right hand plot the relation between reservoir pressure and the percent liquid recovery.

 

Gas revaporization experiments were conducted with each injection gas on a depleted reservoir fluid at a pressure around 80 bar below the saturation pressure. The gas revaporization experiment is described by Pedersen et al. (2014) and is designed to simulate what happens in a depleted gas condensate reservoir when gas injection is used to maintain pressure as production goes on.

Figure 2 shows gas revaporization results with respectively N2, CO2 and HC injection gas. For all three gases the volume of condensed liquid is initially around 7% of the saturation point volume. The left hand plot in Figure 2 shows that almost all liquid is revaporized after addition of 2 moles of CO2 per initial mole reservoir fluid. With N2 injection gas the liquid level after adding 2 moles of gas has gone down to around 3 volume%. With HC injection gas the liquid level after adding the same number of moles of gas is just above 1 volume%. The liquid contents in the gas displaced from the three gas revaporization experiments were converted to liquid recoveries as shown in the right hand plot in Figure 2. The recoveries with CO2 and the HC injection gas are above 80%. The capability to revaporize condensed liquid is higher for CO2 than for the HC gas, but the HC gas has a higher displacement efficiency. The liquid recovery with N2 injection gas is not much higher than the recovery, which can be obtained through natural depletion (right hand plot of Figure 1).

 

Figure 2 Gas revaporization at 133 oC and 222 bar with N2, CO2 and hydrocarbon injection gas. 

 

The gas revaporization experiment showed that injection of N2 was unattractive for an already depleted reservoir. The conclusion would have been different for an undersaturated reservoir. As long as the reservoir pressure is above the saturation pressure, only the displacement efficiency counts. At reservoir conditions N2 has a molar volume, which is 1.5 times that of CO2. The same molar amount of N2 will therefore displace 1.5 times as much reservoir fluid as CO2.

 

References

Orr, F. M. Jr., “Theory of Gas Injection Processes”, Tie-Line Publications, 2007.

Pedersen, K.S., Christensen, P.L and Azeem, J., “Phase Behavior of Petroleum Reservoir Fluids” Chapter 3, CRS Press, 2014.

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