Acid-gas injection encounters diverse H 2 S, water phase changes

March 9, 1998
For acid-gas injection systems, pressure-composition diagrams indicate the significant phase changes that H 2 S and water mixtures can undergo when going from an amine unit to downhole in an injection well. This conclusion of a two-part series, which started in OGJ Mar. 2, 1998, p. 92, describes the importance of considering H 2 S and water phase changes in the design of acid gas injection compressors, pipelines, injection wells, and methanol injection. As an example, consider a simple acid-gas

H2S INJECTION-Conclusion

John J. Carroll
Gas Liquids Engineering
For acid-gas injection systems, pressure-composition diagrams indicate the significant phase changes that H2S and water mixtures can undergo when going from an amine unit to downhole in an injection well.

This conclusion of a two-part series, which started in OGJ Mar. 2, 1998, p. 92, describes the importance of considering H2S and water phase changes in the design of acid gas injection compressors, pipelines, injection wells, and methanol injection.


As an example, consider a simple acid-gas injection scheme where the injected gas is H2S saturated with water at 50° C. and 150 kPa and the required injection pressure is 4,000 kPa. The compression will be carried out in a three-stage compressor with interstage cooling. At each interstage the gas is cooled to 50° C.

Furthermore, it is assumed that no dehydration other than the knockout drums occurs at the interstage. Thus, the gas entering a stage is saturated with water.

Table 1 [46,029 bytes] , summarizes the compression stages and Fig. 1 [70,530 bytes], which is similar to Fig. 2a [201,413 bytes], shows the compression path on the P-x diagram. Note that after the final compression stage the fluid is a single-phase, H2S-rich liquid.

The gas entering the third stage contains 1.0% water. At 50° C. and 4,050 kPa a saturated liquid can hold 2.4% water. Thus, this liquid is undersaturated and an aqueous liquid phase will not form.

One question that needs to be answered is, "What is the possibility of forming an H2S-rich liquid in the compressor?"

In this scheme, during compression the gas is heated. This alone would tend to prevent H2S-rich liquid from forming. But do not be mislead by the fact that the regions on the P-x diagrams where the H2S-rich liquid and the vapor co-exist are fairly small.

In an actual acid-gas injection scheme, the mixture is multicomponent (containing at least H2S and CO2) and this will broaden the region over which the non-aqueous phases can exist.

An engineer designing the compressor should be aware of the possibility of forming a non-aqueous liquid.

It may seem convenient that a 4,000 kPa injection pressure was selected because, in this scheme after the third compression stage, fluid becomes a single phase liquid.

But, what if additional pressure was required to inject the acid gas? Because the acid gas is now a liquid, the additional pressure can be obtained simply by using a high-pressure pump.

Because compressors are more expensive than pumps, the design engineer might be able to take advantage of liquid acid gas to reduce capital costs for the injection scheme.


The acid-gas fluid cools as the gas enters the underground pipeline that connects the compressors to the wellhead. For small injection schemes, the injection flow rate is quite low and, even in short lines, the acid gas will cool to near ambient temperatures.

As the fluid cools there is some danger of forming an aqueous phase. Colder H2S-rich liquid has a lower saturated water content. For example, at 40° C. and 4,000 kPa the saturated water content of H2S-rich liquid is about 2.0% water and at 30° C. and 4,000 kPa it is 1.7%.

In these cases, the possible water content is still greater than the actual water content of the liquefied acid gas (1.0%) and should not present a problem. However, this is something that the design engineer should check carefully.

As the gas cools to about 35° C., one must be concerned with the possibility of forming hydrates. At 15° C., 4,000 kPa, and 1.0% water, Fig. 2b shows (even though this is not to scale) that the fluid is in the LS + H region and thus the conditions are right for forming hydrates.

It is worth repeating: A hydrate may form even though free-water does not. Although there may not be a danger of forming an aqueous phase, one must be concerned with the hydrate.

Another interesting question in transporting acid gas is whether or not there should be cooling after the final compression stage. In general, the warmer the fluid enters the pipeline, the warmer it arrives at the wellhead.

If the acid gas enters the pipeline at a sufficiently high temperature it may never cool to the point where hydrates are a problem. However, the design engineer should carefully check the effect this may have on the potential for forming a liquid phase (either an aqueous liquid or an acid-gas liquid). And what effect this liquid might have on the pipeline.

Consider our simple compressor scheme, but further assume that a discharge temperature of 125° C. Because the mixture contains 1% water (saturated at the third stage), the fluid is a vapor, as seen in Fig. 2c.

As it cools to 103° C. and neglecting the pressure loss, Fig. 2d shows that it remains a vapor. By the time it cools to 50° C., it has become an H2S-rich liquid (Fig. 2a).

Somewhere between 103 and 50° C., the acid gas has liquefied. Merely by looking at the inlet and outlet conditions, one might assume that an aqueous phase was never formed. The transition was simply from a vapor to an LS phase.

But what phases were encountered in between? A mixture containing 99% H2S and 1% water is estimated to have an aqueous dew point at 4,000 kPa and about 68° C. Therefore at a certain point along the line, the fluid cools to the point where an aqueous liquid has formed.

This is followed by a three-phase (LS + LA + V) point at 4,000 kPa and about 57° C. Thus, at 57° C., the LS phase just begins to form, but it is present along with the vapor and an aqueous phase.

As it cools further (and this is an isothermal process, since we've assumed constant pressure), the aqueous phase disappears and an LS + V region is entered.

Finally, the vapor disappears and that is how one ends up with a single-phase exit condition.

Thus, the transition from vapor to H2S-rich liquid is complicated, and a potentially dangerous aqueous phase has been encountered. Merely by examining the inlet and exit conditions, one would have never expected this to happen.

Injection well

The situation in the injection well is opposite to that in the pipeline. As the fluid travels down the well bore, it warms up (due to the geothermal gradient) and the pressure increases (due to hydrostatic head).

If the acid gas is a liquid and remains liquid, then an aqueous phase should not form in the well bore. As mentioned earlier, the warmer the liquid acid gas the more water it can dissolve.

In addition, the solubility of water in H2S liquid is a weak function of the pressure. Note, by assuming that the fluid is always a liquid, one assumes that the temperature is always less than 106° C. (the three-phase critical end point) and the pressure is greater than the three-phase pressure.

The situation is less clear if the fluid injected is a gas. Consider a simple case where the fluid, which is 94 mol% H2S, enters the well at 125° C. Assume that the injection is isothermal, the wellhead pressure is 4,000 kPa, and the reservoir pressure is 12,000 kPa.

This is an extreme case conceived to make a point. Considering only the surface conditions, where the fluid is single phase, and the reservoir conditions, where the fluid is also a single phase, it is easy to conclude that an aqueous phase will not form. However, as the fluid travels down the well bore, it enters the two-phase region and an aqueous liquid forms. This can be seen in Fig. 2c.

It is somewhat difficult to see this effect when both the pressure and temperature are changing, as is the case in an injection well. What is clear is that conclusions based solely on the surface and reservoir conditions can be misleading.

Reference 1 contains a method for calculating the injection profiles for acid-gas disposal wells. If in doubt, it might be wise to determine the state of the fluid (for example, which phases are present) at each point along the integration.

Methanol injection

Methanol is commonly used to combat hydrate formation.

Methanol also effects the amount of water that a saturated acid gas can hold. Thus, the injection of methanol has the added benefit of reducing the possibility of forming an aqueous phase.

A thorough discussion of the phase equilibria in such systems is beyond the scope of this article. However, the design engineer is advised to study the effect of methanol injection on the injection scheme beyond just hydrate inhibition.

Multicomponent mixtures

This series was limited to a binary mixture. In industrial practice, we rarely encounter binary mixtures, and acid-gas injection is no exception.

Some phenomena described previously will be different for a multicomponent mixture. The most important is the behavior at a three-phase point.

For a binary mixture existing in three phases, the compression occurred isobarically and the composition of the phases did not change. For a multicomponent mixture, this is not the case. Both the pressure and the compositions change.

This is analogous to the liquefaction of a gas. For a single component, the isothermal liquefaction is an isobaric process. As was demonstrated previously, for the isothermal liquefaction of a binary mixture, the pressure changes.

Data sources

Some results discussed in this series were taken from experimental data, or correlations based on those data. On the other hand, some were calculated using the following rigorous thermodynamic models:
  • AQUAlibrium (copyright by John Carroll) for vapor plus aqueous liquid and vapor plus liquid plus liquid calculations
  • Hydrate 95 (copyright by DB Robinson & Associates) for hydrate calculations.
These software packages model the behavior with different methods and thus occasionally give results that seem to be in conflict.

As with all software, the user is wise to question the results obtained. This does not detract from the main theme of this series or the results presented.

The vapor pressure of water was obtained from Reference 2 and H2S data from Reference 3.


  1. Carroll, J.J, and Lui, D.W., OGJ., Vol. 95, No. 25, 1997, pp. 63-72.
  2. Haar, L., Gallagher, J.S., and Kell, G.S., NBS/NRC Steam Tables, Hemisphere Publishing, Co., Washington, DC, 1984.
  3. Goodwin, R.D., Hydrogen Sulfide Provisional Thermophysical Properties From 188 to 700 K at Pressures to 75 MPa, National Bureau of Standards Report No. NBSIR 83-1694, Boulder, Colo., 1983.

Copyright 1998 Oil & Gas Journal. All Rights Reserved.