Category: Gas Processing

In the last “Tip of the Month”, we evaluated the accuracy of two commercial process simulators against the experimental data. In this “Tip of the Month”, we will evaluate the accuracy of three shortcut methods for prediction of depression of hydrate formation temperature in the presence of two common inhibitors, methanol (MeOH) or mono ethylene glycol (MEG). We have used the same set of experimental data from the previous “Tip of the Month” as the basis for our evaluation. These shortcut methods may be used to calculate the required concentration of inhibitor and the injection rate for dew point correction process, NGL (Natural Gas Liquid) recovery, or pipeline transportation of natural gas. The detail of the calculation procedure is presented in chapter 6 of Volume 1 of Gas Conditioning and Processing [1]. The three methods evaluated are the Hammerschmidt (HA) [2], Nielsen- Bucklin (NB) [3], and Moshfeghian-Maddox (MM) [4]. These methods were used to predict hydrate formation temperature in the presence of inhibitors. Pure compounds as well as multi component natural gas mixtures covering a wide pressure range of up to 14500 psia (100 MPa) have been studied. Even though the shortcut methods presented in reference [1] could have been used, the required hydrate formation temperatures in the absence of inhibitor (pure water) were predicted by Parish and Prausnitz (PP) [5] for all three methods. This assured the same basis and accurate results. The strength and limitation of these methods are identified and recommendations for industrial applications have been made.

Table 1 presents the composition, inhibitor weight % range, pressure range, number of points, the reference of the experimental data for the gas mixtures studied in this work. The ability of the three methods to predict the hydrate formation temperature for gas E is shown in Figure 1. The accuracy of these methods, for CH4, C2H6, C3H8, CO2, H2S and their mixtures as shown in Table 1, are presented in Figures 1 and 2 for MeOH and Figures 3 and 4 for MEG.

Figure 1 indicates that the PP method predicts the hydrate formation temperature for gas E in the presence of pure water (0 wt% MeOH) accurately. This method was used to add its perdition temperature to the depression temperature predicted by the three shortcut methods for the sake of easy comparison with the experimental data. Figure 1 also indicates that all three methods give good results for 20 wt% MeOH; however, for 40 wt% MeOH, the HA results deviate from the experimental data considerably.

The analysis of Figures 2 indicates that all three methods give accurate results for temperature as low as 20 °F (-6.7 °C) equivalent to maximum of 25 wt% MeOH, but at lower temperature (or higher MeOH concentration) the HA method deviates from the experimental data considerably. For lower temperatures, the MM gives better results than the NB method.

Figure 3 and 4 indicate that all three methods give accurate results for gas mixture F up to concentration of 50 wt% MEG (as low as 0 °F or -18 °C) for which experimental data were available but their prediction for some of the pure compounds below this temperature is questionable.

To learn more about inhibitor injection we suggest participating in our G4 (Gas Conditioning and Processing) and G5 (Gas Conditioning and Processing – Special) courses.

By: Dr. Mahmood Moshfeghian

References:

1. Campbell, J. M., “Gas Conditioning and Processing, Vol. 1, the Equipment Modules, 8th Ed., J. M. Campbell and Company, Norman, Oklahoma, 2001
2. Hammerschmidt, E.G., ‘Formation of gas hydrates in natural gas transmission lines,” Ind & Eng. Chem, Vol. 26, p. 851, 1934
3. Nielsen, R. B. and R.W. Bucklin, “Why not use methanol for hydrate control,” Hydrocarbon Processing, Vol 62, No. 4, P 71, April 1983
4. Moshfeghian, M. and R. N. Maddox, “Method predicts hydrates for high- pressure gas streams,” Oil and Gas J., August 1993.
5. Parrish, W. R. and J. M. Prausnitz. “Dissociation Pressures of Gas Hydrates Formed by Gas Mixtures”, Ind. Eng. Chem. Proc. Dev.,11, 1, 26-35, (1972).
6. Ng, Heng-Joo, and D.B. Robinson, Research Report RR-66, Gas Processors association, Tulsa, Oklahoma, 1983
7. Ng, Heng-Joo, C.J. Chen, and D.B. Robinson, research report RR-106, Gas Processors Association, Tulsa, Oklahoma, 1987
8. Blanc, C., and Tournier-Lasserve, J., World Oil, November, 1990.
9. Ng, Heng-Joo, C.J. Chen, and D.B. Robinson, research report RR-92, Gas Processors Association, Tulsa, Oklahoma, 1985

Many materials may be added to water to depress both hydrate and freezing temperatures. For many practical reasons an alcohol or one of the glycols is injected as an inhibitor, usually methanol, diethylene glycol (DEG) or mono ethylene glycol (MEG). All may be recovered and recirculated, but economic of methanol recovery may not be favorable in many cases. Total injection rate is that needed to provide the necessary inhibitor concentration in the liquid water plus that inhibitor which enters the vapor and hydrocarbon liquid phases. Any inhibitor in the vapor phase or liquid hydrocarbon phase has little effect on hydrate formation conditions. Determination of the amount and concentration of inhibitors and their distribution in different phases are very important for practical purposes and industrial applications. Therefore, in order to determine the required amount and concentration of these inhibitors, several thermodynamic models for hand and rigorous calculations have been developed and incorporated into the computer software.

In this Tip of the Month, we will evaluate the accuracy of two commercial process simulators “A” and “B” against the experimental data. These softwares were used to predict hydrate formation condition in the presence of inhibitor. Pure gas component as well as multi component natural gas mixtures covering a wide pressure range of up to 100 MPa have been studied. These softwares may be used to simulate an integrated NGL (natural gas liquid) plant with inhibitor injection and regeneration process. The optimum concentration and circulation rate are determined using different softwares. The strength and limitation of these softwares are identified and recommendations for industrial applications have been made.

Table 1 presents the composition, inhibitor weight % range, pressure range, number of points, the reference of the experimental data for the gas mixtures studied in this work. The ability of the two softwares to predict the hydrate formation temperature for gas E is shown in Figure 1. The accuracy of these softwares for CH₄, C₂H₆, C₃H₈, CO₂, H₂S and their mixtures as shown in Table 1 are presented in Figures 2 and 3; for methanol and MEG, respectively

The analysis of Figures 2 and 3 indicates that for methanol inhibition, the lower limits of hydrate formation temperatures are -75°F (-60°C) for Sim A (maximum of 70 wt% methanol) and -25°F (-32°C) for Sim B (Maximum of 50 wt% methanol). It should be pointed out that Sim B could not converge for cases of 85 wt% methanol. For MEG, both softwares give accurate results down to 25°F (-4°C) corresponding to 25 wt% MEG; however, for lower temperatures the accuracy drops while the Sim A gives better results. To learn more about inhibitor injection we suggest participating in our G4 (Gas Conditioning and Processing) and G5 (Gas Conditioning and Processing – Special) courses.

By: Dr. Mahmood Moshfeghian

References:

1. Ng, Heng-Joo, and D.B. Robinson, Research Report RR-66, Gas Processors association, Tulsa, Oklahoma, 1983
2. Ng, Heng-Joo, C.J. Chen, and D.B. Robinson, research report RR-106, Gas Processors association, Tulsa, Oklahoma, 1987
3. Blanc, C., and Tournier-Lasserve, J., World Oil, November, 1990.
4. Ng, Heng-Joo, C.J. Chen, and D.B. Robinson, research report RR-92, Gas Processors association, Tulsa, Oklahoma, 1985

In this Tip of the Month, we will study two alternatives for removal of H₂S and CO₂ from natural gas. The process objective is to produce a sweet gas with less than 4 PPM H₂S and the near total removal of CO₂ due to the presence of a downstream nitrogen rejection unit (NRU). Each alternative consist of two stages of acid gas removal. The schematic diagrams for both alternatives are shown in Figure 1. The detail of gas sweetening may be found in the Gas Conditioning and Processing, Vol. 4, “Gas and Liquid Sweetening”.

In option A, sour natural gas is treated in the MDEA unit to selectively remove H₂S and part of the CO₂. The partially treated gas is then sent to the DEA unit for removal of the remaining CO₂. The acid gas from the MDEA unit is sent to the sulfur recovery unit (SRU). The acid gas from the DEA unit, mainly CO_2, and tail gas from the SRU are sent to the incinerator.

In the second alternative (Option B), all of the H₂S and CO₂ are removed in the DEA unit and sent to the MDEA unit where H₂S is selectively removed at low pressure. The H₂S enriched acid gas from the MDEA unit is sent to the SRU. The CO₂ from the MDEA contactor is routed directly to the incinerator unit.

We performed rigorous computer simulation for both alternatives with typical process specifications. The simulation results showed that arrangement of the MDEA and DEA units and the order of their utilization make a difference in the concentration of H₂S in the acid gases fed to the sulfur recovery unit. Our study indicated that option B produces richer H₂S in the acid gases stream, producing a more suitable feed for sulfur recovery unit. A drastic reduction of pumping was obtained for option B. Smaller diameter and fewer number of trays for the contactor of the MDEA unit in Option B are needed. An additional benefit of option B is that less pick up of heavy hydrocarbons from the feed gas was obtained. This will benefit both the operation of the amine units and the SRU. The preliminary evaluation indicates that the overall energy consumption is lower for option B which has more favorable performance. However, for decision making process, a detail economic analysis for both options is highly recommended.

Similar cases in gas sweetening are discussed in our GAS TREATING AND SULFUR RECOVERY (G-6) and REFINERY GAS TREATING, SOUR WATER, SULFUR AND TAIL GAS (RF-61) courses

By: Dr. Mahmood Moshfeghian and Mark E. Bothamley

References:

Maddox, R.N., and D.J. Morgan, “Gas Conditioning and Processing, Vol. 4, Gas and Liquid Sweetening,” 4^th Ed., John M. Campbell & Company, Norman Oklahoma, (1998)

In this Tip of the Month, we will explore the regeneration of molecular sieve dehydrators. Can you save energy by ending the heating cycle when the regeneration outlet temperature reaches approximately 90% of the regeneration inlet heating temperature? Frequent readers of the Tip of the Month surely know the answer: it depends!

But on what does it depend? There are many factors to consider, but to simplify this discussion we shall assume a molecular sieve unit designed to do the following:

• Dehydrate natural gas to less than 1 ppmv
• Heating and cooling are done countercurrent to adsorption and the regeneration medium is bone dry
• The regeneration inlet temperature to the molecular sieves is 288˚C (550˚F)

First, let’s take a brief review of the entire cycle.  Molecular sieve dehydrators are typically two or three tower units. While one vessel is being regenerated, the remaining vessels are adsorbing water from the flowing natural gas.

Below is a simplified cycle schedule showing a three bed dehydrator where A1=First Half of Adsorption Cycle Time, A2=Second Half of Adsorption Cycle Time, C= Cooling Cycle Time and H=Heating Cycle Time:

Not shown in this cycle schedule are the times required to depressurize and re-pressurize the system. The time required for these steps are included in the regeneration cycle and must be done in such a manner to avoid lifting the molecular sieves and/or causing a mechanical bed support failure.

The astute reader will notice the total regeneration time per vessel (heating plus cooling time) must be equal to or less than the total adsorption time per vessel (A1+A2). Failure to accomplish this will result in early water breakthrough of the vessel on adsorption and will ruin someone’s day.

Let’s now explore the mechanisms that lie behind the regeneration cycle of a molecular sieve bed.  During regeneration sufficient sensible heat must be provided to heat everything in the vessel up to 260˚C (500˚F) or so. This includes the molecular sieves, the inert support media, the metal, etc.  The heat of desorption of the water must also be supplied. The sum of the sensible heat plus heat of desorption is the required regeneration heat and helps set the regeneration heating cycle. The heating time is larger than the cooling time because the heating cycle must provide the heat of desorption of water while the cooling cycle is concerned only with sensible heat.

There is more to regeneration than simply waiting until the temperature of the spent regeneration gas reaches a plateau before switching to cooling.  The heating cycle is not complete until the water is swept out of the system and the molecular sieves have reached their design residual water loading. During low pressure regeneration, the limiting step is simply getting the total required heat into the bed of molecular sieves. In this instance, once the outlet temperature reaches approximately 90% of the inlet temperature [262˚C (500˚F)], the heating cycle is completed. In some situations, the heating cycle is actually stopped before the outlet temperature reaches 262˚C (500˚F). Such a cycle is called a thermal pulse.

During high pressure regeneration, the limiting step is getting the water away from the molecular sieves. Despite the fact that the outlet temperature has reached a plateau, the regeneration may not be completed because the high pressure gas cannot carry away the water molecules. In this situation, you have to continue heating the molecular sieves for a period of time until the residual moisture left in the bed is equal to or less than what it was designed for.

This should lead the reader to ask “How can I tell what is limiting my regeneration?” The answer to this is not so simple. One could run field trials; however, this is time consuming and provisions must be taken to avoid premature water breakthrough. It would be much simpler to contact your molecular sieve vendor and ask them. They have design techniques available to determine what the limiting mechanism is.

A conservative rule of thumb is if the regeneration pressure is greater than 4 MPa [600 psia], be careful. Sweeping the water from the molecular sieves may be your limiting step. This discussion assumes you are operating between a minimum pressure drop during the regeneration heating cycle of 0.23 kPa/m [0.01 psi/ft] to ensure good flow distribution and a maximum pressure drop of 5.4 kPa/m [0.24 psi/ft] to avoid bed lifting.

Harvey M. Malino

Problems in meeting sales-gas dew point specifications are not unusual.  A facility engineer often suspects separator carryover when trouble-shooting such a plant.  Proper sizing of equipment for vapor-liquid separation is essential to almost all processes.  The fundamentals of a simple separator design may be extended to several other processes such as fractionation towers, two-phase flow, slug catcher design etc.  Many facility operating problems are related to improperly designed or under-sized gas-liquid separators.

In this Tip of the Month, we will demonstrate the impact of liquid carry over on the sales gas “spec dew point”. Let’s consider the process flow diagram shown in Figure 1 for a simple gas plant. The feed composition and condition are shown in Table 1.

It is desired to process this feed gas to produce a sales gas with a dew point of 20 ˚F (-6.7˚C) at 540 psig (3.723 MPa) The feed gas is mixed with recycle gas from stabilizer, compressed and cooled to 110˚F (43.3˚C) and 555 psig (3.827 MPa), then cooled in the gas-gas exchanger, gas-liquid exchanger and finally in the chiller to 20˚F (-6.7˚C) before entering the separator at 540 psig (3.723 MPa). The phase envelopes for the feed, vapor and liquid streams of the separator are shown in Figure 2. Figure 2 presents the phase behavior of separator if it was operating perfectly, without any liquid carry over or entrainment. In real life, the situation is different and most probably there would be some liquid carry over. In order to show the impact of liquid carry over, we withdraw a small portion of liquid stream from separator and remixed it with the vapor stream and recalculated the dew point temperature. Figure 3 shows how the sales gas dew point curves shift to the right as the percentage of liquid carry over increases. Figure 4 shows the calculated sales gas dew point temperature, at 540 psig (3.723 MPa), as a function of percentage of liquid carry over. It is interesting to note that even a 5% liquid carry over shifts the dew point temperature by more than 20˚F (11˚C) which may results in unexpected large amount of condensate as the gas transported in the pipeline or cause severe damage to the downstream compressor. To learn more about similar cases and how to prevent operational problems such as liquid carry over, we suggest attending our G4 and G5 courses.

By: Dr. Mahmood Moshfeghian

In a previous “Tip of the Month” we discussed several methods of heavy ends characterization and as an example, for a rich natural gas, we tuned the heavy end parameters to match the experimentally measured saturation pressure. After tuning the heavy end parameters, we obtained a phase envelope for each method that passed through the experimental dew point; however, their shapes and specifically, their cricondentherm points were different. At the end, we were faced with the question of “which one is the right phase envelope?”

In this tip, we will explain a procedure for selecting an appropriate C₆₊ characterization method which results in a broader match with the experimental information. For further detail, please refer to Gas Conditioning and Processing, Volume 3, Advanced Techniques and Applications.

Let’s consider a lean natural gas with the composition shown in the first two columns of Table 1. This lean gas contains only 0.067 mol% C₆₊ and even though the amount of C₆₊ is very small, we will see that it has a large impact on the condensate. The detail laboratory analyses [1] of C₆₊ are shown in the 1^st and 2^nd columns of Table 1. We used the SRK EoS in GCAP Software for Vol. 3 of Gas Conditioning and Processing and determined the C₆₊ properties of MW=94.12, SG=0.738, andNBP=195 °F. All other calculations were performed using theSRK EoS.

Table 1. Characterization/Distribution of C₆₊ by different methods

We have plotted the experimentally measured Potential Hydrocarbon Liquid Condensed (PHLC) at 594.7 psia as a function temperature in Figure 1, and by extrapolation, a dew point temperature of 52.1 °F was obtained. We used the methods discussed in the previous tip of the month to characterize the C₆₊ by matching the experimentally determined dew point. For each method, we have presented the tuned MW and distribution of components in Table 1 and the predicted PHLC as a function of temperature and the phase envelope were plotted in Figures 1 and 2, respectively. It should be pointed out that the cricondentherm for the lumped C₆₊ method was below 15 °F; therefore, zero values for PHLC were predicted.

Figure 2 indicates that three of the characterization methods practically generate the same phase envelope. Are all of these phase envelopes presenting the true phase behavior of this lean gas? The answer is “Yes” and “NO”. Figure 1 indicates that, for temperatures close to the dew point, all three methods predict the PHLCs very close to the experimental values; however, at lower temperatures (about 20 °F) the deviation from experimental values increases. Only the normal alkane distribution method gives accurate values even at lower temperatures.

In summary, for sound process design and/or operation we suggest using at least one experimental saturation measurement such dew point or bubble point near the potential operating conditions to characterize the heavy ends. Once the characterization is established, additional experimental measurements should be utilized to verify the accuracy and validity of the tuning technique.

By: Dr. Mahmood Moshfeghian

Reference:

1. Derks, P. A. H., van der Meulen-Kuijk, L., and Smit, A. L. C., “Detailed Analysis of Natural Gas for an Improved Prediction of Condensation Behavior,” Proceedings, 72^nd Annual Convention, Gas Processors Association, 1993.
2. Riazi, M.R. and T.E. Daubert, Hydr. Proc. P. 115, (March) 1980

In a previous “Tip of the Month” we explained how a phase envelope is generated and what factors affect the shape and accuracy of a phase envelope.

In this tip, we will show several methods of C₇₊ (heavy ends) characterization and check the accuracy of each method and present tips to improve the accuracy of each method. For more detail, please refer to Gas Conditioning and Processing, Volume 3, Advanced Techniques and Applications.

Let’s consider a rich gas with the composition shown in the first two column of Table 1. This rich gas contains 3.1 mol% C₇₊ with reported MW=132 and SG=0.774. The experimentally measured dew point pressure is 4075.6 psia at 180.4 °F. For this case study, we will use PR EoS, needless to say that similar results are obtained by SRK EoS.

Method A: In this method we will treat C₇₊ as a single cut and based on its MW and SG, we will predict its normal boiling point (NBP=317.2 °F), critical temperature (Tc=645.2 °F), critical pressure (Pc=371.6 psia), and acentric factor (ω=0.425574) using correlations similar to the ones by Riazi and Duabert [1] which are on page 107, Chapter 4, Gas Conditioning and Processing, Volume 1, Basic Principles. The predicted dew point pressure is 3433 psia far away from the measured value of 4076 psia. The predicted phase envelope for this method is shown in Figure 1. As can be seen, this phase envelope does not pass through the measured dew point.

Method B: We break the C₇₊ into 11 Single Carbon Numbers (SCN) ranging from SCN 7 to SCN 17+ using the exponential decay procedure presented by Katz [2] and applied by others [3-5]. The resulting distributions are shown in the 3^rd and 4^th column of Table 1. The predicted dew point pressure is 4030 psia which is relatively accurate. The corresponding phase envelope is shown in Figure 1 which almost passes through the measured dew point.

Method C: We lumped the 11 SCN components of Method B into 4 cuts. These cuts and compositions are shown in the 5^th and 6^th column of Table 1. The predicted dew point pressure is 3885 psia and the corresponding phase envelope is plotted in Figure 1.

Method D: This method is similar to Method B, except that we used 12 normal parafins (alkanes) instead of SCN components to represent the C₆₊. The 7^th and 8^th column of Table 1 present the distribution of nC₆ to nC₁₇. The predicted dew point pressure is 3730 psia and the corresponding phase envelope is also shown on Figure 1. The advantage of this method is that n-alkane components are readily available in many commercial software where as the SCNs may not.

Figure 1 indicates that none of the methods, except method B which come close, matches the experimentally measured dew point. In the next section, we show how the prediction of each method can be improved to match the experimentally measured dew point.

Adjusting MW (or Tc) in Method A: As can be seen in Figure 2, by changing MW of C₇₊ to 152.5, we can match the measured dew point, perfectly. Please note that based on MW=152.5 and SG=0.774, the new values for the estimated properties will be NBP= 381 °F, Pc=308.4 psia, Tc=706.9 °F, and ω= 0.468456. An alternative option is to adjust only Tc to 703.5 °F. Again, the tuned Tc makes the phase envelope pass through the measured dew point as shown in Figure 2. The Tc adjustment is preferred because less work is involved.

Tuning binary interaction parameters, k_ij, in Methods B and C: A common correlation to estimate the binary interaction parameter is:

In the above equation, Vc_i and Vc_j represent the critical volumes of components i and j, respectively. The default value of exponent n is normally set to 1.2 but it can be used as a tuning parameter to match the experimentally measured dew point. For our case study, we obtained n=1.3011 for Method B and n=1.6573 for Method C. The resulting phase envelopes for these two methods are shown in Figure 2.

Tuning MW in Method D: The distribution (i.e. mole %) of the alkane part of C₆₊ depends on the assumed value of C₆₊ MW. As shown in Figure 2, by changing MW of C₆₊ to 154, we can match the measured dew point, perfectly.

As can be seen from Figure 2, all of the generated (tuned) phase envelopes are passing through the measured dew point; but they have different cricondentherm point. Are all of these phase envelopes correct? In the next tip of the month we will demonstrate how to choose the most accurate phase envelope!

By: Dr. Mahmood Moshfeghian