gas to be saturated with water because water is sent down the well to maintain well pressure. It is not uncommon for there to also be free water in the incoming gas stream; however this is easily removed using a knockout drum on the front end of the process at minimal cost.
Inlet feeds enter the processing plant at a standard vapor volumetric flow of 150 million standard cubic feet per day (MMSCFD), 100 °F, and 1000 psig. The Peng–Robinson equation of state was used in the process simulation model.
The gas feedstock is saturated with water.
2.4.1 Data
First, compositional data was obtained for the Barnett Shale region (located in the Dallas, TX, area) [3]. Next, minor components such as nitrogen, oxygen, and hydrogen were removed from the data sets so that only the major components (CO2 and the hydrocarbons) were considered. The compositional data sets were classified into different types. This was done based on the methane composition in each data set. There were five types of data sets as shown in Table 2.1. Table 2.1 also shows the probability of each feed type as determined from the literature data [3].
Table 2.1 Feed types as determined by methane composition.
| Feed type | Methane composition (mol%) | Probability of feed type (%) |
| 1 | >87 | 7.50 |
| 2 | 81–87 | 28.33 |
| 3 | 75–81 | 28.33 |
| 4 | 69–75 | 28.33 |
| 5 | <69 | 7.50 |
Next, one case from each feed type was selected from among the data sets. The case chosen for each feed type was a case found near the middle of the distribution. A total of five cases were selected (see Table 2.2). From among these cases, the base case was selected as type 3 case since it falls nearest to the middle of the distribution and is representative of the most commonly found composition in this region.
Table 2.2 Selected cases.
| Composition (mol%) | Feed #1 | Feed #2 | Feed #3 | Feed #4 | Feed #5 |
| Methane | 94.11 | 83.62 | 77.78 | 71.94 | 56.34 |
| Ethane | 2.59 | 7.54 | 9.42 | 11.55 | 16.13 |
| Propane | 0.02 | 4.68 | 7.26 | 9.60 | 16.06 |
| n‐Butane | 0.25 | 2.11 | 2.65 | 3.15 | 4.96 |
| i‐Butane | 0.26 | 1.08 | 1.27 | 1.61 | 2.62 |
| n‐Pentane | 0.02 | 0.30 | 0.60 | 0.82 | 1.60 |
| i‐Pentane | 0.03 | 0.30 | 0.53 | 0.76 | 1.44 |
| Neopentane | 0.00 | 0.00 | 0.00 | 0.02 | 0.04 |
| Carbon dioxide | 2.71 | 0.38 | 0.49 | 0.56 | 0.81 |
Finally one additional case is considered. As mentioned in the introduction, sulfur species, predominately hydrogen sulfide, may also be found in shale gas [6]. The goal of considering this case is to determine if the additional processing needed for a gas with a high acid (HA) loading would significantly affect the economics of treating such a stream. This inlet composition of this case was chosen such that the methane and NGL content would be similar to that of the base case (Feed #3) (Table 2.3).
Table 2.3 High acid (HA) gas feed composition.
| Composition (mol%) | HA feed |
| Methane | 74.35 |
| Ethane | 9.00 |
| Propane | 6.94 |
| n‐Butane | 2.54 |
| i‐Butane | 1.22 |
| n‐Pentane | 0.57 |
| i‐Pentane | 0.51 |
| Neopentane | 0.00 |
| Carbon dioxide | 4.78 |
| Hydrogen sulfide | 0.10 |
2.4.2 Process Simulations and Economic Evaluation
Process simulation was performed to meet the required specifications (sales gas gross heating value of 950–1150 Btu/SCF [British thermal unit/standard cubic feet], 1000 psig, and CO2 content of 2–3 mol% maximum, 0.3 g H2S/100 SCF gas) [22,23], and process designs were developed for each feed. ProMax simulation software [24] was used to simulate
