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Composition variety complicates processing plans for US shale gas

This article reviews which gas processing technologies are appropriate for the variety of US shale gas qualities being produced and planned to be produced.

Keith Bullin and Peter Krouskop
Bryan Research & Engineering
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Article Summary
Recently, higher gas prices and improved drilling technology have spurred shale gas drilling across the US. Figure 1 shows the shale plays currently being explored. Some of the more popular areas are the Barnett, Haynesville and Fayetteville shales in the South, and the Marcellus, New Albany and Antrim shales in the East and Midwest. These plays represent a large portion of current and future gas production.

But all shale gas is not the same, and gas processing requirements for shale gas can vary from area to area. As a result, shale gas processors must be concerned about elevated ethane and nitrogen levels across a field. Other concerns are the increased requirements of urban gas processing. In addition, the rapid production growth in emerging shale areas can be difficult to handle.

This article will review which gas processing technologies are appropriate for the variety of gas qualities being produced and planned to be produced.

Gas processing
Gas processing removes one or more components from harvested gas to prepare it for use. Common components removed to meet pipeline, safety, environmental and quality specifications include H2S, CO2, N2, heavy hydro- carbons and water. The technique employed to process the gas varies with the components to be removed as well as with the properties of the gas stream (eg, temperature, pressure, composition and flow rate).

Acid gas removal is commonly by absorption of the H2S and CO2 into aqueous amine solutions. This technique works well for high-pressure gas streams and those with moderate to high concentrations of the acid gas component.

Physical solvents such as methanol or the polymer DEGP, or Selexol may also be used in some cases. And, if the CO2 level is very high, such as in gas from CO2 flooded reservoirs, membrane technology affords bulk CO2 removal in advance of processing with another method. For minimal amounts of H2S in a gas stream, scavengers can be a cost-effective approach to H2S removal.

Natural gas that becomes saturated with water in the reservoir requires dehydration to increase the heating value of the gas and to prevent pipeline corrosion and the formation of solid hydrates.

In most cases, dehydration with a glycol is employed. The water-rich glycol can be regenerated by reducing the pressure and applying heat. Another possible dehydration method is use of molecular sieves that contact the gas with a solid adsorbent to remove the water. Molecular sieves can remove the water down to the extremely low levels required for cryogenic separation processes.

Distillation uses the different boiling points 
of heavier hydrocarbons and nitrogen for 
separation. Cryogenic temperatures, required for the separation of nitrogen and methane,
are achieved by refrigeration and expansion 
of the gas through an expander. Removal of 
the heavy hydrocarbons is dictated by 
pipeline quality requirements, while deep removal is based on the economics of NGL production.

Shale gas processing requirements
The following reviews six shale gas plays, their compositions, and processing needs: Barnett, Marcellus, Fayetteville, New Albany, Antrim and Haynesville.

The Barnett shale formation is the grandfather of shale gas plays. Much of the technology used in drilling and production of shale gas has been developed on this play. The Barnett shale formation lies around the Dallas-Ft. Worth area of Texas (see Figure 2) and produces at depths of 6500-9500ft. The average production rate varies throughout the basin from 0.5 MMscfd to 4 MMscfd, with estimates of 300-350 scf of gas per ton of shale.1 The most active operators in the region are Chesapeake Energy, Devon, EOG Resources and XTO.

The initial discovery region was in a core area on the eastern side of the play. As drilling has moved westward, the form of the hydrocarbons in the Barnett shale has varied from dry gas prone in the east to oil prone in the west.

Table 1 shows the composition of four wells in the Barnett. These wells appear from east to west, with the eastern most well on the top (Well No. 1). As the table suggests, there is a large increase in the amount of ethane and propane as the wells move west.

One well sample on the western edge of the play (Well No. 4) shows a high level (7%) of nitrogen. This level is high enough to require treating, but blending with other gas in the area is the most economical solution.

The gas processing industry has scrambled to keep up with the tremendous growth of the Barnett Shale. Production has jumped from almost nothing in 1999 to approximately 4 BCFD currently. To sustain this growth, the gas processing industry has added the equivalent of a 100 MMscfd cryogenic facility to the area every three months for 10 years. Some of the major gas plants processing Barnett shale gas are the Devon Bridgeport Facility (1 BCFD), Quicksilver Cowtown Plant (200 MMCFD) and Corvette Plant (125 MMSCFD), Enbridge Weatherford Facility (75 MMSCFD), Energy Transfer Godley Plant (300 MMSCFD), the Crosstex Silver Creek (200 MMSCFD), Azle (55 MMCFD) and Goforth (35 MMCFD) plants, the Targa Chico (150 MMSCFD) and Shackelford (125 MMSCFD). Crosstex has announced plans to add the Bear Creek Plant with an additional 200 MMSCFD capacity in late 2009.

The majority of these plants include compression, CO2 treating with amine units, cryogenic separation and fractionation. The processed gas heads East toward Carthage where it can reach the Midwest via the Perryville Hub, or the Northeast via the Transco or Texas Eastern pipeline, or the Southeast via the Transco or Florida Gas pipeline. With the richness of the gas, the Barnett plants remove about 3.5 gallons of natural gas liquids per MSCF of gas. Based on the current 4 BCFD of gas production, approximately 325 000 barrels of natural gas liquids are produced each day.
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