Overview

Video: Lesson 12 (5:38)

Overview

Natural gas has become a very significant fossil fuel in the U.S. because of a sharp increase in shale gas production starting in 2006. The U.S. Energy Information Administration projects that the U.S. natural gas production will increase 44% from 23.0 trillion cubic feet in 2011 to 33.1 trillion cubic feet in 2040 [1]. Almost all of this increase in domestic natural gas production is due to projected growth in shale gas production, which is projected to grow from 7.8 trillion cubic feet in 2011 to 16.7 trillion cubic feet in 2040. It is interesting to note that before the shale gas boom (that has taken place largely in Pennsylvania), the U.S. was planning to import liquefied natural gas (LNG) from countries as far as Peru with the planned construction of LNG ports in California and other states. Currently, there are prospects of exporting LNG overseas in the near future. One particular aspect of the natural gas boom that concerns the petroleum refining industry is the increased production of natural gas liquids (NGL) that are co-produced with natural gas. NGL consist of light hydrocarbons, and they have become an important non-conventional feedstock for refineries, contributing mainly to gasoline production. This new input to refineries along with the increased domestic oil production by the new drilling technology has helped small inland refineries that do not have easy access to imported crude oil as, for example, Gulf Coast refineries.

This lesson will provide an overview of the natural gas processing that employs the same techniques and processes as we have covered in petroleum refining operations, such as in Light Ends Unit for fractionation of light hydrocarbons, and recovering H₂S, as well as its conversion to S. Brief introductions to shale gas and natural gas liquids will be presented before discussing the natural gas processing.

Learning Outcomes

By the end of this lesson, you should be able to:

• appraise different natural gas reserves (conventional, tight, and shale) and assess the contribution of natural gas to energy supply;
• illustrate and evaluate the different stages of natural gas processing, including condensate removal, acid gas removal, water removal, fractionation of natural gas liquids.

What is due for Lesson 12?

This lesson will take us one week to complete. Please refer to the Course Syllabus for specific time frames and due dates. Specific directions for the assignment below can be found in this lesson.

Questions?

If you have any questions, please post them to our Help Discussion (not email), located in Canvas. I will check that discussion forum daily to respond. While you are there, feel free to post your own responses if you, too, are able to help out a classmate.

Shale Gas

Shale gas refers to natural gas that is trapped within shale formations, as different from conventional natural gas resources, such as associated (produced with crude oil), or non-associated (without crude oil) natural gas that is found mostly in sandstone formations. Shales are fine-grained sedimentary rocks that can be rich sources of petroleum and natural gas. Over the past decade, the combination of horizontal drilling and hydraulic fracturing has allowed access to large volumes of shale gas that were previously uneconomical to produce. The production of natural gas from shale formations has invigorated the natural gas industry and the small inland refineries in the United States.

Figure 12.1 shows the EIA data and projections on dry natural gas production in the U.S., indicating the surge in shale gas production, while the conventional associated and non-associated gas production are expected to decline [3]. Dry natural gas refers to natural gas that consists, essentially, of methane without any significant concentration of condensable hydrocarbons, such as propane and butane, that are present in natural gas liquids.

Figure 12.1. History and projections of dry natural gas production in the U.S. [2].

Source: U.S. Energy Information Administration, Annual Energy Outlook Early Release

Natural Gas Liquids

Natural gas liquids (NGLs) are composed of hydrocarbons, including ethane, propane, butane, isobutane, pentane, and higher alkanes. Although ethane cannot be readily liquefied by pressure at ambient temperature such as propane and butane (LPG) it is considered a component of NGL. There are many uses for NGLs, as summarized in Table 12.1 [3]. NGLs are extracted from the natural gas production stream in field processing plants, using techniques discussed related to petroleum refining operations.

NGL field production is growing in the United States, representing an important part of the supply picture.

C indicates carbon, H indicates hydrogen; Ethane contains two carbon atoms and six hydrogen atoms

*Pentanes plus is also known as "natural gasoline." Contains pentane and heavier hydrocarbons. 

Table 12.2. Some components and applications of natural gas liquids [3].

Source: US Energy Information Administration 

Natural Gas Composition and Specifications

Natural gas as recovered at the wellhead consists of mostly methane (C₁), but it contains other hydrocarbons, principally ethane (C₂), propane (C₃), butanes (C₄), and pentanes C₅ that constitute the natural gas liquids, as discussed in the previous section. Raw natural gas also contains water vapor, hydrogen sulfide (H₂S), carbon dioxide, nitrogen, helium, and other impurities, such as mercury. Table 12.3 gives some examples of the composition of natural gas produced in three different locations, to give an example that methane content of natural gas can be as low as 65%. One can also note in Figure 12.2 that some natural gas streams may contain high concentrations of H₂S and N₂. Some natural gas streams could be a commercial source for helium [4]. One of the important objectives of natural gas processing is to remove the corrosive and toxic gas H₂S and convert it to elemental sulfur, as will be discussed later. Important impurities, including those shown in Table 12.3, that need to be removed from natural gas are listed below [5].

Important impurities found in natural gas [5].

• Water: Most gas produced contains water, which must be removed. Concentrations range from trace amounts to saturation.
• Sulfur species: If the hydrogen sulfide (H₂S) concentration is greater than 2 to 3%, carbonyl sulfide (COS), carbon disulfide (CS2), elemental sulfur, and mercaptans may be present.
• Mercury: Trace quantities of mercury may be present in some gases; levels reported vary from 0.01 to 180 μg/Nm³. Typically, the mercury level in pipeline gas should be reduced to 0.01 μg/Nm³.
• Diluents: Although the gases shown in Figure 12.2 are typical, some gases have extreme amounts of undesirable components. For example, some wells in Colorado contain as much as 92% carbon dioxide. High hydrogen sulfide contents (e.g., in Alberta, Canada), and nitrogen contents (e.g., in Texas) have also been observed.
• Oxygen: Some gas-gathering systems in the United States operate below atmospheric pressure. As a result of leaking pipelines, open valves, and other system compromises, oxygen is an important impurity to monitor. A significant amount of corrosion in gas processing is related to oxygen contamination.

Considering that the principal transportation of natural gas over land is by pipeline, natural gas specifications for pipeline transmission have been developed. Table 12.4 gives the natural gas specifications that need to be satisfied for pipeline transportation. Note that in addition to the specified impurity levels for the contaminants, the specifications include the heating value of natural gas (950 -1150 Btu/scf) which depends on the composition, particularly the concentration of inert gases (e.g., N₂ and CO₂) and other diluents.

Table 12.4. Specifications for pipeline quality natural gas [6].

Click for a text description of Table 12.4

Specifications for Pipeline Quality Gas

Major Components	Minimum Mol%	Maximum Mol%
Methane	75	None
Ethane	None	10
Propane	None	5
Butanes	None	2
Pentanes and heavier	None	0.5
Nitrogen and other inerts	None	3
Carbon dioxide	None	2-3
Total diluent gases	None	4-5

Trace Components:

• Hydrogen sulfide: 0.25-0.3 g/100 scf  (6-7 mg/m³)
• Total sulfur: 5-20 g/100 scf (115-460 mg/m³)
• Water Vapor: 4.0-7.0 lb/MM scf (60-110 mg/m³)
• Oxygen: 1.0%

Other Characteristics:

• Heating calculated (gross, saturated): 950-1,150 Btu/scf (35,400-42,800 kJ/m³)
• Liquids: Free of liquid water and hydrocarbons at delivery temperature and pressure.
• Solids: Free of particulates in amounts deleterious to transmission and utilization equipment.

Natural Gas Processing 

A comparison of Images 12.2 and 12.3 illustrates the significance of natural gas processing for purification of the raw natural gas to obtain a pipeline quality gas. In general, natural gas processing includes the following steps:

• Condensate and Water Removal
• Acid Gas Removal
• Dehydration – moisture removal
• Mercury Removal
• Nitrogen Rejection
• NGL Recovery, Separation, Fractionation, and Treatment of Natural Gas Liquids

In addition to these processes, it is often necessary to install scrubbers and heaters at or near the wellhead. The scrubbers remove sand and other large-particle impurities. The heaters ensure that the temperature of the natural gas does not drop too low and form a hydrate with the water in the gas stream. Natural gas hydrates are crystalline ice-like solids or semi-solids that can impede the passage of natural gas through valves and pipes.

A generalized natural gas flow diagram is shown in Figure 12.2 [7]. After initial scrubbing to remove particles, the first step in natural gas processing is the removal of condensate (oil) and water that is achieved by controlling the temperature and pressure of the inlet stream from the well, as shown in Figure 12.4. Gas separated in this unit is sent to acid gas recovery; the condensate or the oil recovered is usually sent to a refinery for processing, while water is disposed, or treated as wastewater.

Figure 12.2. A generalized natural gas processing flow diagram [7].

Figure 12.3. Condensate and water removal [6].

Acid gases (H₂S and CO₂) are separated usually by absorption in an amine solution, as discussed for H₂S recovery in a petroleum refinery in Lesson 10. The recovered H₂S is sent to a combined Claus-SCOT (Tail Gas Treating) unit to be converted to elemental sulfur, as was also discussed in Lesson 10. After removing the acid gases, the natural gas stream is sent to a dehydration unit to remove water typically by absorption in a glycol unit, followed by mercury removal (by adsorption on activated carbons or other sorbents), and nitrogen rejection either cryogenically, or by adsorption, or absorption depending on the nitrogen concentration. The last step in the processing sequence is the Natural Gas Liquids (NGL) extraction, fractionation, and treatment, as described in Figure 12.4.

Figure 12.4: Separation and Fractionation of Natural Gas Liquids [6]

Natural gas liquids (NGLs) have a higher value as separate products. 

Two basic steps: 1) Extraction, 2) Fractionation

1. NGL Extraction
   Absorption Method
   • Similar to using absorption for dehydration, using a different absorbing oil for hydrocarbons. 
   Cryogenic Expansion Process
   • Dropping the temperature of the gas stream to around -120°F by expansion and external refrigeration
2. Natural Gas Liquid Fractionation - works like Light Ends Unit
   • Deethanizer - separates ethane from the NGL stream
   • Depropanizer - separates propane.
   • Debutanizer - boils off the butanes
   • Butane Splitter or Deisobutanizer - separates iso and n-butanes.

NGL extraction can be carried out by absorption in oil that selectively absorbs hydrocarbons heavier than methane, or by a cryogenic expansion and external refrigeration to condense NGL.

Following the NGL extraction, the treated natural gas stream that is, now, mostly methane, or a gas compliant with the natural gas specifications is sent to the pipeline for transmission to the point of use. The extracted NGL, on the other hand, is sent to a fractionation unit that operates like Light Ends Unit in a refinery, as discussed in Lesson 5, separating ethane, propane, butane, and naphtha (>C₅, natural gasoline). Note that the fractionation unit may also include a butane splitter or deisobutanizer to separate n-butane and iso-butane. You may remember from Lesson 8 that iso-butane is a feedstock to alkylation to produce high-octane gasoline when reacted with C₃ and C₄ olefins. NGL from highly sour gases may need additional treatment to remove mercaptans and other sulfur species before NGL leaves the processing plant.

Please take a few minutes to work through the questions below. They will help you study for the quiz this week.

Assignment Reminder

Review the US DOE web page on shale gas [7].

The material in the section on Shale Gas Basics is included in the coverage of the final exam.

Summary

Natural gas has gained prominence in the energy scene as a rising fossil fuel following the development of new drilling technology that set up a boom in shale gas production. As crude oil, natural gas contains wide-ranging impurities in addition to the main component, methane. Natural Gas Processing removes the contaminants in the raw gas and recovers some valuable byproducts, such as natural gas liquids. A number of separation and recovery processes used in a petroleum refinery can also be used for natural gas processing.   

Learning Outcomes

By the end of this lesson, you should be able to:

• appraise different natural gas reserves (conventional, tight, and shale) and assess the contribution of natural gas to energy supply;
• illustrate and evaluate the different stages of natural gas processing, including condensate removal, acid gas removal, water removal, fractionation of natural gas liquids.

Reminder - Complete all Lesson 12 tasks!

Questions?

If you have any questions, please post them to our Help Discussion (not email), located in Canvas. I will check that discussion forum daily to respond. While you are there, feel free to post your own responses if you, too, are able to help out a classmate.