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Consider GTL as an economic alternative for stranded natural gas and ethane

10.01.2013  |  Cantrell, J. ,  Bryan Research & Engineering, Inc., Bryan, TexasBullin, J. A.,  Bryan Research & Engineering, Inc., Bryan, TexasMcIntyre, G.,  Bryan Research & Engineering, Inc., Bryan, TexasButts, C.,  BCCK Engineering, Inc., Midland, TexasCheatham, B.,  BCCK Engineering, Inc., Midland, Texas

The market price for ethane is well below historical values, and projections indicate that this condition will persist. What are the options to find economical applications for gas and related hydrocarbons?

Keywords: [ethane] [ethylene] [natural gas] [pipelines]

The abundance of natural gas in widespread US locations has resulted in many resources being classified as remote or stranded. It is creating the need for economical options to move these resources to market. In many cases, the gas is ethane-rich, and there is a need for new ways to monetize a low-value ethane product. The present market price for ethane is well below historical values, and projections indicate that this market condition will persist. What are the options to find economical applications for natural gas and related hydrocarbons?

Abundant natural gas supplies

US natural gas production has increased substantially over the past 10 years. Fig. 1 shows the level of increased natural gas production for US and individual states. The greatest sources for new natural gas supplies have been through the exploitation of shale formations. These increases have been seen not only in traditional gas production areas such as Texas and Louisiana, but also in nontraditional places such as Pennsylvania and Arkansas.

  Fig. 1.  US natural gas production.1

In many areas, large quantities of natural gas are being flared due to the lack of pipeline availability and infrastructure. For example, as of June 2012, in North Dakota, over 200 MMscfd of natural was flared. This represents about one third of the total gas production in the state.2 Some of these wells will be connected to a pipeline within a year, while others will continue to be flared on a longer-term basis. Along with the large increase in natural gas production in the US (Fig. 1), there has been an even larger increase in natural gas liquids (NGLs), of which ethane is the greatest volume, as shown in Fig. 2.3 

  Fig. 2.  US ethane production.3

From 1984 to 2008, ethane production gradually rose by approximately 40%, from 500,000 bpd (500 Mbpd) to 700 Mbpd. From 2008 to 2012, ethane production grew almost another 40%, from 700 Mbpd to nearly 1 million bpd. These production numbers do not include the more than 50 Mbpd that was either flared or rejected into the residue gas stream. In total, the US has increased available ethane more in the last four years than in the previous 24 years collectively.

Value of ethane

By far, the dominant use of ethane is as a feedstock to US Gulf Coast steam crackers for ethylene production.4 However, ethylene is not a finished product; it is not easily transported outside of the limited ethylene pipeline networks along the Gulf Coast. The only other significant use for ethane is fuel value, which sets the “floor” price.4

Due to ethane’s limited value in total hydrocarbon production, shale plays are frequently developed without significant thought to disposition of the ethane as a stand-alone product.2 For example, in a typical Bakken gas with 12.2 gpm, the ethane content can represent about 44% of the total NGLs by volume, but only 14% of the value. If the gas is produced in association with oil from a well with a gas-to-oil ratio of 1.1 MMscf/bbl, the ethane represents a meager 1% of the value of the hydrocarbons, despite being 10% of the total hydrocarbon liquids produced.

The prices for Henry Hub natural gas, Mont Belvieu purity ethane, and West Texas Intermediate (WTI) crude, all in terms of $/MMBtu, are shown in Fig. 3.5–7 Historically, ethane has tracked near WTI, based on respective heating values. This was true until 2008, when ethane’s value decreased relative to crude oil. The primary reason for this drop was that newly available ethane began flowing, much of it from Texas shale. From Fig. 3, the market separation in terms of $/MM-Btu between gas and ethane prices and crude prices is the highest over the last seven years at least. Furthermore, this trend is expected to continue for many years.

  Fig. 3.  Historic oil, residue, gas and ethane prices.5–7

Fig. 4 shows the ethane production for the US and the Texas Inland refinery district, which includes the Eagle Ford, Barnett and Permian basins.8 From this figure, the estimated ethane production for the Appalachia 1 and Minnesota, Wisconsin, North Dakota, South Dakota (Midwest) refinery districts, which include the Marcellus/Utica and Bakken, respectively, is presented. While the Marcellus/Utica and Bakken districts had no significant ethane production reported, the figure shows the estimated ethane amounts produced from the fields and sold with the residue gas, based on other NGLs produced.

  Fig. 4.  US ethane production.8

From 2008 to 2011, ethane maintained a significant cost premium over natural gas, despite the rising supply, as shown in Fig. 3. With the increasing price separation between oil and ethane, ethylene crackers that used heavier, oil price-dependent feeds such as naphtha, butane and propane began shifting their feedstock to cheaper ethane.4, 9

Limits on ethane price/demand growth

Several new ethylene plants and expansions of existing facilities have been announced. The new capacity will consume some of the expected ethane production.4 To integrate these plants with existing infrastructure for feedstock delivery and product off-take, they are almost exclusively built on the US Gulf Coast.4 This proximity to other ethylene producers requires world-class economies of scale to compete. As such, these olefin plants represent very large ethane commitments, typically on the order of 95 Mbpd (149 MMscfd) of ethane for the service life of the plant. They also involve very large capital commitments, in the range of $1.7 billion (B) to $3 B depending on the sophistication and product slate.10, 11 Because recent shale resources are located far from the Gulf Coast, extensive pipelines are required to bring the ethane to the olefin crackers. The risks of constructing new ethylene capacity, including feedstock, transportation, competition and capital are sizeable, on top of the normal risk of price and demand for the final product.

Transporting ethane from new production areas, such as the Bakken and Marcellus fields, is not a trivial matter. Even if a pipeline exists and capacity is available, transportation costs impact ethane value to the producer significantly. The estimated transportation fees associated with moving ethane from some of the major shale basins to Mont Belvieu are shown in Table 1. In most instances, a purity ethane pipeline was not available, so pricing for a Y-grade product is used in this table.


The opportunity

The problem of residue gas and ethane oversupply and, particularly, localized oversupply in stranded locations is finding a solution to convert moderate quantities (15 MMscfd to 50 MMscfd) of residue gas and ethane to a higher-value and more easily transported product. These small volumes are outside the reasonable scale of a “local” ethylene plant. In many cases, pipelines may be at capacity or not available at all. Furthermore, even if pipeline capacity is available, high transportation fees may result in very low prices for natural gas and ethane in the field. In addition, the present trend of very large differences in gas and ethane prices relative to crude prices is expected to continue.

New process

To cover this engineering gap, a new technology has developed to convert natural gas and light hydrocarbons into a high-value, easily transportable gasoline product, thus substantially increasing the value of the end product.* The small plant size allows installing units at the production sites. In addition, a pipeline is not necessary, as the product can be easily transported by truck or rail.

The innovative process is an integrated conversion process to transform light hydrocarbons into a gasoline product, as shown in Fig. 5. The cracking reactor, or thermal cracker, operates by combusting fuel gas with oxygen to generate a very high-temperature flame. The feed hydrocarbon is preheated in a heat exchanger and then injected into the stream of combustion products to raise the temperature of the feed to the cracking temperature. The cracking of the feed takes place almost instantly. The yield to ethylene and acetylene ranges between 40%–80%, depending on feed composition. The reaction is water quenched to inhibit byproduct reactions that generate carbon monoxide and coke. Due to the nature of thermal reactions, some coke is produced. At these conditions, coking is typically 2%–3% of the inlet carbon. The largest size cracking reactor available is suitable for approximately 5 MMscfd of natural gas feed. For a commercial plant, the appropriate number of thermal reactors would be operated in parallel.

  Fig. 5.  Process flow diagram.

The cracked gas is further cooled by cross-exchange to recover heat and sent to the spray tower. Here, the cracked gas is washed with circulating water to further cool the gas, to condense the combustion water and to remove any coke particles. Once the cracked gas has been cleaned and cooled, it is compressed to approximately 150 psig with a multi-stage rotary screw compressor. The cracked gas then flows to the ethylene reactor where the acetylene is converted to ethylene.

The ethylene-rich product from the ethylene reactor is then preheated and fed to the product reactor to yield gasoline blendstock. The product blendstock consists primarily of C6–C8 with some lighter components down to C4 and some heavier components up to C11. The product contains about 30 wt% aromatics, usually toluene and xylene, as well as a small quantity of naphthenes (5 wt%–10 wt%). The remainder is a mixture of mostly branched paraffins. Olefins are typically less than 3 wt%. The gravity falls in the range of 50°API–60°API with a research octane number of 93–95. A refrigerated lean-oil absorption system is used to efficiently recover the product from the gas stream. A product stabilizer may be used to yield a gasoline blendstock to meet a particular Reid vapor pressure.

The residue gas can be used as fuel. To reduce the buildup of inerts within the recycle loop, an amine sweetening unit removes the carbon dioxide from the fuel gas returning to the burner. The remaining fuel is available for heating or power production.

Process economics

Based on current market conditions, two options for processing remote and stranded natural gas and ethane are presented. The first option reviewed is for 20 MMscfd of stranded or remote natural gas of approximately 1,250 Btu/scf gross heating value. For natural gas with limited possibilities for a pipeline or gas that is being flared, the producer should consider all available alternatives to create additional revenue. The new process produces approximately 1,710 bpd of liquid product with estimated annual gross revenue of $60 MM. As expected, the net revenue from the process is directly tied to the cost of the natural gas feedstock price. As shown in Table 2, the estimated payout for natural gas ranges from 2.8 years for $0/MMBtu gas to 4.3 years for $2/MMBtu gas. Gas feeds with heating values higher than 1,250 Btu/scf would produce larger amounts of liquids and would have corresponding shorter payout times.


The second option reviewed is for 20 MMscfd ethane feed of approximately 1,770 Btu/scf gross heating value. The new approach converts this potentially low-value gas stream into a saleable liquid product of approximately 3,660 bpd.* In economic terms, the $4/MMBtu or less feed stream is now worth $16/MMBtu as a liquid product based on present market prices, as shown in Fig. 3. In addition, with payout times less than three years, the process is very attractive in terms of capital investment and future profits. Upon payout, the process continues to yield substantial profits even if ethane prices increase. HP


This is a revised and upgraded version of a previous presentation from the 21st Gas Processors Association’s Annual Meeting, April 8–9, 2013, San Antonio, Texas.


* Synfuels International Inc. has developed a new process, Synfuels GTL; it is an integrated conversion process to transform light hydrocarbons into a gasoline product.


1 EIA, “Natural Gas Gross Withdrawals and Production,” US Energy Information Agency website, March 2013, http://www.eia.gov/dnav/ng/ng_prod_sum_a_EPG0_FGW_mmcf_m.htm.
2 Curtis, T. and T. Ware, “Restricting North Dakota gas-flaring would delay oil output, impose costs,” Oil & Gas Journal, Nov. 5, 2012, pp. 96–106.
3 EIA, “US Gas Plant Production of Ethane-Ethylene,” US Energy Information Agency website, March 2013, http://www.eia.gov/dnav/pet/hist/LeafHandler.ashx?n=pet&s=metfpus1&f=a.
4 Fasullo, P., “Outlook for US Ethane: Are Brighter Days Ahead,” HGPA Regional Meeting, Oct. 11, 2012.
5 EIA, “Spot Prices,” US Energy Information Agency website, March 2013,
6 EIA, Natural Gas Spot and Futures Prices (NYMEX), US Energy Information Agency website, March 2013, http://www.eia.gov/dnav/ng/ng_pri_fut_s1_m.htm.
7 Midstream Monitor, Natural Gas Liquids—Prices, Midstream Business website, March 2013, http://www.midstreambusiness.com/s/Prices-Natural-Gas-Liquids/.
8 EIA, Natural Gas Plant Field Production, US Energy Information Agency website, March 2013. http://www.eia.gov/dnav/pet/pet_pnp_gp_dc_r3a_mbblpd_a.htm.
9 Ordemann, B., 2013 Houston Gas Processors Association, HGPA Regional Meeting, Feb. 13, 2013.
10 Kaskey, J., “Dow Chemical Seeks US Permit for Biggest Ethylene Plant,” Bloomberg.com, Dec. 10, 2012, http://www.bloomberg.com/news/
11 Marais, J., “Sasol Studies $4.5 Billion Ethane Cracker in Louisiana,” Bloomberg.com, Nov. 30, 2012, http://www.bloomberg.com/news/2011-11-30/sasol-studies-ethane-cracker-plant-of-as-much-as-4-5-billion-in-lousiana.html.
12 FERC, US Federal Energy Regulatory Commission website, 2013, http://etariff.ferc.gov/TariffList.aspx. Joel Cantrell is a senior process engineer at Bryan Research & Engineering with more than 16 years of experience. Mr. Cantrell has been the lead development engineer on the Synfuels GTL project for more than 12 years. His experience includes pilot plants, biofuels and gas processing. Mr. Cantrell holds a BS degree in chemical engineering from Texas A&M University and a PhD in chemical engineering from Lehigh University.

The authors
Jerry Bullin is a graduate of the University of Houston with BS, M.S and PhD degrees in chemical engineering. He is a registered Professional Engineer in the state of Texas, and has worked for several years as a process engineer. In addition, Dr. Bullin was a professor in the Chemical Engineering Department at Texas A&M University for 25 years. At present, he is president of Bryan Research & Engineering, Inc., a firm that develops and markets process simulation software for the oil and gas, refining, and chemical industries.
Gavin McIntyre is manager of process applications and customer service at Bryan Research & Engineering, Inc. He has more than 19 years of experience in process simulation and the oil and gas industry. Mr. McIntyre holds a BS in chemical engineering from Texas A&M University.

R. Clark Butts, PE, is president and CEO of BCCK Engineering, Midland, Texas. In this role, he directs all company operations, investments and projects in addition to developing and implementing new technology. Mr. Butts holds patents related to nitrogen rejection and has over 35 years of experience in the fields of natural gas processing, treating and dehydration. His areas of expertise include nitrogen rejection, carbon dioxide removal and sequestration, helium extraction, oxygen removal and NGL recovery. He developed the Nitech technology, which is used on high nitrogen natural gas streams and is also being successfully used in a broad range of applications.

Bryon Cheatham currently serves as vice president—engineering at BCCK Engineering, Inc. in Midland, Texas. He joined BCCK as process engineer in 2000 after beginning his career in the refining industry where he has also worked in upstream production and operations. Mr. Cheatham holds a BS degree in chemical engineering from the University of Texas. 


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Abdou Said

it is extremely exceptioneal


The para above Table-2 needs corrections as follows, to match with the calculation in Table-2 :

.... the estimated payout for natural gas ranges from 3.5 years (NOT 2.8 years) for $0/MMBtu gas to 5.4 years (NOT 4.3 years) for $2/MMBtu gas.

Athol Love

As a structural engineer asked to provide pump bases and inlet/outlet pipe supports I can say that few engineers understand this inter-relationship between equipment and its supports properly.


There are a couple of fainciatsng points soon enough in the following paragraphs but I do not know if I see these people center to heart. There is some validity but I’m going to take hold opinion until I explore it further. Excellent write-up , thanks and that we want a lot more! Added to FeedBurner also

Mohamed EL ABD

reduction of gas flaring during oil and gas production and recover the associated gas to re-use this as fuel or sell it as feedstock.
please help

Mohammed Al-Saraf

Hi , Can you keep me on your mailing list for all GTL / GTC technology please ? Thank you.

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