Author: Da Huo
The abundance of global reserves, the growing scope of end-uses, and the recent advances in hydraulic fracturing technology have all been fueling the rise of natural gas. Over the last 40 years, global annual consumption of natural gas has more than quadrupled, rising from 23 trillion cubic feet (TCF) in 1965 to 113 TCF in 2011. The forecasted growth rate – approximately 1.5% per year – is roughly double that of crude oil, and consumption is expected to reach 150 TCF by 2030. It is clear that the world energy balance is tilting towards natural gas. Nevertheless, just as there are differing grades of crude oil, so are there differences in the quality of natural gas resources. One primary characteristic is the difference between sweet and sour gas.
Sour gas refers to natural gas that contains significant amounts of acidic gases such as hydrogen sulfide and carbon dioxide (CO2). It is preferable instead to have sweet gas because it does not contain such amounts of these contaminants. According to the International Energy Agency, about 43% of the world’s natural gas reserves (2,580 TCF), excluding North America, are sour. The Middle East, which has the world’s most sour gas reserves, contains 60% sour gas. In Russia, the world’s largest natural gas producer, 34% of total reserves are sour gas.
Sour gas is problematic for a variety of reasons. Besides its toxicity and flammability, hydrogen sulfide in the gas stream also damages drilling equipment, and both hydrogen sulfide and CO2 corrode piping during gas production and transportation. Removing CO2 is also important because high concentrations decrease the amount of energy yielded when burning the gas. The process for liquefying natural gas in order to be transported requires extremely low concentrations of CO2 – less than 50 parts per million (ppm). This is because when the gas is cooled for liquefaction (down to -160 degrees Celsius), CO2 will freeze, causing blockage of flow lines and other operational problems.
Unfortunately, but not surprisingly, the processes for removing these contaminants from the gas stream are both costly and energy intensive. The removal of hydrogen sulfide is usually performed by an amine gas treatment process. The removed hydrogen sulfide is typically converted to sulfur or sulfuric acid, which can be used in other industrial processes. The most common separation technologies for CO2 currently include the use of solvent systems, absorption towers, membrane separators, and cryogenic processes. However, all of these processes are quite expensive.
Over 30 large gas fields worldwide have been identified to contain more than 5 million metric tons (MMT) of CO2. This CO2 must be separated from the natural gas due to transmission and end-usage requirements. The world’s largest gas field, South Pars in Iran, holds 360 TCF of gas reserves, but is also estimated to contain 400 MMT of CO2. Another one of the largest gas fields in the world, Gorgon in Australia, has over 300 MMT of CO2 in reserve. This means 14% of Gorgon’s gas reserves are CO2, which is significantly above tolerable limits for transportation, so it will be extremely important to remove the CO2 from the raw gas stream during production.
The trend toward increasingly sour gas implies that more and more reservoir CO2 will be liberated into the atmosphere unless geological storage becomes widely adopted. The Intergovernmental Panel on Climate Change estimates that about 50 MMT of reservoir CO2 is liberated into the atmosphere by natural gas production every year. Furthermore, this is based on a conservative estimate of CO2 concentration and in reality this number may be as high as 100 MMT. Projecting this out to 2030, the amount of reservoir CO2 emissions associated with gas production may reach 150 MMT per year.
Although these emissions are dwarfed by CO2 emissions attributed to other industries (e.g., power generation), they still represent a significant risk to natural gas development projects, depending on how regulation evolves. Carbon capture and sequestration is technically feasible for the natural gas industry, and should be considered a complementary technology to sour gas exploration and development.
Da Huo is a Ph.D. candidate at Stanford University in Energy Resources Engineering. He works in the lab of Professor Sally Benson on carbon sequestration and fluid transport in fractured rocks.