Sour natural gas contains H2S and CO2, which have to be removed to meet specifications for sales gas. The removal process is done at the gas plants. The resulting acid gas streams (primarily H2S and CO2) are processed in sulfur recovery units or sulfur plants, which convert the H2S to elemental sulfur instead of burning it and flaring the produced SO2. The sulfur recovery units (SRU) are not a major revenue generator (due to the low sulfur price) and are primarily installed for environmental reasons.
The total world sulfur production is anticipated to increase in the future, causing a downward pressure on sulfur prices. With low sulfur prices and large stockpiles of sulfur, it is worthwhile to consider alternate processes for handling sulfur. One such alternate is the injection of acid gas into a subsurface reservoir, much like injecting the produced water during crude oil production.
Acid gas injection has several advantages and disadvantages. Advantages include low operating expenses, reduced sulfur emissions into the atmosphere, CO2 sequestration and the ability to handle wide range of acid gas compositions. Disadvantages include finding a geologically isolated disposal or storage reservoir, increased safety risks, subsurface migration and lost revenues from sulfur. Any one of these could be the controlling factor, and a detailed economic and environmental analysis is needed to decide whether an acid gas injection (AGI) scheme should be installed in lieu of sulfur recovery plant. The existing AGI schemes are primarily installed in Canada (a few in the USA) due to low sulfur prices, increased environmental regulations making it mandatory for operators to control sulfur emissions into the atmosphere, and availability of suitable depleted oil and gas reservoirs.
This paper presents a roadmap for acid gas injection schemes including the technical and economic factors that need to be addressed in deciding whether AGI is feasible. An example feasibility study for a Saudi Arabian field is included as a case study.
Raw natural gas, both associated and non-associated, generally contains carbon dioxide and sometimes hydrogen sulfide. These two components have to be removed from natural gas by a "sweetening" process involving a regenerative solvent. This removal process is necessary for the natural gas to meet pipeline and sales gas specifications. The separated gas stream, often referred as acid gases, usually contains H2S, CO2, water and minor amounts of hydrocarbon components. The amounts of these components in the acid gas stream, particularly H2S and CO2, vary significantly depending on their relative amounts in the raw gas stream and the selected gas treating process.
The acid gases are usually processed in a sulfur recovery unit, typically a modified Claus Plant, to convert H2S to elemental sulfur. The efficiency of the Claus Plant, and hence the conversion of H2S to sulfur, depends on the composition of acid gases. Conversion efficiency decreases as the concentration of CO2 increases relative to H2S in the feed stream. At very high CO2/H2S ratios in the acid gases, a Super Claus unit or a tail gas unit must be employed to boost the conversion efficiencies of the Claus Plant and meet sulfur dioxide (SO2) environmental emission regulations. The addition of a Super Claus or a tail gas unit (TGU) increases the overall cost of sulfur production. The selection of an appropriate sulfur recovery technology also depends on the sulfur production capacity and environmental regulations.
An alternate to recovering the sulfur is to compress the acid gases and inject them into a suitable underground reservoir. This is akin to produced water disposal, with the added advantage of reducing the emission of greenhouse and acid gases. Stricter environmental regulations also favor the reinjection option, as the tail gas is burnt/flared and emitted to the atmosphere in the form of sulfur dioxide (SO2) and CO2.
During the past decade, a number of operators, primarily in Canada, have developed technologies for disposing acid gases by injecting them into subsurface reservoirs. In many cases, the injection option has been economically, operationally and environmentally superior to a sulfur recovery unit. This has been primarily due to the availability of shallower reservoirs for injection, and low acid gas flow rates that make a SRU a more expensive option.