As environmental pressures increase, and interest grows in developing evermore-sour offshore oil fields, FPSO operators will be required to recover sulfur from associated gas to control hydrogen sulfide (H2S) and/or sulfur dioxide (SO2) emissions to the air. The first liquid redox process unit for removing sulfur from associated gas to be used to fuel FPSO topsides is under design, and smaller scavenger systems are also available for use on remote floating platforms.
This paper details the economics of options for recovering sulfur from associated gas. The challenges of modifying onshore process designs of these technologies for use in floating offshore facilities is also discussed.
In onshore applications, regenerable sulfur recovery processes offer order-of-magnitude lower operating costs than scavenger systems. Onshore, these operating cost savings can justify the higher capital costs associated with regenerable technology when dealing with sulfur loads as low as 200 kilograms per day; and liquid redox processes have additional advantages over scavenger systems when evaluated for use in remote floating facilities. Operability in limited space, and greatly reduced logistical demands, decrease the sulfur production breakpoint whereupon regenerable systems show advantages over non-regenerable systems.
As pressure increases for FPSO designers and operators to provide solutions to sulfur emission problems, the correct choice of processing options will minimize the cost and the operating burdens associated with these new facilities.
Environmental pressures long felt by onshore operators to eliminate sulfur emissions to the atmosphere are finding their way into the world of offshore oil and gas producers. New environmental regulations focus on the reduction of sulfur emissions to the air. These sulfur emissions come typically in the form of sulfur dioxide (SO2), created by burning the sulfur compounds naturally existing in oil and gas deposits. Air emissions of SO2 are a primary cause of acid rain, which has been a high profile pollution concern for decades.
Dealing with hydrogen sulfide (H2S) in fuel gas streams was a concern long before acid rain caught the world's attention. Hydrogen sulfide is an extremely toxic, corrosive and odorous gas, raising safety and material of construction issues in its unaltered form. High levels of H2S in many raw natural gas streams have long required processing to reduce the contained acid gases before transport and distribution of the fuel to market. (Watson and Jones, 2008) The simplest method of destroying the hydrogen sulfide removed from fuel streams is combustion to form SO2. Of course, any H2S remaining in the fuel will be oxidized to sulfur dioxide as the fuel is utilized. Although processes exist to remove sulfur dioxide from flue gases, the economical choice for preventing sulfur emissions to the air has been to remove the H2S prior to flaring or using the fuel, thus avoiding sulfur combustion and the formation and release of SO2.
Petroleum refineries have undergone extensive modification over the last twenty years to both reduce sulfur emissions to the air from within refinery battery limits, as well as to produce low sulfur transportation fuels. Low sulfur gasoline and diesel has become the norm in much of the world, and refinery focus is shifting to reducing sulfur in jet fuel and bunker C. Most of the sulfur removed in refineries is first converted to H2S, which is then converted into non-gaseous forms of sulfur.
