Growing Frequency Of Hydrogen Sulfide Creates Operational Issues

(Tech Connections Column, February 2006, American Oil and Gas Reporter)

Reservoir souring is a growing problem worldwide. Experiences shared during a PTTC workshop from the mature San Juan Basin, where the problem is increasing, are typical.

Beyond obvious safety aspects, hydrogen sulfide is corrosive; and if concentrations are high enough, gas may need treating. In the San Juan Basin, the Bureau of Land Management applies Onshore Order No. 6, which addresses requirements for conducting operations in H₂S environments. Potentially hazardous volumes are defined as 100 parts per million any place the public could reasonably be expected to frequent, or 500 ppm at roads.

Both BLM and operators recognized the need to update a 1998 study. Last year BLM solicited data directly from operators and through the Basin Working Committee. The BLM hoped to go beyond mere mapping of where H₂S was present to find answers to questions such as:

• What producing formations contain H₂S?

• What is the range of H₂S concentrations?

• What controls occurrence?

Data from 376 wells (11 operators) were available. Although they don’t provide the total picture, there are evident trends. Hydrogen sulfide is not limited to specific producing formations, although there are isolated areas where there appears to be some degree of formation specificity. There is a general scattering of wells in the center of the basin with a trend toward the northwest. Importantly, if H₂S is a problem in a local area, it is generally a problem for all operators in that area. Maps presented by the BLM (http://octane.nmt.edu/swpttc/proceedings/H2S_05/H2SFarmington.asp) illustrate areas of higher H₂S concentration. BLM also made the data spreadsheet available.

Considering the toxic nature of H₂S, it is good to remember the gas is invisible and heavier than air. H₂S attacks life in three ways:

• It blocks oxygen from bonding to red blood cells, causing oxygen deprivation;

• It seeks to shut down one’s respiratory system; and

• It deadens the sense of smell.

No one should trust his nose to detect H₂S. The Occupational Safety and Health Administration sets the permissible exposure limit (PEL) for H₂S at 10 ppm. The PEL is defined as the maximum concentration one can be exposed to in an eight-hour period, 40-hour week, without respiratory protection. Other concentrations to remember are the short-term exposure limit (STEL) based on a 15-minute exposure period (15 ppm) and an exposure immediately dangerous to life and health (IDLH) of 100 ppm. When concentrations reach 1,000 ppm a person would be knocked out immediately and death would occur in a matter of minutes.

Anyone who could potentially be exposed to H₂S should learn to use and correctly maintain personal and fixed monitors, and should always rely on them rather than smell or “instinct.” Personal protective equipment must be available, emergency response plans laid out, and people trained. An important guiding concept is to never, ever, rescue unless it can be done the right way.

There are fire and explosion hazards that must be recognized beyond the health effects. H₂S is flammable at concentrations between 4.3 and 46.0 percent, igniting at temperatures above 500 degrees F. When H₂S is burned, a main combustion product, sulfur dioxide, has its own health hazards with PEL and IDLH concentrations of 2 and 20 ppm, respectively. Iron sulfide, a corrosion byproduct often removed from wells/equipment, is another fire danger since it can catch fire when exposed to air.

Then there are the safety and cost issues from corrosion-caused leaks. Corrosion is both general and very localized (pits). Pitting rates are typically 10-50 times greater than general corrosion rates. There are equations to estimate uninhibited corrosion rate, so one doesn’t have to wait to see whether treatment is advised. H₂S can also cause corrosion cracking, the remedies for which include using less susceptible metals, lower stress, and special inhibitors.

In the San Juan Basin, H₂S usually results from activity by sulfate-reducing bacteria (SRB) introduced into well bores during past drilling or workover operations. The conventional approach for controlling bacteria is to apply biocides, typically by batch treatment (large enough concentration to achieve a kill). Retreatment frequency typically is determined by experience and monitoring SRB population growth through periodic cultures. Since bacteria can develop a resistance to a given biocide, it is good practice to periodically alternate the type of biocide. There are handling concerns with biocides.

A bio-competitive exclusion approach developed by the Lata Group (www.latagroup.com) is an alternative to biocides. The products used are relatively low cost and nonhazardous. When treated with the patented nitrate-based formula, bio-competitive exclusion stimulates beneficial indigenous nitrate-reducing bacteria (NRB). The product can be tailored to individual applications. The stimulated NRB then out-compete SRB, effectively inhibiting SRB growth and subsequent H₂S generation. Microbial byproducts also cause beneficial improved oil recovery effects. Several case studies ranging from individual well treatments to large surface systems were shared.