Study examines sulfate-reducing bacteria activity

John E. McElhiney, John A.Hardy
Marathon Oil Co.
Littleton, Colo.
Tony Y. Rizk, James F.D. Stott, Robert D. Eden
Capcis, Umist
Manchester, U.K.

Low-sulfate seawater injection can reduce the potential of an oil reservoir turning sour because of sulfate-reducing bacteria.

Sulfate-reducing bacteria (SRB) convert sulfate ions in seawater used in waterflooding into sulfide with the concomitant oxidation of a carbon source. In the case of seawater-flooded oil reservoirs, these carbon sources are water soluble organic acids or their anions.¹ The most important organic acid anion is acetate. It is naturally present in most North Sea formation waters at concentrations greater than 100 mg/kg (ppmwt). The metabolic reaction carried out by the SRB is as follows:

CH₃ COO- + SO₄² - S^2- + H₂O + CO₂ + HCO₃

The sulfide thus formed exists in equilibrium with undissociated hydrogen sulfide according to the following equilibrium, which is pH dependent:

H₂S <-> H+ + HS- <-> 2H⁺ + S²

Note that the term "hydrogen sulfide" is used to include the sum total of H₂S, HS-, and S²- .

A recent study at Capcis (Corrosion and Protection Centre Industrial Services at the University of Manchester Institute of Science & Technology) investigated the efficiency of SRB under various conditions of sulfate limitation. This study was conducted in a flowing bioreactor at 2,000 psia with different temperature zones (mesophilic 35° C. and thermophilic 60-80° C.).

The study mixed microfloral populations derived from real North Sea-produced fluids, and included an active population of marine methanogenic bacteria present to provide competition for the available carbon sources. In general, results showed that SRB continue to convert sulfate to sulfide in stoichiometric quantities without regard to absolute concentrations. For example, SRB function just as well at low concentrations of sulfate as at high concentrations.

However, at low concentrations of sulfate, 50 mg/kg (ppmwt) and less, the SRB will yield only low concentrations of hydrogen sulfide. At stoichiometric conversion, seawater containing 50 mg/kg (ppmwt) of sulfate will yield a maximum of 18 mg of hydrogen sulfide per liter of seawater injected. Additionally, hydrogen sulfide will partition between gas, oil, and water according to its equilibrium relationship at reservoir conditions.

Assuming no scavenging by the reservoir petrofabric, all hydrogen sulfide produced by the SRB will pass through the reservoir and be produced at the wellhead. Fig. 1 [23507 bytes] illustrates a real production profile of a North Sea oil well producing 20,000 b/d. This reservoir is being waterflooded with seawater, and water breakthrough occurs at 750 days.

Fluid production continues at 20,000 b/d with declining oil production. It is assumed that the seawater has been desulfated, leaving about 2 wt % of the original sulfate ion concentration in the seawater, or about 54 mg/kg (ppmwt). In this case, a three-phase mixture of oil, gas, and water is present, and the pressure in this system is below the bubble point.

At a 6.7 pH, the dissociation of hydrogen sulfide into HS- and H+ is about 50%. This condition was used in calculating the equilibrium partitioning between the three phases.

Fig. 1 also shows the results of the bioreactor tests and the calculated partitioning of the hydrogen sulfide between oil, gas, and water phases. For comparison, a production profile of produced hydrogen sulfide resulting from SRB conversion of 270 mg/kg (ppmwt) sulfate, representing injection of desulfated seawater containing ~10% of naturally occurring sulfate, is also shown.

Note that actual hydrogen sulfide production for nondesulfated seawater would typically be much greater than the concentration shown here by an amount limited by the availability of usable carbon source in the particular formation water.

The susceptibility of ferrous metallic materials to the most severe types of sulfide damage is highly dependent on factors such as the chemical composition of steel and the levels of applied and residual stress, in addition to hydrogen sulfide concentration in the gas phase. Thus, no threshold of hydrogen sulfide in the gas phase is universally accepted as an unacceptable value for any given set of conditions. But the lower the hydrogen sulfide concentration the less risk of such damage.

Nevertheless, the relevant industry standard sets out "risk regions" of hydrogen sulfide concentrations with respect to sulfide stress cracking for the more susceptible materials.

In a substantial number of instances, depending upon the total pressure and other reservoir conditions, the introduction of desulfated seawater as the secondary recovery medium predicts the removal of a system from this sulfide stress cracking "risk zone" for sour gas and sour multiphase systems such that:

Nonsour grade materials can be used.
Nonsour weld procedures can be used.
Chemical corrosion inhibition can be more efficient when H₂S is low.
A relaxation of the crack-detection monitoring can be made.
Overall safety requirements may be made less stringent.
Test requirements to ensure sour service materials have been supplied can be lessened.

These benefits can save costs that are difficult to quantify because each project tends to be different. However, sour service-grade material is reported as being 15% or more expensive than nonsour-service carbon steel.

When the savings in welding and testing are added, the overall advantages become significant. For further discussion of this risk zone, refer to NACE Standard MR0175-93_.2

For reservoirs containing indigenous hydrogen sulfide at discovery and for reservoirs in which low concentrations of aqueous organic carbon sources will limit hydrogen sulfide production, even in the presence of high sulfate concentrations, these findings are of little consequence.

However, for a "sweet" reservoir containing no hydrogen sulfide at discovery, the idea that injected seawater loaded with sulfate might fuel biogenic hydrogen sulfide production by SRB and turn it sour is quite troubling. In such a case, initially no need for providing material designs for other than sweet production seems to exist; however, finding copious amounts of hydrogen sulfide later could be devastating indeed.

Therefore, installing nanofiltration at the onset of waterflooding could prove beneficial. No doubt, future work will refine the conditions under which souring might be expected, and economic guidelines will evolve under which nanofiltration should be considered.

References

1. "Oilfield Reservoir Souring," U.K. Health and Safety Executive Offshore Technology Report OTH 92 385, HSE Books, Sudbury, Suffolk, U.K., 1993.

2. "Sulfide Stress Corrosion Cracking Resistant Metallic Material for Oil Field Equipment," Material Requirement MR0175-93, National Association of Corrosion Engineers, Houston, 1993.