Acetate, propionate, and butyrate, collectively referred to as volatile fatty acids (VFA), are considered among the most important electron donors for sulfate-reducing bacteria (SRB) and heterotrophic nitrate-reducing bacteria (hNRB) in oil fields. Samples obtained from a field in the Neuquén Basin, western Argentina, had significant activity of mesophilic SRB, hNRB, and nitrate-reducing, sulfide-oxidizing bacteria (NR-SOB). In microcosms, containing VFA (3 mM each) and excess sulfate, SRB first used propionate and butyrate for the production of acetate, which reached concentrations of up to 12 mM prior to being used as an electron donor for sulfate reduction. In contrast, hNRB used all three organic acids with similar kinetics, while reducing nitrate to nitrite and nitrogen. Transient inhibition of VFA-utilizing SRB was observed with 0.5 mM nitrite and permanent inhibition with concentrations of 1 mM or more. The addition of nitrate to medium flowing into an upflow, packed-bed bioreactor with an established VFA-oxidizing SRB consortium led to a spike of nitrite up to 3 mM. The nitrite-mediated inhibition of SRB led, in turn, to the transient accumulation of up to 13 mM of acetate. The complete utilization of nitrate and the incomplete utilization of VFA, especially propionate, and sulfate indicated that SRB remained partially inhibited. Hence, in addition to lower sulfide concentrations, an increase in the concentration of acetate in the presence of sulfate in waters produced from an oil field subjected to nitrate injection may indicate whether the treatment is successful. The microbial community composition in the bioreactor, as determined by culturing and culture-independent techniques, indicated shifts with an increasing fraction of nitrate. With VFA and sulfate, the SRB genera Desulfobotulus, Desulfotignum, and Desulfobacter as well as the sulfur-reducing Desulfuromonas and the NR-SOB Arcobacter were detected. With VFA and nitrate, Pseudomonas spp. were present. hNRB/NR-SOB from the genus Sulfurospirillum were found under all conditions.
Produced waters from the Barrancas and Chihuido de la Salina (CHLS) fields in Argentina had higher concentrations of sulfate than were found in the injection waters, suggesting that the formation waters in these reservoirs had a high sulfate concentration and that sulfate-reducing bacteria were inactive downhole. Incubation of produced waters with produced oil gave rapid reduction of sulfate to sulfide (souring) at 37 °C, some at 60 °C, but none at 80 °C. Alkylbenzenes and alkanes served as electron donor, especially in incubations with CHLS oil. Dilution with water to decrease the ionic strength or addition of inorganic phosphate did not increase souring at 37 or 60 °C. These results indicate that souring in these reservoirs is limited by the reservoir temperature (80 °C for the Barrancas and 65-70 °C for the CHLS field) and that souring may accelerate in surface facilities where the oil-water mixture cools. As a result, significant sulfide concentrations are present in these surface facilities. The activity and presence of chemolithotrophic Gammaproteobacteria of the genus Thiomicrospira, which represented 85% of the microbial community in a water plant in the Barrancas field, indicated reoxidation of sulfide and sulfur to sulfate. The presence of these bacteria offers potential for souring control by microbial oxidation in aboveground facilities, provided that formation of corrosive sulfur can be avoided.
A case study is presented which addressed the origin of Hydrogen Sulphide (H2S) in produced gas associated with the oil in Las Heras - Cerro Grande oilfield in Gulf of San Jorge Basin, Argentina. The reservoir was initially sweet. However, after waterflooding an increase in H2S concentration was detected in several wells. The H2S amount varies across the field with the highest values found in wells where water injection was initiated and the wells produce with a high water cut. Knowledge of H2S origin contributes to effective control and therefore, to reduce environmental risk, minimize emissions, improve quality of produced hydrocarbons and reduce corrosion rate. The main stages followed include, H2S measurements, H2S source identification and mitigation treatments. The possible mechanisms of reservoir souring have been analyzed by sulphur isotope ratio analysis. These results have been integrated with geological factors and other parameters related to waterflooding. This case is unusual because of water composition. The formation and injection waters have low salinity and are not rich in sulphate ion concentration, very different from sea water composition. Nutrients such as fatty acids are present in both formation and injection waters. The increase in H2S production is attributed to sulphate reducing bacteria (SRB) living in the reservoir. The proposed model to explain H2S origin suggests a closed system with reactive-limited reaction where H2S production is controlled by low sulphate concentration present in waters. A strong correlation was demonstrated between produced H2S, injection water parameters and subsequent souring. A decrease in sulphate concentration present in water production appears to correspond with an increase in H2S concentration. At present, the produced gas is being treated with scavengers. A nitrate injection project is being analyzed to control reservoir souring. The development of a biofilter to oxidize H2S in plant treatment is in laboratory phase. Introduction Las Heras -Cerro Grande oilfield belongs to the main area called Las Heras field, in Gulf of San Jorge Basin, Santa Cruz Province -Argentina (Figure 1). The zone of the field to study covers an area of around 75 Km2 with 250 wells. The field is characterized by its complex structure which is crossed by two main faults NNO-SSE with NE and SO dips that create a central fossa. It is limited by the two faults. The hydrocarbon accumulations are in sandstone, lithic sandstone and tobaceous sandstone of Bajo Barreal Formation - Chubut Group, in Middle / Upper Cretaceous Age, being the origin of the sediments aluvional, ephemeral fluvial and brief lacustrine (Figure 2).Most of the reservoirs of the block comprise the lower section of Bajo Barreal Formation, not reaching the Castillo Formation. On the basis of the paleographic interpretations the coexistence of three groups of geometries at different depths was determined: canalized layers, layers poorly canalized and lobulate layers. The geometry of the channels agrees with the direction of the main faults. Three waterflooding projects were implemented successively to increase oil recovery. Water injection began in 1997, in a pilot well with, an average injection rate of 140 m3/day that was obtained from a water producer. After approximately 6 months, the conversion of remaining injection wells of the first project was carried out and it was followed with wells of two remaining projects, arriving at the total injection in the middle of 2000 with approximately 6000 m3/day distributed among 59 injection wells, with 175 associated producing wells (Figure 3). The initial reservoir conditions prior to waterflooding were 42°C and 85 bar pressure. Produced fluids are separated in surface facilities and the produced water is reinjected into the reservoir after being mixed with produced water from other areas and with a small percentage of Rio Senguer water in Las Heras 3 Plant. The injection water is pumped from LH3 Plant to injection wells.
Nitrate can control souring in fields with high bottom hole temperature (BHT) and where sulfide is produced in the near-injection-wellbore-region (NIWR). The objective of the treatment is to lower the sulfide concentration in produced water and oil, reducing corrosion risk in producing wells and above-ground infrastructure. Achieving this objective can be problematic for fields with low BHT or for fields in which the reservoir contributes sulfate to the produced water, as is demonstrated by analysing three PWRI case studies. Nitrate was found to effectively oxidize sulfide in produced waters, even when excess oil organics were present. An alternative strategy that should be considered is, therefore, to inject nitrate in the produced waters in a dose corresponding to the sulfide concentration.
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