Oilfield Reservoir Souring During Waterflooding: A Case Study with Low Sulphate Concentration in Formation and Injection Waters

Abstract

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.

Isotopic insights into microbial sulfur cycling in oil reservoirs

“…To date, field applications of isotopes to the souring problem have largely been restricted to using sulfur isotopes to differentiate between H 2 S formed from highly fractionating microbial sulfate reduction and H 2 S from abiotic thermochemical sulfate reduction (Aplin and Coleman, 1995 ; Poli et al, 2002 ; Cavallaro et al, 2005 ; Martins and Marques, 2006 ). This is based on the observation that thermochemical sulfate reduction often shows an apparent zero fractionation between reservoir minerals and H 2 S, thought to result from when the sulfate reduction itself is kinetically faster than the release of sulfate to solution (Machel et al, 1995 ).…”

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“…Capacity of methanogenic and sulfate-reducing prokaryotes, responsible for the terminal stages of petroleum biodegradation, to separate (fractionate) the stable isotopes of carbon (ratios of 13 С to 12 C, δ 13 C) and sulfur (ratios of 34 S to 32 S; δ 34 S), respectively is important for the understanding of their geochemical role. Preferential utilization of isotopically light compounds by these microorganisms and formation of methane and sulfide enriched with 12 C and 32 S, respectively were confirmed by numerous authors [24,27,38,49,[51][52][53]. Together with direct measurement of the rates of biogenic processes by radiotracer techniques, comprehensive information on the changes in pH, redox conditions, stable isotope composition, and concentration of individual compounds in formation water, gas and oil (sulfate, carbonate, sulfide, methane, and carbon dioxide, as well as emergence of the products of petroleum degradation) may be used to confirm microbial geochemical activity.…”

H2S Associated With Heavy Oils in Reservoirs Under Primary Production: Cases of Grimbeek and El Alba Fields in Gulf of San Jorge Basin, Argentina

“…The H 2 S souring in the Argentinian fields has been reported with unique characteristics (11,15) that do not respond to classical models documented in other parts of the world. H 2 S souring has been documented in oil fields where the injection water and connate waters have low sulphate contents (16) and in this case, with reservoir temperatures close to 70-80ºC, without another apparent cause than bacteriological activity.…”