Reservoir Souring Research Articles

Souring control in fluid samples of oil industry using a multiple ligand simultaneous docking (MLSD) strategy

We have used docking techniques in order to propose potential inhibitors to the enzymes adenosine phosphosulfate reductase and adenosine triphosphate sulfurylase that are responsible, among other deleterious effects, for causing souring of oil and gas reservoirs. Three candidates selected through molecular docking revealed new and improved polar and hydrophobic interactions with the above-mentioned enzymes. Microbiological laboratory assays performed subsequently corroborated the results of computer modelling that the three compounds can efficiently control the biogenic sulfide production.

Inhibition of microbial sulfate reduction in a flow-through column system by (per)chlorate treatment.

Microbial sulfate reduction is a primary cause of oil reservoir souring. Here we show that amendment with chlorate or perchlorate [collectively (per)chlorate] potentially resolves this issue. Triplicate packed columns inoculated with marine sediment were flushed with coastal water amended with yeast extract and one of nitrate, chlorate, or perchlorate. Results showed that although sulfide production was dramatically reduced by all treatments, effluent sulfide was observed in the nitrate (10 mM) treatment after an initial inhibition period. In contrast, no effluent sulfide was observed with (per)chlorate (10 mM). Microbial community analyses indicated temporal community shifts and phylogenetic clustering by treatment. Nitrate addition stimulated Xanthomonadaceae and Rhizobiaceae growth, supporting their role in nitrate metabolism. (Per)chlorate showed distinct effects on microbial community structure compared with nitrate and resulted in a general suppression of the community relative to the untreated control combined with a significant decrease in sulfate reducing species abundance indicating specific toxicity. Furthermore, chlorate stimulated Pseudomonadaceae and Pseudoalteromonadaceae, members of which are known chlorate respirers, suggesting that chlorate may also control sulfidogenesis by biocompetitive exclusion of sulfate-reduction. Perchlorate addition stimulated Desulfobulbaceae and Desulfomonadaceae, which contain sulfide oxidizing and elemental sulfur-reducing species respectively, suggesting that effluent sulfide concentrations may be controlled through sulfur redox cycling in addition to toxicity and biocompetitive exclusion. Sulfur isotope analyses further support sulfur cycling in the columns, even when sulfide is not detected. This study indicates that (per)chlorate show great promise as inhibitors of sulfidogenesis in natural communities and provides insight into which organisms and respiratory processes are involved.

Biological souring of crude oil under anaerobic conditions

Seawater injection into oil reservoirs for purposes of secondary oil recovery is frequently accompanied by souring (increased sulfide concentrations). Production of hydrogen sulfide causes various problems, such as microbiologically influenced corrosion (MIC) and deterioration of crude oil. Sulfate-reducing bacteria (SRB) are considered to be major players in souring. Volatile fatty acids (VFAs) in oil-field water are believed to be produced by microbial degradation of crude oil. The objective of this research was to investigate mechanisms of souring, focusing specifically on VFA production via crude oil biodegradation. To this end, a microbial consortium collected from an oil–water separator was suspended in seawater; crude oil or liquid n-alkane mixture was added to the culture medium as the sole carbon source, and the culture was incubated under anaerobic conditions for 190 days. Physicochemical analysis showed that preferential toluene degradation and sulfate reduction occurred concomitantly in the culture containing crude oil. Sulfide concentrations were much lower in the alkane-supplemented culture than in the crude oil-supplemented culture. These observations suggest that SRB are related to the toluene activation and VFA consumption steps of crude oil degradation. Therefore, the electron donors for SRB are not only VFA, but many components of crude oil, especially toluene. Alkanes were also degraded by microorganisms, but did not contribute to reservoir souring.

Comparison of microbial communities involved in souring and corrosion in offshore and onshore oil production facilities in Nigeria

Samples were obtained from the Obigbo field, located onshore in the Niger delta, Nigeria, from which oil is produced by injection of low-sulfate groundwater, as well as from the offshore Bonga field from which oil is produced by injection of high-sulfate (2,200ppm) seawater, amended with 45ppm of calcium nitrate to limit reservoir souring. Despite low concentrations of sulfate (0-7ppm) and nitrate (0ppm), sulfate-reducing bacteria (SRB) and heterotrophic nitrate-reducing bacteria (NRB) were present in samples from the Obigbo field. Biologically active deposits (BADs), scraped from corrosion-failed sections of a water- and of an oil-transporting pipeline (both Obigbo), had high counts of SRB and high sulfate and ferrous iron concentrations. Analysis of microbial community composition by pyrosequencing indicated anaerobic, methanogenic hydrocarbon degradation to be a dominant process in all samples from the Obigbo field, including the BADs. Samples from the Bonga field also had significant activity of SRB, as well as of heterotrophic and of sulfide-oxidizing NRB. Microbial community analysis indicated high proportions of potentially thermophilic NRB and near-absence of microbes active in methanogenic hydrocarbon degradation. Anaerobic incubation of Bonga samples with steel coupons gave moderate general corrosion rates of 0.045-0.049mm/year, whereas near-zero general corrosion rates (0.001-0.002mm/year) were observed with Obigbo water samples. Hence, methanogens may contribute to corrosion at Obigbo, but the low general corrosion rates cannot explain the reasons for pipeline failures in the Niger delta. A focus of future work should be on understanding the role of BADs in enhancing under-deposit pitting corrosion.

Functional genes (dsr) approach reveals similar sulphidogenic prokaryotes diversity but different structure in saline waters from corroding high temperature petroleum reservoirs

Oil reservoirs and production facilities are generally contaminated with H2S resulting from the activity of sulphidogenic prokaryotes (SRP). Sulphidogenesis plays a major role in reservoir souring and microbial influenced corrosion in oil production systems. In the present study, sulphidogenic microbial diversity and composition in saline production fluids retrieved from three blocks of corroding high temperature (79 ~ 95 °C) oil reservoirs with high sulfate concentrations were investigated by phylogenetic analyses of gene fragments of the dissimilatory sulfite reductase (dsr). Analysis of dsr gene fragments revealed the presence of several clusters of sulphidogenic prokaryotes that cover the orders Desulfovibrionales (Desulfovibrio, Desulfomicrobium thermophilum), Desulfobacterales (Desulfobacterium, Desulfosarcina, Desulfococcus, Desulfotignum, Desulfobotulus, Desulfobulbus), Syntrophobacterales (Desulfacinum, Thermodesulforhabdus, Desulforhabdus), Clostridiales (Desulfotomaculum) and Archaeoglobales (Archaeoglobus); among which sequences affiliated to members of Desulfomicrobium, Desulfotomaculum and Desulfovibrio appeared to be the most encountered genera within the three blocks. Collectively, phylogenetic and non-metric multidimensional scaling analyses indicated similar but structurally different sulphidogenic prokaryotes communities within the waters retrieved from the three Blocks. This study show the diversity and composition of sulphidogenic prokaryotes that may play a role in the souring mediated corrosion of the oilfield and also provides a fundamental basis for further investigation to control oil reservoir souring and corrosion of pipelines and topside installations.

Laboratory investigation of microbiologically influenced corrosion of C1018 carbon steel by nitrate reducing bacterium Bacillus licheniformis

Abstract Nitrate injection is used to suppress reservoir souring in oil and gas fields caused by Sulfate Reducing Bacteria (SRB) through promotion of nitrate respiration by Nitrate Reducing Bacteria (NRB). However, it is not well publicized that nitrate reduction by NRB can cause Microbiologically Influenced Corrosion (MIC) because nitrate reduction coupled with iron oxidation is thermodynamically favorable. NRB benefits bioenergetically from this redox reaction under biocatalysis. This work showed that the Bacillus licheniformis biofilm, when grown as an NRB biofilm, caused a 14.5 μm maximum pit depth and 0.89 mg/cm 2 normalized weight loss against C1018 carbon steel in one-week lab tests.

Application of Denaturing High-Performance Liquid Chromatography for Monitoring Sulfate-Reducing Bacteria in Oil Fields

Sulfate-reducing bacteria (SRB) participate in microbially induced corrosion (MIC) of equipment and H2S-driven reservoir souring in oil field sites. Successful management of industrial processes requires methods that allow robust monitoring of microbial communities. This study investigated the applicability of denaturing high-performance liquid chromatography (DHPLC) targeting the dissimilatory sulfite reductase ß-subunit (dsrB) gene for monitoring SRB communities in oil field samples from the North Sea, the United States, and Brazil. Fifteen of the 28 screened samples gave a positive result in real-time PCR assays, containing 9 × 10(1) to 6 × 10(5) dsrB gene copies ml(-1). DHPLC and denaturing gradient gel electrophoresis (DGGE) community profiles of the PCR-positive samples shared an overall similarity; both methods revealed the same samples to have the lowest and highest diversity. The SRB communities were diverse, and different dsrB compositions were detected at different geographical locations. The identified dsrB gene sequences belonged to several phylogenetic groups, such as Desulfovibrio, Desulfococcus, Desulfomicrobium, Desulfobulbus, Desulfotignum, Desulfonatronovibrio, and Desulfonauticus. DHPLC showed an advantage over DGGE in that the community profiles were very reproducible from run to run, and the resolved gene fragments could be collected using an automated fraction collector and sequenced without a further purification step. DGGE, on the other hand, included casting of gradient gels, and several rounds of rerunning, excising, and reamplification of bands were needed for successful sequencing. In summary, DHPLC proved to be a suitable tool for routine monitoring of the diversity of SRB communities in oil field samples.

Case Study--Calcium-Carbonate-Scale Inhibitor Performance Degradation Because of H2S-Scavenger Injection in Semoga Field

Summary Semoga field is an oil field in the Rimau block, which is located in South Sumatra, Indonesia. There is also a nearby oil field, Kaji field, in this block. These fields experienced reservoir souring and suffered a history of calcium-carbonate (CaCO3) -scale cases before a proper scale-inhibition program was implemented. At the end of January 2011, there was a separation-system problem at free water knock-out (FWKO) #2 Semoga Station. FWKO outlet lines were dismantled for inspection purposes, and it was found that the oil-outlet line at the downstream of the level control valve (LCV) was clogged by deposits, leaving an inner diameter (ID) of only 0.5 in. X-ray defraction (XRD) and X-ray fluorescence (XRF) analyses confirm that the deposit is CaCO3 scale, even though routine scale-coupon monitoring shows very low scale growth. There is a hydrogen sulfide (H2S) scavenger Brand X injection at the downstream of the LCV on the FWKO #2, with a concentration of 11,050 ppm. The scale-inhibitor dosage in the water line on Semoga Station was only 9-10 ppm. Laboratory simulation shows that H2S scavenger Brand X injection reduced the scale-inhibition percentage from 97.2 to 35.3%, with 9 ppm of scale inhibitor. Meanwhile, no deposits were found in the oil-outlet line at the downstream of the LCV at Kaji Station, which has the same H2S scavenger-injection point and dosage. The scale-inhibitor dosage in the water line at Kaji Station was 17.5-22 ppm. Laboratory simulation shows that 20 ppm of scale inhibitor resulted in a scaleinhibition percentage of 58%. Laboratory analysis shows that the scale-inhibition percentage increases linearly as the scale inhibitor increases under H2S scavenger Brand X influence. However, another laboratory test conducted using H2S scavenger Brand Y shows that the scale-inhibition percentage will decrease with the increase of scale inhibitor concentration, until it reaches the lowest value before increasing again with the increase of scale inhibitor concentration. Thus, the scale-inhibitor performance under H2S scavenger Brand Y influence behaves parabolically. It is concluded that H2S-scavenger injection increases system pH, resulting in the increase of scaling tendency. However, adding scale-inhibitor concentration is not always the answer to overcoming scale growth resulting from this effect. It is important to understand scale-inhibitor performance behavior on certain H2S scavenger brands before taking preventive measures. Scale-inhibitor performance might have a linear correlation between increasing concentration and scale-inhibition percentage, as shown by the behavior with H2S scavenger Brand X, but it might also have a parabolic correlation, as shown by the behavior with H2S scavenger Brand Y or even other correlation types.

Lessons Learned From Applications of a New Organic-Oil-Recovery Method That Activates Resident Microbes

Summary Using a breakthrough process, which does not require microbes to be injected, more than 100 microbial enhanced-oil-recovery (MEOR) treatments were conducted from 2007 to the end of 2010 in oil-producing and water-injection wells in the United States and Canada. On average, these treatments increased oil production by 122%, with an 89% success rate. This paper reviews the MEOR process, reviews the results of the first 100+ treatments, and shares what has been learned from this work. Observations and conclusions include the following: Screening reservoirs is critical to success. Identifying reservoirs where appropriate microbes are present and oil is movable is the key. MEOR can be applied to a wide range of oil gravities. MEOR has been applied successfully to reservoirs with oil gravity as high as 41° API and as low as 16° API. When microbial growth is appropriately controlled, reservoir plugging or formation damage is no longer a risk. Microbes reside in extreme conditions and can be manipulated to perform valuable in-situ "work." MEOR has been applied successfully at reservoir temperatures as high as 200°F and salinities as high as 140,000 ppm total dissolved solids (TDS). MEOR can be applied successfully in dual-porosity reservoirs. A side benefit of applying MEOR is that it can reduce reservoir souring. An oil response is not always observed when treating producing wells. MEOR can be applied to many more reservoirs than thought originallys with little downside risk. This review of more than 100 MEOR well treatments expands the types of reservoirs in which MEOR can be applied successfully. Low-risk and economically attractive treatments can be accomplished when appropriate scientific analysis and laboratory screening are performed before treatments.

Modeling and Simulation of Nitrate Injection for Reservoir Souring Remediation

Summary Reservoir souring refers to the onset of hydrogen sulfide (H2S) production during waterflooding. Besides health and safety issues, H2S content reduces the value of the produced hydrocarbon. Nitrate injection is an effective method to prevent the formation of H2S. Designing this process requires the modeling of a complicated set of biogeochemical reactions involved in the production of H2S and its inhibition. This paper describes the modeling and simulation of biological reactions associated with the injection of nitrate to inhibit reservoir souring. The model is implemented in a general-purpose adaptive reservoir simulator (GPAS). To the best of our knowledge, GPAS is the first field-scale reservoir simulator that models reservoir souring treatment. The basic mechanism in the biologically mediated generation of H2S is the reaction between sulfate in the injection water and fatty acids in the formation water in the presence of sulfate-reducing bacteria (SRB). There are proposed mechanisms that describe the effect of nitrate injection on souring remediation. Depending on the circumstances, more than one mechanism may occur at the same time. These mechanisms include the inhibitory effect of nitrite on sulfate reduction, the competition between SRB and nitrate-reducing bacteria (NRB), and the stimulation of nitrate-reducing sulfide-oxidizing bacteria (NR-SOB). For each mechanism, we specify the biological species and chemical components involved and determine the role of each component in the biological reaction. For every biological reaction, a set of ordinary differential equations along with differential equations for the transport of chemical and biological species are solved. The results of reported experiments in the literature are used to find the input parameters for field-scale simulations. This reservoir simulator can then predict the onset of reservoir souring and the effectiveness of nitrate injection and helps in the design of the process. The comprehensive modeling accounts for variation in biological system characteristics and reservoir conditions that affect the production and remediation of H2S.

Short term corrosion monitoring of carbon steel by bio-competitive exclusion of thermophilic sulphate reducing bacteria and nitrate reducing bacteria

Recent interest has centred on the application of nitrate injection to control reservoir souring. In the present study, the impact of nitrate injection on the corrosion of ASTM A572-50 carbon steel was evaluated. The steel samples were exposed to corrosive production water (high chloride and sulphate) for 21 days at 50°C. Crude oil and NaNO3 were added as bacterial nutrients. Indigenous bacterial isolates were used and four different conditions were evaluated: control cell (no bacteria), nitrate reducing bacteria (NRB) inoculated cell, sulphate reducing bacteria (SRB) inoculated cell and mixed bacteria (NRB+SRB) inoculated cell. Open circuit potential (Ecorr) and Electrochemical impedance spectroscopy (EIS) were employed to monitor the corrosion process throughout the immersion time. It is shown that the corrosion rates in the cells inoculated with bacteria are lower than the control cell. Both NRB and SRB may offer beneficial corrosion protection to the steel. However, the microscopy results show that localized corrosion in the presence of bacteria is inevitable. Additionally, nitrate promotes the growth of NRB and suppresses the growth of SRB; hence H2S production can be eliminated. NRB oxidize the produced sulphide by SRB and maintain Eh in an inhibitory level to SRB.

Assessing the Magnitude and Consequences of Reservoir Souring

Reservoir souring Reservoir souring, defined as the unplanned increase in hydrogen sulfide (H2S) in produced fluids during field life, is a growing concern for the petroleum production industry. H2S is a poisonous, dense gas with serious safety implications; it can lead to sudden catastrophic failure of nonresistant metallic materials from sulfide stress corrosion cracking or hydrogen-induced cracking, and it can enhance pitting corrosion rates. But how does reservoir souring develop, and how can its consequences for materials be anticipated? Consideration also needs to be given to the currently available options for souring control and their shortcomings. Despite the significant advances that have been made over the past 30 years or so in the understanding of H2S- related materials degradation mechanisms, H2S still causes many failures every year. While it may be understandable that such failures continue to occur in operating environments where reservoir souring is a new phenomenon, failures are also occurring where the industry is mature. For example, recently in the UK, a carbon steel pipeline transporting sour hydrocarbons onshore failed by sulfide stress cracking (SSC) after 6 weeks of operation, necessitating replacement at a cost of GBP 100 million. Over 2000–01, sour gas pipelines failures, including those affected by both microbial and chemically induced corrosion, accounted for 35 (4%) of the 952 pipeline failures in Alberta, Canada. The challenge of dealing with H2S is likely to rise in importance as an increasing number of high-temperature, high-pressure (HTHP) reservoirs are exploited in the future. This will require more widespread use of corrosion resistant alloys (CRAs), increasing the costs of wells and downstream equipment. Therefore, we need more corrosion data on a range of alloys when there are fewer materials engineers (particularly metallurgists) coming into the industry and fewer corrosion testing facilities in steel companies, meaning that operating companies and even fabrication contractors are having to take on the task of generating materials susceptibility data. H2S Generation and Mobility Reservoir souring is the production of increased concentrations of H2S in well-stream fluids from production wells subject to water injection for secondary recovery. It is generally acknowledged to be caused by the activity of a specialized group of microorganisms, the sulfate-reducing bacteria (SRB). Low populations of SRB cells are ubiquitous in seawater and many other natural waters that are used for secondary recovery. Biogenic H2S originates solely from SRB activity in the water phase and subsequently partitions between water, liquid hydrocarbon, and gas, dependent on temperature, pressure, the pH of the aqueous phase, fluid phase ratios, and a number of other factors. However, the progress of reservoir souring is routinely measured and expressed in terms of H2S concentrations in the gas phase at separator conditions and the corresponding partial pressures of gaseous H2S.

Subsea Water Treatment Comes of Age

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper OTC 21578, ’Subsea Water Treatment Comes of Age,’ by David Pinchin, SPE, Well Processing A/S, originally prepared for the 2011 Offshore Technology Conference, Houston, 2-5 May. The paper has not been peer reviewed. This subsea seawater-treatment system has undergone several phases of development since its inception in 2002. It works by extracting water from the seabed area (where there are inherent advantages such as space, stable temperatures, lower degree of bacterial concentration, and distance from platform discharges). A combination of residence time within a “still room,” two steps of electrochemical disinfection, and chemical dosing are implemented to achieve disinfection and solids reduction. Introduction Water injection (waterflooding) is by far the most used method of increasing oil recovery from an oil reservoir. Water quality is an important factor for maximizing sweep efficiency (displacement of oil) during waterflooding and also preventing reservoir souring. Key objectives of seawater-treatment plants are therefore to minimize the blocking of reservoir pores (e.g., with solids, biomass, and scale) and to control reservoir souring. The full-length paper describes a subsea seawater-treatment system that is seen as filling the “missing link” to the already proven technology of “raw” seawater injection on the seabed by subsea pumps. To be accepted as a viable water-treatment process, it must be capable of providing at least the same level of reservoir protection as afforded by a topside seawater-treatment plant. Subsea Treatment System and Testing The subsea treatment unit comprises several equipment items assembled in such a way as to maximize solids removal and disinfection of the seawater. The process uses the seabed environment and makes use of its beneficial effects. A still room is used to isolate the water to be treated from external conditions (e.g., storms and tidal movements). The inlet compartment is designed to allow for a good degree of solids settling with sufficient density to drop out. The water then is chlorinated by electrolysis as it transfers to a second compartment where it is afforded a long residence time to allow the chlorine reaction to take place and to allow further solids settling. The water exiting the still room then flows through a hydroxyl-radical generator where a final oxidation process takes place. The treatment unit therefore generates its own treatment chemicals by electrolysis and requires only a combined power/control signal interface cable. For the testing, a submerged lift pump was used to induce flow through the subsea treatment unit and up to an onshore sampling/control container.

Biocorrosion of carbon steel by a nitrate-utilizing consortium of sulfate-reducing bacteria obtained from an Algerian oil field

The biooxidation of sulfide under denitrifying conditions is a key process in the control of souring in oil reservoirs and in the treatment of gas and liquids contaminated with sulfide and nitrate. The effect of nitrate injection on the microbial community has been evaluated in the setting of offshore oil industry production, but has not been studied onshore, such as in the Algerian oilfields. A consortium of sulfate-reducing bacteria (SRB) was isolated by first inoculating saline Postgate’s medium C with injection water obtained from the In Amenas oil field, situated in the South Eastern Algerian Sahara, and then exposing the test solution to sulfate. When nitrate was dosed at 120 mg/l it was reduced by this bacterial consortium, with some ammonium production. This mechanism could be important in oilfield systems where nitrate is applied to prevent sulfide generation by SRB that leads to reservoir souring. In static tests, the influence of this SRB consortium on corrosion was assessed using carbon steel coupons, in the presence of sulfate alone and sulfate with 120 mg/l nitrate. The results of the static test indicate that the occurrence of pitting corrosion was fairly low under this condition. This is the first report on the use of nitrates in the fight against corrosion in the Algerian oil industry.

A model for transport of hydrogen sulfide in oil- and water-saturated porous media

In several oilfields, reservoir souring by generation of hydrogen sulfide (H2S) occurs in secondary recovery during which seawater is injected into originally sweet reservoirs. At the production site, high concentrations of H2S can cause severe damage to both equipment and human personnel. Proper modeling of H2S concentration in produced fluids can be useful for decision-making during field development design. We present a model for the transport of H2S in an oil- and water-saturated, water-wet porous medium. The different retardation mechanisms for the H2S are described. For the adsorption of H2S to rock, we include two distinct phases of adsorption. In addition, we introduce a functional relationship between adsorption capacity and permeability. As H2S mixes with oil, fractions become immobile as part of the residual oil.

Development and Implementation of a Multidimensional Reservoir Souring Module in a Chemical Flooding Simulator

Reservoir souring is an after-production phenomenon in reservoirs that are subjected to seawater injection. Souring can damage the reservoir rocks, production facilities, and the environment. In order to predict the onset of reservoir souring, several models have been developed. Study of the published models for the reservoir souring prediction shows that there are many inconsistencies between the simulated results and field data. These differences are due to the capability of the models to consider the effective parameters in the porous media. In this study, we introduce a new model that has more features than previous models in simulation of generation and transportation of H2S in reservoir for the purpose of field applications.

Application of a 3D Reservoir Simulator with Biodegradation Capability to Evaluate Reservoir Souring Predictive Models

Reservoir souring is a process in which a previously sweet oil field starts to produce fluids (oil, gas, or water) that contain H2S. It is costly and difficult to address these problems after a field development plan is already in place. In this article, a new reservoir souring model developed and implemented in a chemical flooding simulator is used to evaluate the capabilities of the previous models on reservoir souring. This study reveals the limitations of the published models in prediction of reservoir souring in oil fields and advantages of the developed model and simulator.

Chelators enhanced biocide inhibition of planktonic sulfate-reducing bacterial growth

Biocides are currently the primary mitigation method to control sulfate-reducing bacteria (SRB) in biofouling, reservoir souring and microbiologically influenced corrosion. Increasingly restrictive environmental regulations and safety concerns on biocide uses demand more efficient dosing of biocides. Chelators have been known to enhance antibiotics because of their properties such as increasing the permeability of the outer cell membrane of Gram-negative bacteria. Two readily biodegradable chelators, ethylenediaminedisuccinate (EDDS) and N-(2-hydroxyethyl)iminodiacetic acid (HEIDA) disodium salts that are touted as potential replacements of ethylenediaminetetraacetic acid (EDTA), were evaluated as potential biocide enhancers for glutaraldehyde and tetrakis hydroxymethyl phosphonium sulfate (THPS) in their inhibition of planktonic SRB growth. Desulfovibrio vulgaris ATCC 7757 and Desulfovibrio desulfuricans ATCC 14563 were grown in modified ATCC 1249 medium and in enriched artificial seawater, respectively. Laboratory tests in 100 ml anaerobic vials showed that EDDS or HEIDA alone did not inhibit SRB growth. However, when EDDS or HEIDA was combined with glutaraldehyde or THPS, each of them enhanced the biocide inhibition of planktonic SRB growth.

Prokaryotic Community Structure and Sulfate Reducer Activity in Water from High-Temperature Oil Reservoirs with and without Nitrate Treatment

Sulfate-reducing prokaryotes (SRP) cause severe problems like microbial corrosion and reservoir souring in seawater-injected oil production systems. One strategy to control SRP activity is the addition of nitrate to the injection water. Production waters from two adjacent, hot (80 degrees C) oil reservoirs, one with and one without nitrate treatment, were compared for prokaryotic community structure and activity of SRP. Bacterial and archaeal 16S rRNA gene analyses revealed higher prokaryotic abundance but lower diversity for the nitrate-treated field. The 16S rRNA gene clone libraries from both fields were dominated by sequences affiliated with Firmicutes (Bacteria) and Thermococcales (Archaea). Potential heterotrophic nitrate reducers (Deferribacterales) were exclusively found at the nitrate-treated field, possibly stimulated by nitrate addition. Quantitative PCR of dsrAB genes revealed that archaeal SRP (Archaeoglobus) dominated the SRP communities, but with lower relative abundance at the nitrate-treated site. Bacterial SRP were found in only low abundance at both sites and were nearly exclusively affiliated with thermophilic genera (Desulfacinum and Desulfotomaculum). Despite the high abundance of archaeal SRP, no archaeal SRP activity was detected in [(35)S]sulfate incubations at 80 degrees C. Sulfate reduction was found at 60 degrees C in samples from the untreated field and accompanied by the growth of thermophilic bacterial SRP in batch cultures. Samples from the nitrate-treated field generally lacked SRP activity. These results indicate that (i) Archaeoglobus can be a major player in hot oil reservoirs, and (ii) nitrate may act in souring control-not only by inhibiting SRP, but also by changing the overall community structure, including the stimulation of competitive nitrate reducers.

A Process Option To Comply With Zero-Harmful-Discharge Legislation in Norwegian Waters

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper SPE 118012, "The CTour Process, an Option To Comply With Zero-Harmful-Discharge Legislation in Norwegian Waters - Experience of CTour Installation on Ekofisk After Startup 4th Quarter 2007," by Kare Voldum and Eimund Garpestad, ConocoPhillips Norway, and Nils Olav Anderssen and Inge Brun Henriksen, ProPure, originally prepared for the 2008 SPE Abu Dhabi International Petroleum Exhibition and Conference, Abu Dhabi, UAE, 3-6 November. The paper has not been peer reviewed. A series of joint-industry projects in conjunction with Norwegian research institutions have developed a solvent extraction process to remove contaminants from produced water. Results from performance testing indicate that the efficiency from the original pilot tests had been reproduced successfully, yielding on a field scale residual oil in water (OIW) of 1 to 2 ppm and naphthalenes and polycyclic-aromatic-hydrocarbon (PAH) reduction by 86 to 92%. Introduction The Ekofisk field, operated by ConocoPhillips, is the oldest operating field in the Norwegian sector of the North Sea. It is a carbonate reservoir that has been seawater flooded since 1986. Currently, it is in a stage of increasing water cut that is projected to peak at 41 000 m3/d by year 2015. The Norwegian operators have to comply with the OSPAR (which replaced the Oslo and Paris Conventions) discharge legislation, which states that overboard discharges of hydrocarbons cannot exceed 30 ppm and that the annual total oil discharges cannot exceed 85% of the reported annual discharges of the year 2000. This represents a big challenge for an operator experiencing increasing water cut. In the Norwegian sector of the North Sea, in addition to the OSPAR legislation, operators must comply with specific Norwegian legislation that calls for "zero environmental impact" from overboard discharges. The environmental-impact factor (EIF) is used as a tool to quantify the harmful effect of discharges to the environment. The EIF was developed as a management tool on the basis of internationally agreed procedures for hazard and risk assessment. The tool models the dispersion of produced water, accounting for volume, composition of oil and aromatic components [benzene, toluene, ethyl benzene, and zylene (BTEX) and naphthalenes, PAHs, and phenols], production chemicals, and heavy metals, and it calculates the predicted-environmental-concentration/predicted-no-effect-concentration ratio. To comply with the new discharge legislation, ConocoPhillips originally projected to achieve a 95% reduction in EIF at Ekofisk by introducing produced-water reinjection (PWRI). However, after a pilot PWRI test was performed, the conclusion was that reinjection was not cost efficient, and most importantly, it became apparent that it introduced a risk of reservoir souring, and could cause substantial loss of oil produced.