To see the other types of publications on this topic, follow the link: Oil reservoir souring.
Journal articles on the topic 'Oil reservoir souring'
Create a spot-on reference in APA, MLA, Chicago, Harvard, and other styles
Consult the top 45 journal articles for your research on the topic 'Oil reservoir souring.'
Next to every source in the list of references, there is an 'Add to bibliography' button. Press on it, and we will generate automatically the bibliographic reference to the chosen work in the citation style you need: APA, MLA, Harvard, Chicago, Vancouver, etc.
You can also download the full text of the academic publication as pdf and read online its abstract whenever available in the metadata.
Browse journal articles on a wide variety of disciplines and organise your bibliography correctly.
1
Jahanbani Veshareh, Moein, and Shahab Ayatollahi. "Microorganisms’ effect on the wettability of carbonate oil-wet surfaces: implications for MEOR, smart water injection and reservoir souring mitigation strategies." Journal of Petroleum Exploration and Production Technology 10, no. 4 (September 12, 2019): 1539–50. http://dx.doi.org/10.1007/s13202-019-00775-6.
Full textAbstract:
Abstract In upstream oil industry, microorganisms arise some opportunities and challenges. They can increase oil recovery through microbial enhanced oil recovery (MEOR) mechanisms, or they can increase production costs and risks through reservoir souring process due to H2S gas production. MEOR is mostly known by bioproducts such as biosurfactant or processes such as bioclogging or biodegradation. On the other hand, when it comes to treatment of reservoir souring, the only objective is to inhibit reservoir souring. These perceptions are mainly because decision makers are not aware of the effect microorganisms’ cell can individually have on the wettability. In this work, we study the individual effect of different microorganisms’ cells on the wettability of oil-wet calcite and dolomite surfaces. Moreover, we study the effect of two different biosurfactants (surfactin and rhamnolipid) in two different salinities. We show that hydrophobe microorganisms can change the wettability of calcite and dolomite oil-wet surfaces toward water-wet and neutral-wet states, respectively. In the case of biosurfactant, we illustrate that the ability of a biosurfactant to change the wettability depends on salinity and its hydrophilic–hydrophobic balance (HLB). In distilled water, surfactin (high HLB) can change the wettability to a strongly water-wet state, while rhamnolipid only changes the wettability to a neutral-wet state (low HLB). In the seawater, surfactin is not able to change the wettability, while rhamnolipid changes the wettability to a strongly water-wet state. These results help reservoir managers who deal with fractured carbonate reservoirs to design a more effective MEOR plan and/or reservoir souring treatment strategy.
2
Sugai, Yuichi, Yukihiro Owaki, and Kyuro Sasaki. "Simulation Study on Reservoir Souring Induced by Injection of Reservoir Brine Containing Sulfate-Reducing Bacteria." Sustainability 12, no. 11 (June 4, 2020): 4603. http://dx.doi.org/10.3390/su12114603.
Full textAbstract:
This paper examined the reservoir souring induced by the sulfate-reducing bacteria (SRB) inhabiting the reservoir brine of an oilfield in Japan. Although the concentration of sulfate of the reservoir brine was lower than that of seawater, which often was injected into oil reservoir and induced the reservoir souring, the SRB inhabiting the reservoir brine generated hydrogen sulfide (H2S) by using sulfate and an electron donor in the reservoir brine. This paper therefore developed a numerical simulator predicting the reservoir souring in the reservoir into which the reservoir brine was injected. The results of the simulation suggested that severe reservoir souring was not induced by the brine injection; however, the SRB grew and generated H2S around the injection well where temperature was decreased by injected brine whose temperature was lower than that of formation water. In particular, H2S was actively generated in the mixing zone between the injection water and formation water, which contained a high level of the electron donor. Furthermore, the results of numerical simulation suggested that the reservoir souring could be prevented more surely by sterilizing the SRB in the injection brine, heating up the injection brine to 50 °C, or reducing sulfate in the injection brine.
3
Basafa, Mahsan, and Kelly Hawboldt. "Reservoir souring: sulfur chemistry in offshore oil and gas reservoir fluids." Journal of Petroleum Exploration and Production Technology 9, no. 2 (August 4, 2018): 1105–18. http://dx.doi.org/10.1007/s13202-018-0528-2.
Full text
4
Fan, Fuqiang, Baiyu Zhang, Penny L. Morrill, and Tahir Husain. "Isolation of nitrate-reducing bacteria from an offshore reservoir and the associated biosurfactant production." RSC Advances 8, no. 47 (2018): 26596–609. http://dx.doi.org/10.1039/c8ra03377c.
Full text
5
Basafa, Mahsan, and Kelly Hawboldt. "Sulfur speciation in soured reservoirs: chemical equilibrium and kinetics." Journal of Petroleum Exploration and Production Technology 10, no. 4 (January 2, 2020): 1603–12. http://dx.doi.org/10.1007/s13202-019-00824-0.
Full textAbstract:
AbstractReservoir souring is a widespread phenomenon in reservoirs undergoing seawater injection. Sulfate in the injected seawater promotes the growth of sulfate-reducing bacteria (SRB) and archaea-generating hydrogen sulfide. However, as the reservoir fluid flows from injection well to topside facilities, reactions involving formation of different sulfur species with intermediate valence states such as elemental sulfur, sulfite, polysulfide ions, and polythionates can occur. A predictive reactive model was developed in this study to investigate the chemical reactivity of sulfur species and their partitioning behavior as a function of temperature, pressure, and pH in a seawater-flooded reservoir. The presence of sulfur species with different oxidation states impacts the amount and partitioning behavior of H2S and, therefore, the extent of reservoir souring. The injected sulfate is reduced to H2S microbially close to the injection well. The generated H2S partitions between phases depending on temperature, pressure, and pH. Without considering chemical reactivity and sulfur speciation, the gas phase under test separator conditions on the surface contains 1080 ppm H2S which is in equilibrium with the oil phase containing 295.7 ppm H2S and water phase with H2S content of 8.8 ppm. These values are higher than those obtained based on reactivity analysis, where sulfur speciation and chemical reactions are included. Under these conditions, the H2S content of the gas, oil, and aqueous phases are 487 ppm, 134 ppm, and 4 ppm, respectively.
6
Abrakasa, S., and H. O. Nwankwoala. "The Presence of 2-Thiaadamantane in Niger Delta Oils may indicate Souring in Niger Delta Reservoirs." Pakistan Journal of Geology 3, no. 1 (June 1, 2019): 22–27. http://dx.doi.org/10.2478/pjg-2019-0003.
Full textAbstract:
AbstractSome oil samples from various Nigerian oil fields were examined for the presence of Thermochemical Sulphate Reduction (TSR) derived organo sulphur compounds. Oil samples were diluted with DCM and injected into the GC–MS for full scan analysis. The GC–MS results show the presence 2–thiaadamantane, 1–methyl-2-thiaadamanatane and 5–methyl-2-thiaadamanatane, the compounds were identified by comparison of extracted spectras with literature. The presence of these compounds in oils has been accepted on a wider horizon as indicators of reservoir souring. The plot of 5–Methyl-2-thiaadamantane/Adamantane and Dibenzothiophene/Adamanatane showed a fair correlation, corroborating the presence of 5–Methyl-2-thiaadamantane and fairly high abundance of Dibenzothiophene, the plot of 2-thiaadamantane/Adamantane and 5–Methyl-2-Thiaadamantane/Adamantane corroborating the presence of 2-thiaadamantane and 5–Methyl-2-Thiaadamantane inferring that the presence of 2-thiaadamantane and 5–Methyl-2-Thiaadamantane indicate that reservoir souring is active.
7
Coombe, Dennis A., Tom Jack, Gerrit Voordouw, Frank Zhang, Bill Clay, and Kirk Miner. "Simulation of Bacterial Souring Control in an Alberta Heavy-Oil Reservoir." Journal of Canadian Petroleum Technology 49, no. 05 (May 1, 2010): 19–26. http://dx.doi.org/10.2118/137046-pa.
Full text
8
Zahner, R. L. L., S. J. J. Tapper, B. W. G. W. G. Marcotte, and B. R. R. Govreau. "Lessons Learned From Applications of a New Organic-Oil-Recovery Method That Activates Resident Microbes." SPE Reservoir Evaluation & Engineering 15, no. 06 (December 6, 2012): 688–94. http://dx.doi.org/10.2118/145054-pa.
Full textAbstract:
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.
9
Liu, Jin-Feng, Wei-Lin Wu, Feng Yao, Biao Wang, Bing-Liang Zhang, Serge Maurice Mbadinga, Ji-Dong Gu, and Bo-Zhong Mu. "A thermophilic nitrate-reducing bacterium isolated from production water of a high temperature oil reservoir and its inhibition on sulfate-reducing bacteria." Applied Environmental Biotechnology 1, no. 2 (November 18, 2016): 35. http://dx.doi.org/10.18063/aeb.2016.02.004.
Full textAbstract:
A thermophilic spore-forming facultative anaerobic bacterium, designated as Njiang2, was isolated from the production water of a high temperature oil reservoir (87°C). The physiological, biochemical and 16S rRNA gene based phylogenetic analysis indicated that Njiang2 belonged to the genus Anoxybacillus. Njiang2 could significantly inhibit H2S production when co-cultured with Desulfotomaculum sp under laboratory conditions, which implied its great potential in mitigation of brine souring in the oil reservoir and in control of biocorrosion caused by sulfate-reducing bacteria. As far as we know, this might be the first report of Anoxybacillus sp. isolated from high temperature oilfield
10
da Silva, Marcio Luis Busi, Hugo Moreira Soares, Agenor Furigo, Willibaldo Schmidell, and Henry Xavier Corseuil. "Effects of Nitrate Injection on Microbial Enhanced Oil Recovery and Oilfield Reservoir Souring." Applied Biochemistry and Biotechnology 174, no. 5 (August 23, 2014): 1810–21. http://dx.doi.org/10.1007/s12010-014-1161-2.
Full text
11
Gittel, Antje, Ketil Bernt S�rensen, Torben Lund Skovhus, Kjeld Ingvorsen, and Andreas Schramm. "Prokaryotic Community Structure and Sulfate Reducer Activity in Water from High-Temperature Oil Reservoirs with and without Nitrate Treatment." Applied and Environmental Microbiology 75, no. 22 (October 2, 2009): 7086–96. http://dx.doi.org/10.1128/aem.01123-09.
Full textAbstract:
ABSTRACT 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�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 [35S]sulfate incubations at 80�C. Sulfate reduction was found at 60�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.
12
Li, Dongmei, and Philip Hendry. "Microbial diversity in petroleum reservoirs." Microbiology Australia 29, no. 1 (2008): 25. http://dx.doi.org/10.1071/ma08025.
Full textAbstract:
Buried hydrocarbon deposits, such as liquid petroleum, represent an abundant source of reduced carbon for microbes. It is not surprising therefore that many organisms have adapted to an oily, anaerobic life deep underground, often at high temperatures and pressures, and that those organisms have had, and in some cases continue to have, an effect on the quality and recovery of the earth?s diminishing petroleum resources. There are three key microbial processes of interest to petroleum producers: reservoir souring, hydrocarbon degradation and microbially enhanced oil recovery (MEOR).
13
Vargas, Silvia M., Richard Woollam, William Durnie, and Michael Hodges. "Carbon Dioxide Induced Corrosion of Carbon Steel X65 Exposed to Nitrite Aqueous Solutions." SPE Journal 24, no. 05 (August 17, 2018): 2279–91. http://dx.doi.org/10.2118/191134-pa.
Full textAbstract:
Summary Nitrate used to control reservoir souring in oil fields contains nitrite impurities. Nitrite is a strong oxidizer, and when used in souring–treatment fluids, the flow path often includes carbon–steel piping. Vanadium, also an oxidizer, is at times found in oilfield–production streams that commingle with souring–treatment fluids. The interactions between nitrite and vanadium and their effects on carbon steel X65 corrosion were investigated. The effect of nitrite on corrosion was investigated using synthetic brine to simulate produced water [rich in carbon dioxide (CO2), pH value of approximately 5] and seawater (negligible CO2, pH value of approximately 7). Tests were conducted with carbon steel X65 exposed to synthetic brine at 25, 60, and 80°C using a rotating cylinder electrode (RCE). The test results demonstrate the following: The corrosivity of nitrite strongly depends on the pH level. Nitrite increases corrosion at pH of approximately 5 and is relatively benign at pH of approximately 7. Nitrite reduces to ammonium (thermodynamically stable in acid solutions), whereas vanadium(III) delays the formation of ammonium. Inhibited corrosion tests indicate that nitrite reduces the performance of the studied commercial corrosion inhibitors (CIs).
14
Prajapat, Ganshyam, Shikha Jain, Sandeep Rellegadla, Pankaj Tailor, and Akhil Agrawal. "Synergistic approach to control reservoir souring in the moderately thermophilic oil fields of western India." Bioresource Technology Reports 14 (June 2021): 100649. http://dx.doi.org/10.1016/j.biteb.2021.100649.
Full text
15
Prajapat, Ganshyam, Sandeep Rellegadla, Shikha Jain, and Akhil Agrawal. "Reservoir souring control using benzalkonium chloride and nitrate in bioreactors simulating oil fields of western India." International Biodeterioration & Biodegradation 132 (August 2018): 30–39. http://dx.doi.org/10.1016/j.ibiod.2018.04.017.
Full text
16
Callbeck, Cameron M., Xiaoli Dong, Indranil Chatterjee, Akhil Agrawal, Sean M. Caffrey, Christoph W. Sensen, and Gerrit Voordouw. "Microbial community succession in a bioreactor modeling a souring low-temperature oil reservoir subjected to nitrate injection." Applied Microbiology and Biotechnology 91, no. 3 (May 3, 2011): 799–810. http://dx.doi.org/10.1007/s00253-011-3287-2.
Full text
17
Okoro, C. C. "The Biocidal Efficacy of Chlorine Dioxide (ClO2) in the Control of Oil Field Reservoir Souring and Bio-corrosion in the Oil and Gas Industries." Petroleum Science and Technology 33, no. 2 (December 20, 2014): 170–77. http://dx.doi.org/10.1080/10916466.2014.908913.
Full text
18
Rempel, C. L., R. W. Evitts, and M. Nemati. "Dynamics of corrosion rates associated with nitrite or nitrate mediated control of souring under biological conditions simulating an oil reservoir." Journal of Industrial Microbiology & Biotechnology 33, no. 10 (June 7, 2006): 878–86. http://dx.doi.org/10.1007/s10295-006-0142-z.
Full text
19
Li, Zuoli, Zhenghe Xu, Subhash Ayirala, and Ali Yousef. "Smartwater Effects on Wettability, Adhesion, and Oil Liberation in Carbonates." SPE Journal 25, no. 04 (April 17, 2020): 1771–83. http://dx.doi.org/10.2118/193196-pa.
Full textAbstract:
Summary The chemistry of injection water affects oil recovery from carbonate reservoirs by smartwater flooding. It is widely believed that the ions present in the smartwater alter the wettability of carbonate rocks, depending on their type and the amounts present. Although some effort has been made to understand the effects of salinity and water-ion compositions on wettability in carbonates, the prior research studies were mostly limited to contact angle, spontaneous imbibition, and coreflooding. In the current study, adhesion forces between a carbonate substrate and a crude-oil droplet in the brines of varying ionic compositions were measured directly by using a custom-designed integrated-thin-film drainage apparatus (ITFDA) equipped with a bimorph force sensor. In addition, the liberation kinetics of crude oil from carbonate rocks were determined using an optical microscope-based liberation cell at both ambient and elevated temperatures. These measurements were complemented with thermogravimetric analysis (TGA) and standard macroscopic data such as water-contact angles and ζ-potentials. The effect of individual cations [calcium (Ca2+); magnesium (Mg2+)] and anions [sulfate (SO42−)] on wettability, adhesion, and oil liberation in carbonates was studied by using reservoir rock surfaces, reservoir crude oil, and different brines composed of a single type of salt at a fixed low salinity. Both deionized (DI) water and low-salinity brine composed of sufficient amounts of the three key ions (SO42−, Ca2+, and Mg2+) were also used as the baseline for these experiments. The results showed a significant increase in water wettability (or decrease in contact angles) with low-salinity brines compared with DI water, depending on the types of ions present in these brines. The presence of SO42− increased the water wettability the most, followed by the Ca2+ and Mg2+ ions. The ζ-potential data of carbonate rock minerals in DI water/brines showed similar trends on surface charges to correlate well with contact angles. Increasing the water wettability of brines on carbonate surfaces decreased the adhesion force between the oil and the rock in the corresponding brines. The adhesion forces on the carbonate surface were found to be in the following order: DI water > Mg2+ brine > Ca2+ brine > low-salinity brine with SO42−, Ca2+, and Mg2+ ions > SO42− brine. Such favorable changes in adhesion forces in turn led to more efficient crude-oil liberation from carbonates at a microscopic scale when exposed to different low-salinity brines than in DI water. The dynamic oil-liberation data from carbonates at both ambient and elevated temperatures demonstrated the significant advantage of low-salinity brine containing SO42− ions compared with DI water, but showed only its slight effectiveness over the low-salinity brine composed of three key ions. The TGA further confirmed the efficiency of both the low-salinity brines, composed of SO42− and the three key ions, to liberate more crude oil from carbonates. The findings from different microscopic- to macroscopic-scale measurements reported in this work clearly indicate the importance of both lower salinity and the major role of certain ions in the smartwater to effectively release crude oil from carbonates. It can also be concluded that low-salinity water containing sufficient amounts of three key ions can become a practical smartwater for waterflooding operations, considering the adverse effect of SO42− ions on the interactions at the crude-oil/water interface as well as the reservoir damage resulting from scaling and souring issues.
20
Hubert, Casey, Gerrit Voordouw, and Bernhard Mayer. "Elucidating microbial processes in nitrate- and sulfate-reducing systems using sulfur and oxygen isotope ratios: The example of oil reservoir souring control." Geochimica et Cosmochimica Acta 73, no. 13 (July 2009): 3864–79. http://dx.doi.org/10.1016/j.gca.2009.03.025.
Full text
21
Priha, Outi, Mari Nyyssönen, Malin Bomberg, Arja Laitila, Jaakko Simell, Anu Kapanen, and Riikka Juvonen. "Application of Denaturing High-Performance Liquid Chromatography for Monitoring Sulfate-Reducing Bacteria in Oil Fields." Applied and Environmental Microbiology 79, no. 17 (June 21, 2013): 5186–96. http://dx.doi.org/10.1128/aem.01015-13.
Full textAbstract:
ABSTRACTSulfate-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 × 101to 6 × 105dsrBgene 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 differentdsrBcompositions were detected at different geographical locations. The identifieddsrBgene sequences belonged to several phylogenetic groups, such asDesulfovibrio,Desulfococcus,Desulfomicrobium,Desulfobulbus,Desulfotignum,Desulfonatronovibrio, andDesulfonauticus. 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.
22
Marathe, R. V. "Technology Focus: Mature Fields and Well Revitalization (January 2021)." Journal of Petroleum Technology 73, no. 01 (January 1, 2021): 50. http://dx.doi.org/10.2118/0121-0050-jpt.
Full textAbstract:
Sustaining production from mature brownfields is becoming an uphill task in the current storm of pandemic plus economic crisis. In this year’s papers on mature fields and well revitalization, I have found operators focusing on making all-out efforts to improve their ongoing waterflood operations to extend the life of existing wells, which is preferred over drilling new infill wells. Waterflooding is the oldest method used for secondary recovery in oil fields because water is readily available and relatively inexpensive. Although the concept behind waterflooding is relatively simple and easy to implement, the reality is different, with many potential challenges such as water circulation because of poor reservoir conformance, induced matrix fracturing resulting in early water breakthrough, and reservoir souring, to mention just a few. The older the waterflood, the more susceptible it becomes to problems and challenges, and the most unavoidable challenge is managing increased amounts of produced water. A third of the papers studied this year focus on improved-/enhanced-oil-recovery techniques, and a majority of them focus on improving waterfloods through various techniques such as using classical analysis and data-driven technologies for redistributing injected water and integrating efforts with cross-disciplinary teams. Another area of focus is extending the life of existing wells. It is both a challenge and an opportunity. It is a challenge because operators must find a delicate balance between extending the life of an old well and jeopardizing the safety and integrity conditions in the field. It is an opportunity because it provides an attractive alternative for identifying and appraising possible behind-casing opportunities before plugging and abandonment. Several studies have been conducted to identify and appraise such opportunities.
23
Mahdi, Najwa H., Wijdan H. Al-Tamimi, and Mohammed S. Al-Jawad. "Determination of sulfide production by Reducing Bacteria isolated in the injection water of an Iraqi oil field." Journal of Petroleum Research and Studies 9, no. 3 (September 24, 2019): 23–35. http://dx.doi.org/10.52716/jprs.v9i3.312.
Full textAbstract:
Several oilfields undergo to reservoir souring, typically during water injection for secondary recovery, resulted in increasing concentrations of produced hydrogen sulfide (H2S). The main reason for this is the mechanism of generating hydrogen sulfide are the sulfate reducing bacteria (SRB). These bacteria use sulfate (So4) in the injection water as an electron acceptor and use organic acids which exist in formation water as a source of energy and carbon to generate H2S. In addition to that, the issues of health and safety, the existence of H2S decreases the worth of the produced hydrocarbon. The present study includes isolation and enumeration of sulfate reducing bacteria (SRB) from the injection and produced water of Ahdeb oilfield in Iraq by using Most Probable Number (MPN) technique. The Laboratory experimental work for production of sulfide with mix cultures of these bacteria was performed also with sodium lactate as an energy source. The experiments were carried out to determine the concentration of sulfide versus consumption of lactate in vitro. The concentration of sulfide is determined by using spectrophotometer method, whereas; the concentration of sodium lactate is calculated by using high performance liquid chromatography (HPLC) system. The experimental results demonstrates that the most numbers of bacteria in injection water are higher than the number in produced water samples. Whilst, the production of sulfide by SRB presents that inversely correlated to the concentration of sodium lactate. The growth experiments shows that the SRB concentration is increased in areas where the energy source and sulfate have high concentrations. Also, there is a direct relationship between SRB concentration and sulfide production. Therefore, the water injection from these bacteria must be treated before the injection to the reservoir to provide all the condition of SRB growth.
24
Gieg, Lisa M., Tom R. Jack, and Julia M. Foght. "Biological souring and mitigation in oil reservoirs." Applied Microbiology and Biotechnology 92, no. 2 (August 20, 2011): 263–82. http://dx.doi.org/10.1007/s00253-011-3542-6.
Full text
25
Bagnall, A. C., and J. B. Blanche. "The Use of Horizontal Drilling in International Exploration." Energy Exploration & Exploitation 10, no. 4-5 (September 1992): 230–45. http://dx.doi.org/10.1177/014459879201000404.
Full textAbstract:
Internationally (outside the USA) more than 300 horizontal wells were drilled in 1991. Horizontal well reservoir targets generally consist of a preponderance of clastic reservoirs over carbonates in the ratio of approximately 60% to 40%. The concept of using horizontal wells as an exploration tool can be defined as a means not only of proving new reserves in undrilled plays, but as a means of re-exploring previously drilled and poorly productive terrains. The Austin Chalk play in South Texas is the prime example of this concept in action. Exploration in this case can be defined as the adding of multiple orders of additional reserves value. International basin selection criteria are discussed which can optimise the chances of finding high value additional reserves in the initial stages of an exploration campaign by using horizontal drilling (with the important help of previous subsurface coverage or pilot drilling). These criteria include the presence of self sourcing carbonate reservoirs, the presence and predictability of regional fracturing, the mechanical properties of the reservoir rocks, the presence of significant original oil or gas-in-place and the reservoir depth criteria in which horizontal drilling technology is practicable and cost-effective.
26
Mueller, R. F., and P. H. Nielsen. "Characterization of thermophilic consortia from two souring oil reservoirs." Applied and environmental microbiology 62, no. 9 (1996): 3083–87. http://dx.doi.org/10.1128/aem.62.9.3083-3087.1996.
Full text
27
Fida, Tekle Tafese, Chuan Chen, Gloria Okpala, and Gerrit Voordouw. "Implications of Limited Thermophilicity of Nitrite Reduction for Control of Sulfide Production in Oil Reservoirs." Applied and Environmental Microbiology 82, no. 14 (May 6, 2016): 4190–99. http://dx.doi.org/10.1128/aem.00599-16.
Full textAbstract:
ABSTRACTNitrate reduction to nitrite in oil fields appears to be more thermophilic than the subsequent reduction of nitrite. Concentrated microbial consortia from oil fields reduced both nitrate and nitrite at 40 and 45°C but only nitrate at and above 50°C. The abundance of thenirSgene correlated with mesophilic nitrite reduction activity.ThaueraandPseudomonaswere the dominant mesophilic nitrate-reducing bacteria (mNRB), whereasPetrobacterandGeobacilluswere the dominant thermophilic NRB (tNRB) in these consortia. The mNRBThauerasp. strain TK001, isolated in this study, reduced nitrate and nitrite at 40 and 45°C but not at 50°C, whereas the tNRBPetrobactersp. strain TK002 andGeobacillussp. strain TK003 reduced nitrate to nitrite but did not reduce nitrite further from 50 to 70°C. Testing of 12 deposited pure cultures of tNRB with 4 electron donors indicated reduction of nitrate in 40 of 48 and reduction of nitrite in only 9 of 48 incubations. Nitrate is injected into high-temperature oil fields to prevent sulfide formation (souring) by sulfate-reducing bacteria (SRB), which are strongly inhibited by nitrite. Injection of cold seawater to produce oil creates mesothermic zones. Our results suggest that preventing the temperature of these zones from dropping below 50°C will limit the reduction of nitrite, allowing more effective souring control.IMPORTANCENitrite can accumulate at temperatures of 50 to 70°C, because nitrate reduction extends to higher temperatures than the subsequent reduction of nitrite. This is important for understanding the fundamentals of thermophilicity and for the control of souring in oil fields catalyzed by SRB, which are strongly inhibited by nitrite.
28
Kopsen, E., and T. Scholefield. "PROSPECTIVITY OF THE OTWAY SUPERGROUP IN THE CENTRAL AND WESTERN OTWAY BASIN." APPEA Journal 30, no. 1 (1990): 263. http://dx.doi.org/10.1071/aj89016.
Full textAbstract:
Recent hydrocarbon discoveries in the non-marine rift fill sequence of the Otway Basin at Windermere, Katnook and Ladbroke Grove have upgraded the importance of this relatively poorly known interval of the sedimentary column and provide hydrocarbon trapping models for future exploration. Using a seismic stratigraphic approach based on high resolution seismic data and the geological re-evaluation of many key early wells, a clearer pattern has emerged for the distribution of major reservoir and seal units.The best reservoirs occur in the Crayfish Group 'A', 'B' and 'D' units and the Windermere Member of the Lower Eumeralla Formation. One of the most critical elements in controlling the more prospective areas is the diagenetic characteristics of the main hydrocarbon objective units. Reservoir quality is significantly affected by the abundance or absence of volcanic detritus and depth of burial, and as a result, the most attractive reservoir is the Crayfish 'A' lying at depths shallower than 3000 m. Lateral fault seals and good vertical seals are present at various stratigraphic levels through the sequence for the development of effective traps in fault blocks and anticlines.The Casterton Group and the basal coal measures zone of the Lower Eumeralla Formation overlying the Windermere Member are identified as the most prospective oil sourcing units in the sequence. Secondary oil sourcing intervals occur within the Crayfish 'C' unit and at the top of the Lower Eumeralla Formation. A higher drilling success rate is now expected in the future with hydrocarbon fairways in the supergroup expected to comprise:Fault blocks and anticlines in the more basinal areas, e.g. the Katnook and Ladbroke Grove gas fields.The 'shoulders' of the main rift depocentres where fault traps will be most prevalent, e.g. the Kalangadoo CO2 discovery.Portions of the northern platform lying on migration pathways extending from the main graben (hydrocarbon kitchen) areas.
29
Zahmatkeshan, Fatemeh, Hojjat Mahdiyar, Hamed Aghaei, Mehdi Escrochi, and Hojjat Kazemi. "Investigating the souring mechanism in two giant carbonate oil reservoirs, southwestern Iran." Journal of Petroleum Science and Engineering 204 (September 2021): 108737. http://dx.doi.org/10.1016/j.petrol.2021.108737.
Full text
30
Jurelevicius, Diogo, Luana Ramos, Fernanda Abreu, Ulysses Lins, Maíra P. de Sousa, Vanessa V. C. M. dos Santos, Mônica Penna, and Lucy Seldin. "Long-term souring treatment using nitrate and biocides in high-temperature oil reservoirs." Fuel 288 (March 2021): 119731. http://dx.doi.org/10.1016/j.fuel.2020.119731.
Full text
31
Barakat, Stephanie, Bob Cook, Karine D'Amore, Alberto Diaz, and Andres Bracho. "An Australian first initiative to re-develop the first commercial onshore oilfield into a CO2 miscible-EOR project." APPEA Journal 59, no. 1 (2019): 179. http://dx.doi.org/10.1071/aj18095.
Full textAbstract:
The Moonie onshore oil field discovered in 1961, was the first commercial oil discovery in Australia. The field was purchased by Bridgeport Energy Limited (BEL) from Santos in late 2015. An Australian first initiative by BEL is to enhance oil production from the field using tertiary recovery CO2 miscible flood to maximise field oil recovery. The process involves an evaluation of well injection strategies for a miscible displacement process using reservoir simulation modelling. In addition, the project jointly addresses community concerns regarding the rise in greenhouse gas emissions by sourcing 60000–120000 tonnes/annum of CO2 from a nearby power station and/or an ethanol plant. Justified by laboratory experiments and reservoir compositional simulations, BEL’s project timeline to implement a CO2-enhanced oil recovery (EOR) pilot could start from 2020 followed by a 2–3-year full field oil production acceleration project if additional CO2 can be sourced. Based on incremental recovery and operational consideration, an injection well in the southern end of the field surrounded by six existing producers has been selected as a pilot flood. Positive indicative economics are achieved by the efficient displacement with CO2 of 8000 scf/bbl of incremental oil. Full field dynamic modelling predicts a further 8% oil recovery factor by injecting 60 Bcf of CO2 over five years, which could store in excess of three million tonnes of CO2. For the pilot, more than 90% of the injected CO2 will remain in the Precipice sandstone reservoir. However, the efficiency and viability of a CO2-EOR project is subject to successful implementation of the miscibility modelling, logistics and injection strategy and uncertainty quantification. To propel the project into the execution phase a fast-multiphase reservoir simulator has been implemented to complete a probabilistic range of results in optimal time.
32
Chen, Ching-I., Mark A. Reinsel, and Robert F. Mueller. "Kinetic investigation of microbial souring in porous media using microbial consortia from oil reservoirs." Biotechnology and Bioengineering 44, no. 3 (July 1994): 263–69. http://dx.doi.org/10.1002/bit.260440302.
Full text
33
Hubert, Casey, and Gerrit Voordouw. "Oil Field Souring Control by Nitrate-Reducing Sulfurospirillum spp. That Outcompete Sulfate-Reducing Bacteria for Organic Electron Donors." Applied and Environmental Microbiology 73, no. 8 (February 16, 2007): 2644–52. http://dx.doi.org/10.1128/aem.02332-06.
Full textAbstract:
ABSTRACT Nitrate injection into oil reservoirs can prevent and remediate souring, the production of hydrogen sulfide by sulfate-reducing bacteria (SRB). Nitrate stimulates nitrate-reducing, sulfide-oxidizing bacteria (NR-SOB) and heterotrophic nitrate-reducing bacteria (hNRB) that compete with SRB for degradable oil organics. Up-flow, packed-bed bioreactors inoculated with water produced from an oil field and injected with lactate, sulfate, and nitrate served as sources for isolating several NRB, including Sulfurospirillum and Thauera spp. The former coupled reduction of nitrate to nitrite and ammonia with oxidation of either lactate (hNRB activity) or sulfide (NR-SOB activity). Souring control in a bioreactor receiving 12.5 mM lactate and 6, 2, 0.75, or 0.013 mM sulfate always required injection of 10 mM nitrate, irrespective of the sulfate concentration. Community analysis revealed that at all but the lowest sulfate concentration (0.013 mM), significant SRB were present. At 0.013 mM sulfate, direct hNRB-mediated oxidation of lactate by nitrate appeared to be the dominant mechanism. The absence of significant SRB indicated that sulfur cycling does not occur at such low sulfate concentrations. The metabolically versatile Sulfurospirillum spp. were dominant when nitrate was present in the bioreactor. Analysis of cocultures of Desulfovibrio sp. strain Lac3, Lac6, or Lac15 and Sulfurospirillum sp. strain KW indicated its hNRB activity and ability to produce inhibitory concentrations of nitrite to be key factors for it to successfully outcompete oil field SRB.
34
Nemati, M., G. E. Jenneman, and G. Voordouw. "Impact of Nitrate-Mediated Microbial Control of Souring in Oil Reservoirs on the Extent of Corrosion." Biotechnology Progress 17, no. 5 (October 5, 2001): 852–59. http://dx.doi.org/10.1021/bp010084v.
Full text
35
Gu, Ji-Dong. "Pattern of Research Trend Emerging from Small Data." Applied Environmental Biotechnology 5, no. 2 (2020): 1–2. http://dx.doi.org/10.26789/aeb.2020.02.001.
Full textAbstract:
Identification and prediction of the current ongoing and future research trends are critically important to research scientists to be on track of the significantly important topics and also ahead of the others if all possible. Such information can be extrapolated by mining the existing data available from different databases to delineate the important research topics that many are working on and also the emerging ones that attract attention. Because of the readily availability of online published articles in Open Access mode and instant information in real time on viewing number, read and citations, a simple summary of the papers published in this journal over the past 4 years indicated clearly the most viewed research articles and topics are in line with the main stream information available, namely novel dehalogenase, thermophilic organisms and biotechnological application in bioleaching, souring inhibition in oil reservoirs, and the current public interest on plastics. This information can be used in refining one’s specific research to target for popularity and visibility.
36
Kempton, Richard, Se Gong, John Kennard, Herbert Volk, David Mills, Peter Eadington, and Keyu Liu. "Detection of palaeo-oil columns in the offshore northern Perth Basin: extension of the effective Permo-Triassic charge system." APPEA Journal 51, no. 1 (2011): 377. http://dx.doi.org/10.1071/aj10024.
Full textAbstract:
A widespread charge system for oil accumulation in the offshore northern Perth Basin, Western Australia, is revealed by specialised fluid inclusion technologies. Palaeo-oil columns are detected in about three of four exploration wells, including those at the Cliff Head, Dunsborough, Frankland and Perseverance fields, and in dry wells at Flying Foam–1, Hadda–1, Houtman–1, Leander Reef–1, Lilac–1, Livet–1, Mentelle–1 and Morangie–1. A high incidence of palaeo-oil charge into Permian reservoirs below the Kockatea Shale confirms that the conventional oil shows are, in part, residues of palaeo-oil. Oil migration is suggested at Vindara–1 and Leander Reef–1 and is below detection limits in Batavia–1, Charon–1, Fiddich–1 Geelvink–1A, Gun Island–1 and South Turtle Dove–1B, Twin Lions–1 and Wittecarra–1. New geochemical data from fluid inclusion oil at Hadda–1 shows evidence for a contribution from the Hovea Member of the Kockatea Shale, including: high wax content; low pristane/phytane ratio; high abundance of extended tricyclic terpanes; and, the highly diagnostic C33 n-alkylcyclohexane biomarker. This key component of the petroleum system acted as both source and seal, and extends further offshore than previously realised. Possible co-sourcing from terrestrial organic matter is indicated by high abundances of C29 steranes and diasteranes, C19 tricyclic, and C24 tetracyclic terpanes, which may be sourced from Permian rocks. The high incidence of palaeo-oil and residual columns suggests that trap integrity is likely to be an important preservation risk, with elements of gas displacement. Screening of prospects for structural and hydrocarbon charge characteristics, which are favourable for retention of oil, is key in future exploration of the offshore northern Perth Basin.
37
Volk, H., S. C. George, C. J. Boreham, and R. H. Kempton. "GEOCHEMICAL AND COMPOUND SPECIFIC CARBON ISOTOPIC CHARACTERISATION OF FLUID INCLUSION OILS FROM THE OFFSHORE PERTH BASIN,WESTERN AUSTRALIA: IMPLICATIONS FOR RECOGNISING EFFECTIVE OIL SOURCE ROCKS." APPEA Journal 44, no. 1 (2004): 223. http://dx.doi.org/10.1071/aj03008.
Full textAbstract:
The molecular composition of fluid inclusion (FI) oils from Leander Reef–1, Houtman–1 and Gage Roads–2 provide evidence of the origin of palaeo-oil accumulations in the offshore Perth Basin. These data are complemented by compound specific isotope (CSI) profiles of n-alkanes for the Leander Reef–1 and Houtman–1 samples, which were acquired on purified n-alkane fractions gained by micro-fractionation of lean FI oil samples, showing the technical feasibility of this technique. The Leander Reef–1 FI oil from the top Carynginia Formation shares many biomarker similarities with oils from the Dongara and Yardarino oilfields, which have been correlated with the Early Triassic Kockatea Shale. The heavier isotopic values for the C15-C25 n-alkanes in the Leander Reef–1 FI oil indicate, however, that it is a mixture, and suggest that the main part of this oil (~90%) was sourced from the more terrestrial and isotopically heavier Early Permian Carynginia Formation or Irwin River Coal Measures. This insight would have been precluded when looking at molecular evidence alone. The Houtman–1 FI oil from the top Cattamarra Coal Measures (Middle Jurassic) was sourced from a clay-rich, low sulphur source rock with a significant input of terrestrial organic matter, deposited under oxic to sub-oxic conditions. Biomarkers suggest sourcing from a more prokaryotic-dominated facies than for the other FI oils, possibly a saline lagoon. The Houtman–1 FI oil δ13C CSI n-alkane data are similar to those acquired on the Walyering–2 oil. Possible lacustrine sources may exist in the Early Jurassic Eneabba Formation and are present in the Late Jurassic Yarragadee Formation. The low maturity Gage Roads–2 FI oil from the Carnac Formation (Early Cretaceous) was derived from a strongly terrestrial, non-marine source rock containing a high proportion of Araucariacean-type conifer organic matter. It has some geochemical differences to the presently reservoired oil in Gage Roads–1, and was probably sourced from the Early Cretaceous Parmelia Formation.
38
JPT staff, _. "E&P Notes (July 2021)." Journal of Petroleum Technology 73, no. 07 (July 1, 2021): 13–17. http://dx.doi.org/10.2118/0721-0013-jpt.
Full textAbstract:
Maha Appraisal Hits Gas for Eni in Indonesia Eni encountered natural-gas-bearing sands with its Maha 2 well in the West Ganal Block offshore Indonesia. Drilled to a depth of 2970 m in 1115 m water depth, the well encountered 43 m of gas-bearing net sands in levels of Pliocene Age, according to the operator. A production test, which was limited by surface facilities, recorded a gas deliverability of the reservoir flowing at 34 MMscf/D. The opera-tor collected data and samples during the test, to study in preparation of a field development plan for the Maha field. Two additional appraisal wells are planned for the discovery. Eni, along with partners Neptune West Ganal BV and P.T. Pertamina Hulu West Ganal, expect the field to be developed subsea and tied back to the nearby Jangkrik floating production unit (FPU), about 16 km to the northwest. Eni has been operating off Indonesia since 2001. Its current equity production in the region is around 80,000 BOE/D. Shell Sells Out of Philippines Gas Field Royal Dutch Shell has agreed to sell its stake in the Malampaya offshore gas field in the Philippines for $460 million. The major sold its 45% stake in Service Contract 38 (SC38), a deepwater license which includes the producing gas field, to a subsidiary of the Udenna Group, which already holds a 45% stake in the project. The divestment is part of the company’s strategy to narrow its oil and gas operations. The base consideration for the sale is $380 million, with additional payments of up to $80 million in 2022 and 2024 contingent on asset performance and commodity prices, according to Shell. The deal is due to complete by the end of 2021. The Malampaya gas field, discovered in 1991, currently supplies fuel to power plants that deliver about a fifth of the country’s electricity requirements, based on energy ministry data. Equinor Green Lights First Phase of Bacalhau Development Off Brazil Equinor, along with partners ExxonMobil, Petrogal Brasil, and Pré-Sal Petróleo SA, will move forward with a planned $8-billion Phase 1 development of the Bacalhau field in the Brazilian pre-salt Santos area. The Bacalhau field is situated across two licenses, BM-S-8 and Norte de Carcará. The target resource is a high-quality carbonate reservoir containing light oil. The development will consist of 19 subsea wells tied back to a floating production, storage, and offloading unit (FPSO) located at the field. The vessel will be one of the largest FPSOs in Brazil with a production capacity of 220,000 B/D of oil and 2 million bbl of storage capacity. The stabilized oil will be offloaded to shuttle tankers and the gas from Phase 1 will be re-injected in the reservoir. The FPSO contractor will operate the FPSO for the first year. Thereafter, Equinor plans to operate the facilities until the end of the license period. The development plan was approved by the Brazilian National Agency of Petroleum, Natural Gas, and Biofuels (ANP) in March 2021. First oil from the field is slated for 2024. Wintershall Strikes Gas at Dvalin North An exploration well drilled by Wintershall on its Dvalin North prospect in the Norwegian Sea has encountered a significant gas reservoir. The discovery at Dvalin North is estimated to hold to hold 33–70 million BOE and is just 12 km north of the company’s operated Dvalin field and 65 km north of the operated Maria field. The well also encountered hydrocarbons in two shallower secondary targets, with a combined resource estimate of 38–87 million BOE, making the potential for the field in excess of 150 million BOE. The well, drilled by the Deepsea Aberdeen rig, encountered gas, condensate, and oil columns of 33 m and 114 m in the Cretaceous Lysing and Lange formations, respectively. In the primary target in the Garn Formation, the well found a gas column of 85 m. The license partners, including Petoro and Sval Energi, are evaluating development options for the discovery, which could include a tieback to the Dvalin field. Third Odfjell Rig Tapped by Equinor Odfjell has been awarded a three-well, $40-million drilling contract for its semisubmersible drilling unit Deepsea Stavanger by Equinor. The rig will join sister units Deepsea Atlantic and Deepsea Aberdeen under contract with the Norwegian operator. The rig is scheduled to start drilling the first of three planned exploration wells in the North Sea in February 2022. The wells are expected to take about 4 months to complete. The contract includes continuing options after the initial phase. South Africa Shale Tests Encounter Gas at Karoo Pockets of shale gas were encountered during test drilling in the semi-desert Karoo region of South Africa, according to the nation’s energy ministry. A total of 34 gas samples had been bottled and taken to laboratories after the government’s Council for Geosciences set out to drill a 3500-m stratigraphic hole in the Karoo to establish and test the occurrence of shale gas. “The first pocket of gas was intercepted at 1734 m with a further substantial amount intercepted at 2467 m spanning a depth of 55 m,” said Gwede Mantashe, South African energy minister, during his budget vote in parliament on 18 May. In 2017, geologists at the University of Johannesburg and three other institutions estimated the gas resource in the Karoo was probably 13 Tcf. Earlier, the US Energy and Information Administration estimated the Karoo Basin’s technically recoverable shale-gas resource at 390 Tcf, then making it the eighth largest in the world and second largest in Africa behind Algeria. Seadrill Venture Nets New Drilling Contract Seadrill’s Sonadrill Holding Ltd., the 50/50 joint venture with an affiliate of Sonangol, has secured a 12-well contract with one option for nine wells and 11 one-well options in Angola for drillship Sonangol Quenguela. The $131-million contract before options is inclusive of mobilization revenue and additional services with commencement expected in early 2022 and running through mid-2023. The contract is contingent on National Concessionaire approval. Sonangol Quenguela is the second of two Sonangol-owned drillships to be bareboat-chartered into Sonadrill. The drillship is a seventh-generation, DP3, dual activity, e-smart ultradeepwater drillship delivered in 2019, capable of drilling up to 40,000-ft wells. A further two Seadrill-owned units are expected to be bareboat-chartered into Sonadrill. Seadrill will manage and operate the four units on behalf of Sonadrill. Shell Makes US Gulf Discovery at Leopard An exploration well at the Shell-led Leopard prospect in the deepwater US Gulf of Mexico encountered more than 600 ft net oil pay at multiple levels. Leopard is in Alaminos Canyon Block 691, approximately 20 miles east of the Whale discovery, 20 miles south of the recently appraised Blacktip discovery, and 33 miles from the Perdido spar host facility. Evaluation is ongoing to further define development options. According to Shell, Leopard is an opportunity to increase production in the Perdido Corridor, where its Great White, Silvertip, and Tobago fields are already producing. Meanwhile, the Whale discovery, also in the Perdido Corridor, is progressing toward a final investment decision in 2021. Shell operates Leopard with a 50% working interest. Partner Chevron holds the remaining 50% stake. Shell Could Leave Tunisia in 2022 Shell informed Tunisian authorities in May it will hand back upstream concessions and leave the country next year as it turns its focus to renewable energy, according to a Reuters report sourcing a senior official in the country’s energy ministry. The license in question is the Miskar concession in the southern city of Gabes. The operator has also requested the early hand-back of the Asdrubal permit, which expires in 2035. Recent reports suggest the operator may be looking for the Tunisian government to extend its permit on the field under more favorable terms ahead of its planned departure.
39
Shi, Xiang, Daiane A. F. Oliveira, Lea Holsten, Katrin Steinhauer, and Julia R. de Rezende. "Long-Term Biocide Efficacy and Its Effect on a Souring Microbial Community." Applied and Environmental Microbiology 87, no. 17 (August 11, 2021). http://dx.doi.org/10.1128/aem.00842-21.
Full textAbstract:
Reservoir souring is a problem for the oil and gas industry, because H 2 S corrodes the steel infrastructure, downgrades oil quality, and poses substantial risks to field personnel and the environment. Biocides have been widely applied to remedy souring, but the long-term performance of biocide treatments is hard to predict or to optimize due to limited understanding of the microbial ecology affected by biocide treatment.
40
Wang, Yanqing, Xiang Li, and Jun Lu. "Physicochemical Modeling of Barium and Sulfate Transport in Porous Media and Its Application in Seawater-Breakthrough Monitoring." SPE Journal, May 1, 2021, 1–22. http://dx.doi.org/10.2118/205482-pa.
Full textAbstract:
Summary Seawater injection is widely used to improve oil recovery in offshore oil reservoirs. However, injecting seawater into reservoirs can cause many flow-assurance issues, such as scaling and reservoir souring, which are strongly related to the percentage of seawater breakthrough. Thermodynamic models have been developed to evaluate the effects of barite deposition on oil production, but the reservoir stripping effect has not been fully considered. In this study, a new model that incorporates both chemical reaction (barium and sulfate reaction) and physical reactions (ion adsorption/desorption) is developed to investigate the in-situbarite-deposition process. To the best of our knowledge, for the first time, ion adsorption/desorption is integrated by coupling the adsorption/desorption isotherm to the reservoir simulator. The barium and sulfate chemical reaction is modeled by incorporating the solubility product constant into the model. The model accuracy is verified through convergence rate tests and comparison with the coreflood experimental results. The simulation results of both barium and sulfate concentration profiles are greatly improved by integrating the ion adsorption/desorption process. The new physicochemical model is further used to investigate barite deposition under various scenarios. Simulation results indicate that most barite deposits are in the deep reservoir for the areal model. Barite that deposits in the reservoir before seawater breakthrough accounts for 45% of total barite deposition and the barite deposited during the seawater-breakthrough period makes up 54%, while the deposition during the tailing period, where the seawater fraction is larger than 95%, is negligible. For a homogeneous reservoir, the barite-deposition period at the near-wellbore area of the producer is between 30% and 65% of the seawater-breakthrough percentage, and heterogeneity leads to a broader deposition period. For vertical heterogeneous reservoirs, a considerable amount of barite forms in the wellbore, which accounts for 17% of total barite deposition. Based on the accurate simulation of barium and sulfate transport in the reservoir, barium and sulfate concentration profiles can be used to determine the seawater-breakthrough percentage and help optimize production operations that aim to mitigate flow assuranceissues.
41
Dolfing, Jan, and Casey R. J. Hubert. "Using Thermodynamics to Predict the Outcomes of Nitrate-Based Oil Reservoir Souring Control Interventions." Frontiers in Microbiology 8 (December 19, 2017). http://dx.doi.org/10.3389/fmicb.2017.02575.
Full text
42
Lahme, Sven, Dennis Enning, Cameron M. Callbeck, Demelza Menendez Vega, Thomas P. Curtis, Ian M. Head, and Casey R. J. Hubert. "Metabolites of an Oil Field Sulfide-Oxidizing, Nitrate-ReducingSulfurimonassp. Cause Severe Corrosion." Applied and Environmental Microbiology 85, no. 3 (November 16, 2018). http://dx.doi.org/10.1128/aem.01891-18.
Full textAbstract:
ABSTRACTOil reservoir souring and associated material integrity challenges are of great concern to the petroleum industry. The bioengineering strategy of nitrate injection has proven successful for controlling souring in some cases, but recent reports indicate increased corrosion in nitrate-treated produced water reinjection facilities. Sulfide-oxidizing, nitrate-reducing bacteria (soNRB) have been suggested to be the cause of such corrosion. Using the model soNRBSulfurimonassp. strain CVO obtained from an oil field, we conducted a detailed analysis of soNRB-induced corrosion at initial nitrate-to-sulfide (N/S) ratios relevant to oil field operations. The activity of strain CVO caused severe corrosion rates of up to 0.27 millimeters per year (mm y−1) and up to 60-μm-deep pitting within only 9 days. The highest corrosion during the growth of strain CVO was associated with the production of zero-valent sulfur during sulfide oxidation and the accumulation of nitrite, when initial N/S ratios were high. Abiotic corrosion tests with individual metabolites confirmed biogenic zero-valent sulfur and nitrite as the main causes of corrosion under the experimental conditions. Mackinawite (FeS) deposited on carbon steel surfaces accelerated abiotic reduction of both sulfur and nitrite, exacerbating corrosion. Based on these results, a conceptual model for nitrate-mediated corrosion by soNRB is proposed.IMPORTANCEAmbiguous reports of corrosion problems associated with the injection of nitrate for souring control necessitate a deeper understanding of this frequently applied bioengineering strategy. Sulfide-oxidizing, nitrate-reducing bacteria have been proposed as key culprits, despite the underlying microbial corrosion mechanisms remaining insufficiently understood. This study provides a comprehensive characterization of how individual metabolic intermediates of the microbial nitrogen and sulfur cycles can impact the integrity of carbon steel infrastructure. The results help explain the dramatic increases seen at times in corrosion rates observed during nitrate injection in field and laboratory trials and point to strategies for reducing adverse integrity-related side effects of nitrate-based souring mitigation.
43
Chen, Chuan, Yin Shen, Dongshan An, and Gerrit Voordouw. "Use of Acetate, Propionate, and Butyrate for Reduction of Nitrate and Sulfate and Methanogenesis in Microcosms and Bioreactors Simulating an Oil Reservoir." Applied and Environmental Microbiology 83, no. 7 (January 27, 2017). http://dx.doi.org/10.1128/aem.02983-16.
Full textAbstract:
ABSTRACT Acetate, propionate, and butyrate (volatile fatty acids [VFA]) occur in oil field waters and are frequently used for microbial growth of oil field consortia. We determined the kinetics of use of these VFA components (3 mM each) by an anaerobic oil field consortium in microcosms containing 2 mM sulfate and 0, 4, 6, 8, or 13 mM nitrate. Nitrate was reduced first, with a preference for acetate and propionate. Sulfate reduction then proceeded with propionate (but not butyrate) as the electron donor, whereas the fermentation of butyrate (but not propionate) was associated with methanogenesis. Microbial community analyses indicated that Paracoccus and Thauera (Paracoccus-Thauera), Desulfobulbus, and Syntrophomonas-Methanobacterium were the dominant taxa whose members catalyzed these three processes. Most-probable-number assays showed the presence of up to 107/ml of propionate-oxidizing sulfate-reducing bacteria (SRB) in waters from the Medicine Hat Glauconitic C field. Bioreactors with the same concentrations of sulfate and VFA responded similarly to increasing concentrations of injected nitrate as observed in the microcosms: sulfide formation was prevented by adding approximately 80% of the nitrate dose needed to completely oxidize VFA to CO2 in both. Thus, this work has demonstrated that simple time-dependent observations of the use of acetate, propionate, and butyrate for nitrate reduction, sulfate reduction, and methanogenesis in microcosms are a good proxy for these processes in bioreactors, monitoring of which is more complex. IMPORTANCE Oil field volatile fatty acids acetate, propionate, and butyrate were specifically used for nitrate reduction, sulfate reduction, and methanogenic fermentation. Time-dependent analyses of microcosms served as a good proxy for these processes in a bioreactor, mimicking a sulfide-producing (souring) oil reservoir: 80% of the nitrate dose required to oxidize volatile fatty acids to CO2 was needed to prevent souring in both. Our data also suggest that propionate is a good substrate to enumerate oil field SRB.
44
Dutta, Avishek, Ben Smith, Thomas Goldman, Leanne Walker, Matthew Streets, Bob Eden, Reinhard Dirmeier, and Jeff S. Bowman. "Understanding Microbial Community Dynamics in Up-Flow Bioreactors to Improve Mitigation Strategies for Oil Souring." Frontiers in Microbiology 11 (December 3, 2020). http://dx.doi.org/10.3389/fmicb.2020.585943.
Full textAbstract:
Oil souring occurs when H2S is generated in oil reservoirs. This not only leads to operational risks and health hazards but also increases the cost of refining crude oil. Sulfate-reducing microorganisms are considered to be the main source of the H2S that leads to oil souring. Substrate competition between nitrate-reducing and sulfate-reducing microorganisms makes biosouring mitigation via the addition of nitrate salts a viable strategy. This study explores the shift in microbial community across different phases of biosouring and mitigation. Anaerobic sand-filled columns wetted with seawater and/or oil were used to initiate the processes of sulfidogenesis, followed by mitigation with nitrate, rebound sulfidogenesis, and rebound control phases (via nitrate and low salinity treatment). Shifts in microbial community structure and function were observed across different phases of seawater and oil setups. Marine bacterial taxa (Marinobacter, Marinobacterium, Thalassolituus, Alteromonas, and Cycloclasticus) were found to be the initial responders to the application of nitrate during mitigation of sulfidogenesis in both seawater- and oil- wetted columns. Autotrophic groups (Sulfurimonas and Desulfatibacillum) were found to be higher in seawater-wetted columns compared to oil-wetted columns, suggesting the potential for autotrophic volatile fatty acid (VFA) production in oil-field aquifers when seawater is introduced. Results indicate that fermentative (such as Bacteroidetes) and oil-degrading bacteria (such as Desulfobacula toluolica) play an important role in generating electron donors in the system, which may sustain biosouring and nitrate reduction. Persistence of certain microorganisms (Desulfobacula) across different phases was observed, which may be due to a shift in metabolic lifestyle of the microorganisms across phases, or zonation based on nutrient availability in the columns. Overall results suggest mitigation strategies for biosouring can be improved by monitoring VFA concentrations and microbial community dynamics in the oil reservoirs during secondary recovery of oil.
45
Booker, Anne E., Mikayla A. Borton, Rebecca A. Daly, Susan A. Welch, Carrie D. Nicora, David W. Hoyt, Travis Wilson, et al. "Sulfide Generation by DominantHalanaerobiumMicroorganisms in Hydraulically Fractured Shales." mSphere 2, no. 4 (July 5, 2017). http://dx.doi.org/10.1128/mspheredirect.00257-17.
Full textAbstract:
ABSTRACTHydraulic fracturing of black shale formations has greatly increased United States oil and natural gas recovery. However, the accumulation of biomass in subsurface reservoirs and pipelines is detrimental because of possible well souring, microbially induced corrosion, and pore clogging. Temporal sampling of produced fluids from a well in the Utica Shale revealed the dominance ofHalanaerobiumstrains within thein situmicrobial community and the potential for these microorganisms to catalyze thiosulfate-dependent sulfidogenesis. From these field data, we investigated biogenic sulfide production catalyzed by aHalanaerobiumstrain isolated from the produced fluids using proteogenomics and laboratory growth experiments. Analysis ofHalanaerobiumisolate genomes and reconstructed genomes from metagenomic data sets revealed the conserved presence of rhodanese-like proteins and anaerobic sulfite reductase complexes capable of converting thiosulfate to sulfide. Shotgun proteomics measurements using aHalanaerobiumisolate verified that these proteins were more abundant when thiosulfate was present in the growth medium, and culture-based assays identified thiosulfate-dependent sulfide production by the same isolate. Increased production of sulfide and organic acids during the stationary growth phase suggests that fermentativeHalanaerobiumuses thiosulfate to remove excess reductant. These findings emphasize the potential detrimental effects that could arise from thiosulfate-reducing microorganisms in hydraulically fractured shales, which are undetected by current industry-wide corrosion diagnostics.IMPORTANCEAlthough thousands of wells in deep shale formations across the United States have been hydraulically fractured for oil and gas recovery, the impact of microbial metabolism within these environments is poorly understood. Our research demonstrates that dominant microbial populations in these subsurface ecosystems contain the conserved capacity for the reduction of thiosulfate to sulfide and that this process is likely occurring in the environment. Sulfide generation (also known as “souring”) is considered deleterious in the oil and gas industry because of both toxicity issues and impacts on corrosion of the subsurface infrastructure. Critically, the capacity for sulfide generation via reduction of sulfate was not detected in our data sets. Given that current industry wellhead tests for sulfidogenesis target canonical sulfate-reducing microorganisms, these data suggest that new approaches to the detection of sulfide-producing microorganisms may be necessary.