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Relevant bibliographies by topics / Oil reservoir souring

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Academic literature on the topic 'Oil reservoir souring'

Author: Grafiati

Published: 4 June 2021

Last updated: 1 February 2022

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Journal articles on the topic "Oil reservoir souring"

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.

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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.

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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.

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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.

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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.

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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.

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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.

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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.

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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.

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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.

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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.

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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.

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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.

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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.

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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

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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.

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Dissertations / Theses on the topic "Oil reservoir souring"

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Walsh, Sally. "The isolation and starvation-survival of thermophilic sulphate-reducing bacteria." Thesis, University of Exeter, 1995. http://ethos.bl.uk/OrderDetails.do?uin=uk.bl.ethos.307293.

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Marsland, Simon David. "Non-oxidative dissolution of iron sulphide minerals : of relevance to inorganic chemical souring of oil reservoirs." Thesis, Imperial College London, 1992. http://ethos.bl.uk/OrderDetails.do?uin=uk.bl.ethos.326670.

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Book chapters on the topic "Oil reservoir souring"

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Streets, Matthew, and Leanne Walker. "Microbial Reservoir Souring." In Microbial Bioinformatics in the Oil and Gas Industry, 207–25. Boca Raton: CRC Press, 2021. http://dx.doi.org/10.1201/9781003023395-10.

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Fischer, David, Monica Canalizo-Hernandez, and Amit Kumar. "Effects of Reservoir Souring on Materials Performance." In Microbiologically Influenced Corrosion in the Upstream Oil and Gas Industry, 111–37. Boca Raton : Taylor & Francis, CRC Press, 2017.: CRC Press, 2017. http://dx.doi.org/10.1201/9781315157818-6.

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Hubert, C. "Microbial Ecology of Oil Reservoir Souring and its Control by Nitrate Injection." In Handbook of Hydrocarbon and Lipid Microbiology, 2753–66. Berlin, Heidelberg: Springer Berlin Heidelberg, 2010. http://dx.doi.org/10.1007/978-3-540-77587-4_204.

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Carlson, Hans K., and Casey R. J. Hubert. "Mechanisms and Monitoring of Oil Reservoir Souring Control by Nitrate or Perchlorate Injection." In Microbial Communities Utilizing Hydrocarbons and Lipids: Members, Metagenomics and Ecophysiology, 225–49. Cham: Springer International Publishing, 2019. http://dx.doi.org/10.1007/978-3-030-14785-3_17.

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Carlson, Hans K., and Casey R. J. Hubert. "Mechanisms and Monitoring of Oil Reservoir Souring Control by Nitrate or Perchlorate Injection." In Microbial Communities Utilizing Hydrocarbons and Lipids: Members, Metagenomics and Ecophysiology, 1–25. Cham: Springer International Publishing, 2019. http://dx.doi.org/10.1007/978-3-319-60063-5_17-1.

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Xue, Yuan, Gerrit Voordouw, and Lisa M. Gieg. "Laboratory Protocols for Investigating Microbial Souring and Potential Treatments in Crude Oil Reservoirs." In Springer Protocols Handbooks, 183–210. Berlin, Heidelberg: Springer Berlin Heidelberg, 2015. http://dx.doi.org/10.1007/8623_2015_115.

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Westlake, D. W. S. "Ch. R-16 Microbial Ecology of Corrosion and Reservoir Souring." In microbial enhancement of oil recovery—recent advances, Proceedings of the 1990 international conference on microbial enhancement of oil recovery, 257–63. Elsevier, 1991. http://dx.doi.org/10.1016/s0376-7361(09)70164-5.

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Conference papers on the topic "Oil reservoir souring"

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Evans, Paul. "Reservoir Souring Modelling, Prediction and Mitigation." In ASME 2008 27th International Conference on Offshore Mechanics and Arctic Engineering. ASMEDC, 2008. http://dx.doi.org/10.1115/omae2008-57085.

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The prediction of reservoir souring due to the activity of sulphate-reducing bacteria (SRB) during water injection is an important consideration in material selection for wells and production facilities. A number of reservoir souring models have been developed in the past 16 years or so, with the objective of predicting the timing and magnitude of H2S production. The results of the reservoir souring models are dependent on a number of reservoir geometry, geochemical, microbiological and reservoir geology parameters. For example, the SRB activity is dependent on the availability of essential nutrients such as sulphate and dissolved hydrocarbons in the injection and formation waters. Environmental parameters such as temperature and pressure control in which parts of the reservoir SRB can be active. Water flow path and extent of water breakthrough has a major impact on H2S production. Very low reservoir permeabilities will restrict the movement of SRB into the rock matrix and certain minerals have the ability to scavenge H2S within the reservoir. All of these parameters must be accounted for in a reservoir souring simulation, and this requires the cooperation of reservoir engineers, geologists, production chemists and facilities engineers. Several techniques have been employed in the oil industry to try to control the generation of H2S within the reservoir. These include the application of biocides to control SRB activity, the injection of nitrate to stimulate other bacterial populations to out compete SRB for available food sources and the use of sulphate removal technologies to minimize sulphide production.

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Zhu, Feibai, Cor Kuijvenhoven, Noorazlenawati Bt Borhan, Sara-Jane Dickson, and Bart Lomans. "Learnings from Reservoir Souring Assessment on an Offshore Malaysian Field." In SPE EOR Conference at Oil and Gas West Asia. Society of Petroleum Engineers, 2016. http://dx.doi.org/10.2118/179787-ms.

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Coombe, D., T. Jack, G. Voodouw, F. Zhang, B. Clay, and K. Miner. "Simulation of Bacterial Souring Control in an Alberta Heavy-Oil Reservoir." In Canadian International Petroleum Conference. Petroleum Society of Canada, 2009. http://dx.doi.org/10.2118/2009-050.

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Ashkanani, Fatma, Moudi Al-Ajmi, and Hom Chetri. "Management of Reservoir Souring While Water Flooding of Major Reservoirs in North Kuwait: Threat, Tracking & Tackling." In SPE Kuwait Oil and Gas Show and Conference. Society of Petroleum Engineers, 2015. http://dx.doi.org/10.2118/175210-ms.

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Al-Rasheedi, Shamaa, Christopher Kalli, David Thrasher, and Salman Al-Qabandi. "Prediction and Evaluation of the Impact of Reservoir Souring in North Kuwait, A Case Study." In Middle East Oil Show and Conference. Society of Petroleum Engineers, 1999. http://dx.doi.org/10.2118/53164-ms.

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Alkhalifah, Hawraa A. N. A. M., Tasneem Al-Twaitan, and Hom Chetri. "Reservoir Souring Tracking; Evaluation & Management to De-Eisk the Development Activities in a Giant Carbonate Reservoir in North Kuwait." In SPE Kuwait Oil & Gas Show and Conference. Society of Petroleum Engineers, 2019. http://dx.doi.org/10.2118/198059-ms.

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Jahanbani Veshareh, M., and H. M. Nick. "Learnings from Reservoir Souring Treatment by Nitrate Injection in the Halfdan Oil Field." In 80th EAGE Conference and Exhibition 2018. Netherlands: EAGE Publications BV, 2018. http://dx.doi.org/10.3997/2214-4609.201801357.

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Ligthelm, D. J., R. B. de Boer, J. F. Brint, and W. M. Schulte. "Reservoir Souring: An Analytical Model for H2S Generation and Transportation in an Oil Reservoir Owing to Bacterial Activity." In Offshore Europe. Society of Petroleum Engineers, 1991. http://dx.doi.org/10.2118/23141-ms.

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Shi, Xiang, Julia R. de Rezende, and Kenneth Sorbie. "Microbial Ecology Metrics to Assess the Effect of Biocide on Souring Control and Improve Souring Modelling." In SPE International Oilfield Corrosion Conference and Exhibition. SPE, 2021. http://dx.doi.org/10.2118/205037-ms.

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Abstract Reservoir souring is a long-standing issue for the oil and gas industry caused by sulfate-reducing microorganisms (SRM) producing H2S from sulfate ions. In this work, we investigated the connections between the development of souring and the change in three key microbial ecology metrics: the abundance, alpha diversity and community structure of a souring microbiota under the biocide treatment of 100 ppm glutaraldehyde (henceforth referred to as GA). These are studied in sand-packed flow-through bioreactors during and after the biocide treatment using cutting-edge DNA assays. Our study suggests that the rebound of microbial sulfide production after the 100 ppm GA treatment is closely associated with the recovery in microbial abundance and microbial alpha diversity. The study also shows that 100 ppm GA treatment may lead to a measurable shift in the SRM community structure. By comparing the effluent microbial community with the sand microbial community, the study suggests that the change in alpha diversity of the produced water microbial community might be an early warning for the sulfide breakthrough due to souring recurrence in practice. This work explores the relationship between souring and the underlining microbial community behaviours in response to the 100 ppm GA treatment and, to characterise these changes, we propose measurable metrics. A conceptual model is also proposed describing the near-term biological process behind the biocide treatment-recovery cycle in a souring scenario. Finally, this work highlights the potential applications and caveats of harnessing the increasingly available field microbial community data for the improvement of souring modelling and field souring control strategies.

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Al-Marri, Salem Sml, Saad F. Alkafeef, Hom B. Chetri, Asma'a Al-Ghabdan, and Ealian H. D. Al-Anzi. "Opportunistic Fluid Sampling and Analysis to track reservoir souring in water flooded operations in North Kuwait reservoirs C - Implications for the future." In SPE Middle East Oil and Gas Show and Conference. Society of Petroleum Engineers, 2009. http://dx.doi.org/10.2118/120055-ms.

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