Relevant bibliographies by topics / Reservoir souring / Journal articles
To see the other types of publications on this topic, follow the link: Reservoir souring.

Journal articles on the topic 'Reservoir souring'

Author: Grafiati
Published: 4 June 2021
Last updated: 16 February 2022

Create a spot-on reference in APA, MLA, Chicago, Harvard, and other styles

Select a source type:

Consult the top 50 journal articles for your research on the topic '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

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 text
Abstract:
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.
APA, Harvard, Vancouver, ISO, and other styles
2

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 text
Abstract:
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.
APA, Harvard, Vancouver, ISO, and other styles
3

Mahdi, Najwa H., and Mohammed S. Al-Jawad. "Estimation of H2S Produced from Reservoir Souring." Journal of Petroleum Research and Studies 9, no. 4 (December 1, 2019): 74–88. http://dx.doi.org/10.52716/jprs.v9i4.323.

Full text
Abstract:
The increase of the produce H2S due to water injection is known as reservoir souring. The sulfate reduced bacteria (SRB) which may be exist in the injected water reduces the sulfate which already existing in the reservoir. This study includes prediction of H2S for Mauddud reservoir in the Ahdeb oilfield by using specialized reservoir numerical simulator. Reservoir souring modeling utilized to enable operations to make better decisions for remedial actions to either prevent souring or to mitigate its impact. The aim of this study is to estimate the probability and timing of the start of H2S production in produced fluids. The results showed that the maximum concentration of H2S in the prediction production well was reached to 2.9 Ibm/day which occurs after 180 days this carry out when the SRB concentration was about 2000 ppm .The SRB concentration is increasing in areas where the sulfate is in high concentration and also there is a direct relationship between the SRB concentration and the H2S concentration
APA, Harvard, Vancouver, ISO, and other styles
4

Haghshenas, Mehdi, Kamy Sepehrnoori, Steven L. Bryant, and Mohammad Ali Farhadinia. "Modeling and Simulation of Nitrate Injection for Reservoir Souring Remediation." SPE Journal 17, no. 03 (August 29, 2012): 817–27. http://dx.doi.org/10.2118/141590-pa.

Full text
Abstract:
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.
APA, Harvard, Vancouver, ISO, and other styles
5

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
APA, Harvard, Vancouver, ISO, and other styles
6

Schofield, Mick, and Jim Stott. "Assessing the Magnitude and Consequences of Reservoir Souring." Journal of Petroleum Technology 64, no. 05 (May 1, 2012): 76–79. http://dx.doi.org/10.2118/0512-0076-jpt.

Full text
APA, Harvard, Vancouver, ISO, and other styles
7

Johnson, Richard J., Benjamin D. Folwell, Alexander Wirekoh, Max Frenzel, and Torben Lund Skovhus. "Reservoir Souring – Latest developments for application and mitigation." Journal of Biotechnology 256 (August 2017): 57–67. http://dx.doi.org/10.1016/j.jbiotec.2017.04.003.

Full text
APA, Harvard, Vancouver, ISO, and other styles
8

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 text
Abstract:
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.
APA, Harvard, Vancouver, ISO, and other styles
9

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
APA, Harvard, Vancouver, ISO, and other styles
10

Skjevrak, I., D. C. Standnes, U. S. Thomsen, J. Xu, K. Håland, A. Kjølhamar, and P. K. Munkerud. "Field observations of reservoir souring development and implications for the Extended Growth Zone (EGZ) souring model." Journal of Petroleum Science and Engineering 204 (September 2021): 108721. http://dx.doi.org/10.1016/j.petrol.2021.108721.

Full text
APA, Harvard, Vancouver, ISO, and other styles
11

Veshareh, Moein Jahanbani, and Hamidreza M. Nick. "Biased samples to study reservoir souring processes: A numerical analysis." Journal of Cleaner Production 315 (September 2021): 127944. http://dx.doi.org/10.1016/j.jclepro.2021.127944.

Full text
APA, Harvard, Vancouver, ISO, and other styles
12

Farhadinia, M. A., S. L. Bryant, K. Sepehrnoori, and M. Delshad. "Application of a 3D Reservoir Simulator with Biodegradation Capability to Evaluate Reservoir Souring Predictive Models." Petroleum Science and Technology 28, no. 4 (February 10, 2010): 382–92. http://dx.doi.org/10.1080/10916460903070561.

Full text
APA, Harvard, Vancouver, ISO, and other styles
13

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 text
Abstract:
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.
APA, Harvard, Vancouver, ISO, and other styles
14

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
APA, Harvard, Vancouver, ISO, and other styles
15

Li, Haizhou, Lu Zhang, Liping Liu, and Ali Shabani. "Impact of rock mineralogy on reservoir souring: A geochemical modeling study." Chemical Geology 555 (November 2020): 119811. http://dx.doi.org/10.1016/j.chemgeo.2020.119811.

Full text
APA, Harvard, Vancouver, ISO, and other styles
16

Kögler, Felix, Fabian S. F. Hartmann, Dirk Schulze-Makuch, Andrea Herold, Hakan Alkan, and Nicole Dopffel. "Inhibition of microbial souring with molybdate and its application under reservoir conditions." International Biodeterioration & Biodegradation 157 (February 2021): 105158. http://dx.doi.org/10.1016/j.ibiod.2020.105158.

Full text
APA, Harvard, Vancouver, ISO, and other styles
17

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 text
Abstract:
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
APA, Harvard, Vancouver, ISO, and other styles
18

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 text
Abstract:
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).
APA, Harvard, Vancouver, ISO, and other styles
19

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 text
Abstract:
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).
APA, Harvard, Vancouver, ISO, and other styles
20

Tsesmetzis, Nicolas, Eric B. Alsop, Adrien Vigneron, Fons Marcelis, Ian M. Head, and Bart P. Lomans. "Microbial community analysis of three hydrocarbon reservoir cores provides valuable insights for the assessment of reservoir souring potential." International Biodeterioration & Biodegradation 126 (January 2018): 177–88. http://dx.doi.org/10.1016/j.ibiod.2016.09.002.

Full text
APA, Harvard, Vancouver, ISO, and other styles
21

Kuijvenhoven, Cor, Jean-Christophe Noirot, Andrew M. Bostock, Dave Chappell, and Arfan Khan. "Use of Nitrate to Mitigate Reservoir Souring in Bonga Deepwater Development Offshore Nigeria." SPE Production & Operations 21, no. 04 (November 1, 2006): 467–74. http://dx.doi.org/10.2118/92795-pa.

Full text
APA, Harvard, Vancouver, ISO, and other styles
22

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
APA, Harvard, Vancouver, ISO, and other styles
23

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 text
Abstract:
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.
APA, Harvard, Vancouver, ISO, and other styles
24

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 text
Abstract:
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.
APA, Harvard, Vancouver, ISO, and other styles
25

Farhadinia, M. A., S. L. Bryant, K. Sepehrnoori, and M. Delshad. "Development and Implementation of a Multidimensional Reservoir Souring Module in a Chemical Flooding Simulator." Petroleum Science and Technology 28, no. 6 (March 15, 2010): 535–46. http://dx.doi.org/10.1080/10916460903070579.

Full text
APA, Harvard, Vancouver, ISO, and other styles
26

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
APA, Harvard, Vancouver, ISO, and other styles
27

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
APA, Harvard, Vancouver, ISO, and other styles
28

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
APA, Harvard, Vancouver, ISO, and other styles
29

Yin, Bei, Terry Williams, Thomas Koehler, Brandon Morris, and Kathleen Manna. "Targeted microbial control for hydrocarbon reservoir: Identify new biocide offerings for souring control using thermophile testing capabilities." International Biodeterioration & Biodegradation 126 (January 2018): 204–7. http://dx.doi.org/10.1016/j.ibiod.2016.07.019.

Full text
APA, Harvard, Vancouver, ISO, and other styles
30

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
APA, Harvard, Vancouver, ISO, and other styles
31

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
APA, Harvard, Vancouver, ISO, and other styles
32

Dindoruk, Birol, Ram R. Ratnakar, and Sanyal Suchismita. "Phase Equilibria of Acid-Gas Aqueous Systems (CO2, H2S, CH4, Water) and In-Situ pH Measurements in Application to Top-of-Line Corrosion." SPE Journal 26, no. 04 (February 22, 2021): 2364–79. http://dx.doi.org/10.2118/201341-pa.

Full text
Abstract:
Summary We present thermodynamic modeling and pH measurements of fluid systems containing acid-gases (e.g., CO2 and H2S), water, and hydrocarbons—replicating the production and shutdown conditions in sour fields—for the purpose of evaluating top-of-line corrosion (TLC) and wellbore integrity and screening/selection of the proper wellbore materials. In particular: An equation of state (EOS) model using Peng-Robinson EOS in combination with the Huron-Vidal (HV) mixing rule for an aqueous subsystem is developed. In the model, subject EOS parameters are calibrated against existing thermodynamic data (saturation data for pure components and solubility data for binary systems) in literature. New in-situ pH measurement data are presented for a model system corresponding to a sour field. It was found that the wellbore can be subjected to pH levels as low as 2.7 with reservoir fluid containing 12 mol% CO2 and 88 mol% CH4 with downhole flowing conditions of 200 bar and 150°C and wellhead shut-in conditions of 300 bar and 4°C, as observed from the experiments. A modeling workflow is developed to estimate pH of the condensed water as a function of temperature and composition of the aqueous phase. The comparison between prediction and experimental measurement shows a very good match between the two (within pH ±0.1). Such studies (pH measurements and prediction) are not available in the literature but play important roles in material screening and assuring wellbore integrity for sour fields. More importantly, sensitivity analysis can be performed to investigate the effects of various factors (such as reservoir temperature/pressure, shutdown conditions, and compositions or extent of souring) on pH prediction. Furthermore, the methodologies developed through this work can also be extended to reservoir facilities, pipelines, sour gas disposal/handling units, and downstream systems such as water utilities, reactor plants, and refineries. The work can also support regulation/licensing for these sour systems.
APA, Harvard, Vancouver, ISO, and other styles
33

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 text
Abstract:
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.
APA, Harvard, Vancouver, ISO, and other styles
34

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
APA, Harvard, Vancouver, ISO, and other styles
35

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 text
Abstract:
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.
APA, Harvard, Vancouver, ISO, and other styles
36

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 text
Abstract:
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.
APA, Harvard, Vancouver, ISO, and other styles
37

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 text
Abstract:
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.
APA, Harvard, Vancouver, ISO, and other styles
38

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 text
Abstract:
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.
APA, Harvard, Vancouver, ISO, and other styles
39

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
APA, Harvard, Vancouver, ISO, and other styles
40

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 text
Abstract:
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.
APA, Harvard, Vancouver, ISO, and other styles
41

Becker, Stephan, Lars Reuning, Joachim E. Amthor, and Peter A. Kukla. "Diagenetic Processes and Reservoir Heterogeneity in Salt-Encased Microbial Carbonate Reservoirs (Late Neoproterozoic, Oman)." Geofluids 2019 (November 4, 2019): 1–19. http://dx.doi.org/10.1155/2019/5647857.

Full text
Abstract:
A common problem in dolomite reservoirs is the heterogeneous distribution of porosity-reducing diagenetic phases. The intrasalt carbonates of the Ediacaran-Early Cambrian Ara Group in the South Oman Salt Basin represent a self-sourcing petroleum system. Depositional facies and carbonate/evaporite platform architecture are well understood, but original reservoir properties have been modified by diagenesis. Some of the carbonate reservoirs failed to produce hydrocarbons at acceptable rates, which triggered this study. The extent of primary porosity reduction by diagenetic phases was quantified using point counting. To visualize the distribution of diagenetic phases on a field scale, we constructed 2D interpolation diagenesis maps to identify patterns in cementation. The relative timing of diagenetic events was constrained based on thin-section observations and stable isotope analyses. Near-surface diagenesis is dominated by reflux-related processes, leading to porosity inversion in initial highly porous facies and a patchy distribution of early cements. This strong diagenetic overprint of primary and early diagenetic porosity by reflux-related cements leads to a reduction of stratigraphic and facies control on porosity. Calcite was identified as a burial-related cement phase that leads to an almost complete loss of intercrystalline porosity and permeability. Bitumen is an important pore-occluding phase and time marker of the deep-burial realm. The stratigraphic position of the dolomite reservoirs embedded at the base of a salt diapir had a strong impact on its diagenetic development. The salt isolated the dolomites from external fluids, leading to a closed system diagenesis and the buildup of near lithostatic fluid pressures. In combination, these processes decreased the impact of further burial diagenetic processes. The study highlights that cement distribution in salt-encased carbonate reservoirs is mainly related to early diagenetic processes but can be very heterogeneous on a field scale. Further work is needed to implement these heterogeneities in an integrated numerical reservoir model.
APA, Harvard, Vancouver, ISO, and other styles
42

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
APA, Harvard, Vancouver, ISO, and other styles
43

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 text
Abstract:
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.
APA, Harvard, Vancouver, ISO, and other styles
44

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
APA, Harvard, Vancouver, ISO, and other styles
45

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
APA, Harvard, Vancouver, ISO, and other styles
46

Barclay, S. A., K. Liu, and D. Holland. "RESERVOIR QUALITY, DIAGENESIS AND SEDIMENTOLOGY OF THE PALE AND SUBU SANDSTONES: RE-VISITING THE EASTERN PAPUAN BASIN, PAPUA NEW GUINEA." APPEA Journal 43, no. 1 (2003): 515. http://dx.doi.org/10.1071/aj02027.

Full text
Abstract:
Two shallow diamond drill holes (Subu–1 and Subu–2) continuously cored in August and September 2001 by InterOil Australia represent the first sub-surface penetrations of reservoir quality sandstones in the Eastern Papuan Basin of Papua New Guinea. These wells intersected two sedimentologically distinct thick quartz sandstones (>100 m). The upper sandstone unit is Campanian in age and is correlated with the Pale Sandstone, whereas the lower sandstone is of Turonian age and has not been reported previously, and is tentatively named as the Subu Sandstone in this paper.The core has been the subject of detailed reservoir quality and diagenetic study as part of a multi-disciplinary study conducted by CSIRO Petroleum. The results of the reservoir quality portion of this study form the basis of this report and demonstrate the following:There are two distinct depositional systems present with a lower sandy slope apron and basin floor fan system (Subu Sandstone) and a younger upper shoreface-shallow marine depositional system (Pale Sandstone).While the porosity and permeability data for subsurface samples (5 to 16% and 0.1 to 1000mD) are lower than previously reported by Boult and Carman (1990) for surface samples both the sandstone units demonstrate thick, good reservoir quality reservoir capable of holding significant volumes of hydrocarbons.Bitumen is present in the pore space through out the sandstones in both wells. The presence of biodegraded hydrocarbons demonstrates that liquid hydrocarbons have been generated in the basin and have either migrated through the Subu and Pale sandstone or have been reservoired in them.Associated with the bitumen is pyrite precipitated as an in-situ by-product of shallow biodegradation of the parent liquid hydrocarbon as indicated by sulphur isotope analysis.Diagenetic effects include compaction (the dominant control on reservoir quality), minor quartz cementation, minor secondary porosity generation, and in thin zones localised carbonate cementation.Despite their very different depositional settings and age difference the thin section petrology of the Pale and Subu sandstones are very similar. The subtle difference between them is textural (grain size, sorting) and detrital clay content. The Subu Sandstone is typically finer grained, displays a higher degree of sorting and has a higher detrital clay content than the Pale Sandstone.The character of these sandstones may have as much to do with provenance as with depositional environment and may indicate a separate quartz-rich depositional system sourcing sediment from the Australian craton independent of the Fly Platform Toro/Imburu systems.
APA, Harvard, Vancouver, ISO, and other styles
47

Krueger, Martin. "Use of the photoelectric effect as a reservoir quality indicator in the Niobrara Formation, Piceance Basin, northwest Colorado." Interpretation 6, no. 1 (February 1, 2018): SA1—SA5. http://dx.doi.org/10.1190/int-2017-0035.1.

Full text
Abstract:
The late Cretaceous Niobrara Formation and underlying lower Mancos Group have significant petroleum potential in the Piceance Basin of northwest Colorado. Relative to the Denver Basin Niobrara, the Piceance Basin Niobrara has had significantly less drilling activity, and therefore fewer subsurface data are available. There are several key geologic differences pertaining to the Niobrara depositional history in these two basins. First, the overall thickness of the formation increases greatly to the west. Thicknesses of 91.4 m (300 ft), common in the Denver Basin, become thicknesses of as much as 548.6 m (1800 ft) in the Piceance Basin. Second, to date, maximum total organic carbon (TOC) values from the Piceance Basin are approximately 3 wt%, whereas in the Denver Basin, TOC values may be as high as 8 wt%. Several factors may contribute to the lesser TOC, but a significant factor is the dilution of organic material by increasing siliciclastic deposition. Unlike the Denver Basin stratigraphy of organic-rich marls providing the bulk of sourcing to carbonate-rich benches of greater fracture porosity, TOC and carbonate richness are coupled in the Piceance Basin. Core and well-log data suggest that the Piceance Basin Niobrara Formation’s carbonate-rich strata have higher TOC content relative to the interlaying clay-rich strata. This relationship enables the use of the photoelectric effect, the PEF or PE log, to map trends of carbonate richness and classify reservoir quality, where carbonate and organics may be at maximum values. In other unconventional reservoirs that share similar depositional histories and display the positive correlation between carbonate and organic richness, the PEF curve should be used for reservoir quality screening purposes.
APA, Harvard, Vancouver, ISO, and other styles
48

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
APA, Harvard, Vancouver, ISO, and other styles
49

Li, Jun, Raheel Ahmed, Qian Zhang, Yongfan Guo, and Xiaochun Li. "A Geochemical Model of Fluids and Mineral Interactions for Deep Hydrocarbon Reservoirs." Geofluids 2017 (2017): 1–11. http://dx.doi.org/10.1155/2017/3482603.

Full text
Abstract:
A mutual solubility model for CO2-CH4-brine systems is constructed in this work as a fundamental research for applications of deep hydrocarbon exploration and production. The model is validated to be accurate for wide ranges of temperature (0–250°C), pressure (1–1500 bar), and salinity (NaCl molality from 0 to more than 6 mole/KgW). Combining this model with PHREEQC functionalities, CO2-CH4-brine-carbonate-sulfate equilibrium is calculated. From the calculations, we conclude that, for CO2-CH4-brine-carbonate systems, at deeper positions, magnesium is more likely to be dissolved in aqueous phase and calcite can be more stable than dolomite and, for CO2-CH4-brine-sulfate systems, with a presence of CH4, sulfate ions are likely to be reduced to S2− and H2S in gas phase could be released after S2− saturated in the solution. The hydrocarbon “souring” process could be reproduced from geochemical calculations in this work.
APA, Harvard, Vancouver, ISO, and other styles
50

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
APA, Harvard, Vancouver, ISO, and other styles
We offer discounts on all premium plans for authors whose works are included in thematic literature selections. Contact us to get a unique promo code!

To the bibliography