Relevant bibliographies by topics / Oil fields Geology

Contents

  1. Journal articles
  2. Dissertations / Theses
  3. Books
  4. Book chapters
  5. Conference papers
  6. Reports

Academic literature on the topic 'Oil fields Geology'

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

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Journal articles on the topic "Oil fields Geology"

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Mikhailov, N. N., O. M. Ermilov, and L. S. Sechina. "Adsorbed oil of gas condensate fields." Russian Geology and Geophysics 57, no. 6 (June 2016): 958–66. http://dx.doi.org/10.1016/j.rgg.2015.01.027.

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Goffey, G., J. Gluyas, and N. Schofield. "UK oil and gas fields: an overview." Geological Society, London, Memoirs 52, no. 1 (2020): 3–18. http://dx.doi.org/10.1144/m52-2019-48.

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Gluyas, J. G., and H. M. Hichens. "UK Oil and Gas Fields - An Overview." Geological Society, London, Memoirs 20, no. 1 (2003): 3–4. http://dx.doi.org/10.1144/gsl.mem.2003.020.01.02.

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AbstractThis volume was conceived when one of us (JG) returned to the UK in mid-1996. Having not worked the UK offshore since the late 1980s it was clear that there had been many changes, not least in the number of fields on production. During that first year back in the UK, JG's copy of Abbots (1991) UK Oil and Gas Fields, 25 Years Commemorative Volume became exceedingly well used. A casual comment to Wendy Cawthorne of the Geological Society library to this effect solicited the response that JG was not alone in finding Abbots (1991) useful. Memoir 14 was the Geological Society's 'best seller'. However, although Abbots (1991) continues to sell well, it was by 1996 out of date insofar as it contains papers describing only about half of the fields then on production.A combination of egotistical zeal, wishing for a bestseller and altruism towards the UK industry led us to make an offer to the Geological Society to revise Memoir 14. The offer was accepted and by April 1998, editors had been appointed and letters of invitation to contribute to the memoir were sent to exploration managers in all the UK operating companies. The responses to those letters were for the most part positive. A request was made to authors for manuscripts to be sent to the editors by June 1999. The first to arrive was six months ahead of schedule (thanks A. Yaliz & N. McKim for their paper on the Douglas Field). However, neither the editors
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Soeparyono, N., and P. Lennox. "Structural styles, Cepu oil fields, Java, Indonesia." Exploration Geophysics 22, no. 2 (June 1991): 369–74. http://dx.doi.org/10.1071/eg991369.

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Marakushev, A. A., and S. A. Marakushev. "Formation of oil and gas fields." Lithology and Mineral Resources 43, no. 5 (September 2008): 454–69. http://dx.doi.org/10.1134/s0024490208050039.

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Yaliz, A., and N. McKim. "The Douglas Oil Fields, Block 110/13b, East Irish Sea." Geological Society, London, Memoirs 20, no. 1 (2003): 61–75. http://dx.doi.org/10.1144/gsl.mem.2003.020.01.05.

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AbstractThe Douglas Field, on stream in February 1996, is the first oil field to be developed in the East Irish Sea Basin, with an estimated STOIIP of 202 MMBBL. The field structure consists of three tilted fault blocks formed during extensional faulting in Triassic-early Jurassic times, and later readjusted by contractional movements during Tertiary inversion. The oil is trapped in the Triassic Ormskirk Sandstone Formation, which comprises moderate to high porosity aeolian and fluvial sandstones. The reservoir depth is shallow (2140 ft) with a maximum oil column of 375 ft. The reservoir can be divided into several laterally extensive units based on vertical facies variations. The reservoir quality is principally controlled by primary depositional processes, and authigenic clay minerals are not important. However, bitumen is formed extensively in specific areas of the field causing significant permeability reduction. The hydrocarbon filling history of the field was complex, with the occurrence of at least two phases of oil generation and migration. The field contains a relatively 'dead' oil with a low GOR (170scf/bbl). Pressure maintenance is achieved through sea water injection, and to date ten production and six injection wells have been drilled. The crude is light (44° API) and contains high levels of H2S (0.5mol%) and mercaptans, which are removed during processing offshore.
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Zhantayev, Zh Sh, G. Zh Zholtayev, B. Iskakov, and А. Gaipova. "GEOMECHANICAL MODELING OF STRUCTURES OIL AND GAS FIELDS." Series of Geology and Technical Sciences 447, no. 3 (June 15, 2021): 40–45. http://dx.doi.org/10.32014/2021.2518-170x.60.

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The presence of areas of accumulation of hydrocarbons in the sedimentary strata is genetically related both to the conditions of sedimentation and to secondary changes in the properties of the geological environment, caused along with other and geodynamic processes. At the same time, it is the stress-strain state that is the key characteristic of the environment, the analysis of which makes it possible to predict the influence of geodynamic factors that cause deformation processes in the sedimentary stratum, on the formation of zones of decompaction and increased fracturing, areas of increased filtration-capacity properties of reservoir rocks, the direction of natural migration of hydrocarbons. Using the example of 3D seismic data obtained at the Akshabulak area, the possibility of integrating geomechanical modeling and additional express analysis of seismic data in solving problems related to determining the probable places of accumulations and directions of natural migration of hydrocarbons is shown.
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Zhantayev, Zh Sh, G. Zh Zholtayev, B. Iskakov, and А. Gaipova. "GEOMECHANICAL MODELING OF STRUCTURES OIL AND GAS FIELDS." SERIES OF GEOLOGY AND TECHNICAL SCIENCES 4, no. 448 (August 15, 2021): 124–30. http://dx.doi.org/10.32014/2021.2518-170x.90.

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Robson, D. "The Argyll, Duncan and Innes Fields, Block 30/24 and 30/25a, UK North Sea." Geological Society, London, Memoirs 14, no. 1 (1991): 219–26. http://dx.doi.org/10.1144/gsl.mem.1991.014.01.27.

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abstractThe Argyll, Duncan and Innes Fields are situated in the UK Central Graben in Blocks 30/24 and 30/25a. They produce oil from Devonian, Rotliegendes, Zechstein and Jurassic reservoirs through a common floating production facility, the Deepsea Pioneer.Argyll was the first UK North Sea oil field to come on stream, with first oil produced in June 1975. Duncan and Innes were added later and the estimated STOIIP for the three fields is approximately 270 MMBBL. To date over 90 MMBBL have been recovered, and the fields are now on decline.
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Liu, Wei Fu, Shuang Long Liu, and Hong Ying Han. "Depositional Model and Development Significance of Clastic Reservoir." Applied Mechanics and Materials 522-524 (February 2014): 1245–48. http://dx.doi.org/10.4028/www.scientific.net/amm.522-524.1245.

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A general geologic sedimentation model for reservoir is made by carefully analyzing the inberent essence of depositional environmentand for clastic rocks of lake basin. The basic model in the streaming environment is composed of two basic facies units: one is the waterway facie and the other is non-waterway facie. The principal characteristics of developing geology and sedimentology have been outlined. It can be commonly used in developing under-producted reserves and raising recovery ratio in the highly developed oil fields.
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Dissertations / Theses on the topic "Oil fields Geology"

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Wolpert, Jeremy M. "Stratigraphic and structural analysis of the J1 Sandstone, Scotts Bluff Trend, Scotts Bluff and Morrill counties, Nebraska." Morgantown, W. Va. : [West Virginia University Libraries], 2006. https://eidr.wvu.edu/etd/documentdata.eTD?documentid=4925.

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Thesis (M.S.)--West Virginia University, 2006.
Title from document title page. Document formatted into pages; contains xi, 103 p. : ill. (some col.), maps (some col.). Includes abstract. Includes bibliographical references (p. 90).
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Torn, Daniel. "Sedimentology and stratigraphy of diatomaceous sediments in the Casmalia Hills and Orcutt oil fields in the Santa Maria basin, California." Thesis, California State University, Long Beach, 2014. http://pqdtopen.proquest.com/#viewpdf?dispub=1528056.

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Two industry acquired diatomite cores (Sisquoc Formation) from the Orcutt (Newlove 76-RD1) and Casmalia Hills (Stokes A-30804) oil fields were analyzed by core descriptions, laboratory analysis (XRD and SEM), and gamma ray logs. Based on these data, five distinct lithofacies, nine sedimentary features and compositional trends of both cores were established. Newlove 76-RD1 and Stokes A-30804 record an upward-shallowing succession at different depositional positions on the Pliocene paleo-slope of the Santa Maria basin. Stokes A-30804 reflects slope deposition on a lower flank of a paleo-bathymetric high receiving higher detrital influx from inter-ridge troughs. Slope deposition of Newlove 76-RD1 was closer to a paleo-bathymetric high where purer diatomaceous sediments accumulated. Within Stokes A-30804, purer opal-A dominant lithofacies contain the highest oil saturations. The diagenesis and precipitation of opal-CT and abundance of phyllosilicate significantly hinders oil saturation within lithofacies.

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Nakanishi, Takeshi. "Practical application of sequence stratigraphy and risk analysis for stratigraphic trap exploration." Title page, contents and abstract only, 2002. http://web4.library.adelaide.edu.au/theses/09PH/09phn1635.pdf.

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"September 2002" Includes bibliographical references (leaves 200-209) Outlines an evaluation procedure for stratigraphic trap exploration by employing sequence stratigraphy, 3D seismic data visualisation and quantitative risk analysis with case studies in an actual exploration basin.
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Badescu, Adrian Constantin. "Reservoir characterization of the Miocene Starfak and Tiger Shoal fields, offshore Louisiana through integration of sequence stratigraphy, 3-D seismic, and well-log data." Access restricted to users with UT Austin EID, 2002. http://wwwlib.umi.com/cr/utexas/fullcit?p3108452.

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Boggs, Cheryle Ann. "Glacial Drift Thickness and Vs Characterized Using Three-Component Passive Seismic Data at the Dominion Stark-Summit Gas Storage Field, North Canton, Ohio." Wright State University / OhioLINK, 2014. http://rave.ohiolink.edu/etdc/view?acc_num=wright1420815127.

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Stevenson, Patrick M. "Petroleum geology and geochemistry of the Manyberries oil field, southeastern Alberta." Thesis, National Library of Canada = Bibliothèque nationale du Canada, 1999. http://www.collectionscanada.ca/obj/s4/f2/dsk2/ftp01/MQ38614.pdf.

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Stevenson, Patrick M. "Petroleum geology and geochemistry of the Manyberries oil field, southeastern Alberta." Calgary, Alta. : University of Calgary, 1998. https://dspace.ucalgary.ca/handle/1880/26270.

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Thesis (M.Sc.) -- University of Calgary, 1998.
Three folded leaves and 3 1/2 in. computer disk in back pocket. 3 folded leaves and 3 1/2 in. computer disk in back pocket. Includes bibliographical references. Also available on microfiche. Available in PDF format via the World Wide Web.
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Duggan, James P. "Sedimentology and diagenesis of Swan Hills Simonette oil field, west-central Alberta basin." Thesis, National Library of Canada = Bibliothèque nationale du Canada, 1997. http://www.collectionscanada.ca/obj/s4/f2/dsk3/ftp04/mq37116.pdf.

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Benzagouta, Mohammed Said. "Petrophysical controls on sandstone reservoir characteristics in the Buchan Oil Field, northern North Sea." Thesis, University of Newcastle Upon Tyne, 1991. http://ethos.bl.uk/OrderDetails.do?uin=uk.bl.ethos.239703.

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Gyore, Domokos. "Noble gases as tracers of injected CO2 in the Cranfield enhanced oil recovery field." Thesis, University of Glasgow, 2015. http://theses.gla.ac.uk/7127/.

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Identifying how injected CO2 is retained underground is a fundamental challenge for carbon capture and storage. Developing tracers that are cheap and widely applicable will increase confidence that stored CO2 remains in place. This PhD examines the applicability of the isotopic composition of noble gases (He, Ne, Ar, Kr and Xe) that are present as minor natural constituents in CO2, as tracers of the fate of injected CO2. The Cranfield oil field (MS, USA), into which natural CO2 is injected for enhanced oil recovery (EOR), was developed as a site for a parallel study of carbon capture and storage, and is the focus of this research. Samples of gas from the transported CO2, and the injection and production wells were taken 18 and 45 months after the commencement of injection in July 2008. Neon isotope data are consistent with simple binary mixing between the injected and in situ natural gas. This relationship allows the Ne isotope composition of the pre-injection gas in Cranfield to be determined. Coherent correlations between Ne, He and Ar isotopes allow the natural gas end-member composition to be calculated as well. The noble gas isotopic ratios (3He/4He = 0.05 RA, where RA is the atmospheric value of 1.39 x 10-6, 20Ne/22Ne = 9.62, 21Ne/22Ne = 0.0384, 40Ar/36Ar = 836 and 40Ar*/4He = 0.09, where 40Ar* is the sum of the radiogenic and mantle derived 40Ar) of the natural gas in Cranfield are typical of natural gases derived from the continental crust. Helium isotope ratios and the 40Ar*/4He ratio notably correlate with CO2 concentrations, indicating that the noble gas fingerprints of the injected gas are preserved, and may offer utility as a tracer of the CO2. The He and Ar isotope systematics of the four sampled wells that have the lowest CO2 concentrations identify the loss of a significant amount of CO2 from the free gas phase. The amount of loss in each of the four wells can be quantified from the measured 3He/4He and 40Ar*/4He ratios and changes in the CO2/3He values. Losses vary between 22% and 96%, with good agreement between the different methods. It is notable however, that these four wells do not have significant gas production, and do not contribute significantly to the total amount of produced and re-injected gas. So, even though there is a significant loss from these wells, the total amount of CO2 lost is estimated to be only ~0.1% of the total injected gas, equivalent to 10kt gas. Notwithstanding this, the new data indicate that, across the entire field, CO2 is retained as a free phase and stratigraphic trapping is the most important storage mechanism. The fractionation of 40Ar*/4He, CO2/3He and δ13CCO2 in the CO2-poor samples is consistent with dissolution in water. The non-radiogenic noble gases (20Ne, 36Ar, 84Kr, 132Xe) originate from the atmosphere and are present in the gas, water and oil phases in the reservoir to differing degrees. It has been revealed that groundwater degassing, induced by CO2 injection plays an important role in fractionating 20Ne/36Ar, 84Kr/36Ar and 132Xe/36Ar at the early stage of injection, but a large heterogeneity in the degree of degassing has been observed throughout the reservoir. Some wells have shown 100% water degassing, while others are close to 0%. Oil degassing, and therefore the active CO2 – oil contact, became important during the later phase of injection, which is consistent with the fact that more CO2 injection was required to degas the oil than water. Temporal variations in the non-radiogenic noble gas ratios and 3He/4He are indicative of the evolution of the oil displacement efficiency. This fully agrees with the injection – production well data recorded in the field during sampling. This suggests that noble gases can also be used as a reservoir engineering tool to better understand the interaction of CO2, water and oil in the subsurface not only during CO2 storage but also to track EOR operations.
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Books on the topic "Oil fields Geology"

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Craig, James D. Geologic report for the Beaufort Sea planning area, Alaska: Regional geology, petroleum geology, environmental geology. Anchorage, Alaska: U.S. Dept. of Interior, Minerals Management Service, Alaska OCS Region, 1986.

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Craig, James D. Geologic report for the Beaufort Sea planning area, Alaska: Regional geology, petroleum geology, environmental geology. Anchorage, Alaska: U.S. Dept. of Interior, Minerals Management Service, Alaska OCS Region, 1986.

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American Association of Petroleum Geologists, ed. Oil field production geology. Tulsa, Okla: American Association of Petroleum Geologists, 2009.

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Craig, James D. Geologic report for the Beaufort Sea planning area, Alaska: Regional geology, petroleum geology, environmental geology. Anchorage, Alaska: U.S. Dept. of Interior, Minerals Management Service, Alaska OCS Region, 1986.

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1949-, Sherwood Kirk W., Johnson Peter P, and United States. Minerals Management Service. Alaska OCS Region., eds. Geologic report for the Beaufort Sea planning area, Alaska: Regional geology, petroleum geology, environmental geology. Anchorage, Alaska: U.S. Dept. of Interior, Minerals Management Service, Alaska OCS Region, 1986.

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Li, Desheng. Tectonic types of oil and gas basins in China. Beijing, P.R. China: Petroleum Industry Press, 1991.

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Dowling, D. B. Geological notes to accompany map of Sheep River gas and oil field, Alberta. Ottawa: Govt. Print. Bureau, 1997.

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Harper, John A. Geology of the oil and gas fields of southwestern Pennsylvania. Harrisburg, PA: Pennsylvania Geological Survey, 1987.

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Harper, John A. Geology of the oil and gas fields of southwestern Pennsylvania. Harrisburg: Commonwealth of Pennsylvania, Dept. of Environmental Resources, Office of Resources Management, Bureau of Topographic and Geologic Survey, 1987.

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ʻAdasānī, Maḥmūd Khālid. Ḥuqūl al-nafṭ fī gharb al-Kuwayt. [Kuwait: s.n., 1986.

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Book chapters on the topic "Oil fields Geology"

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Miall, Andrew D. "Case Studies of Oil and Gas Fields in Fluvial Reservoirs." In The Geology of Fluvial Deposits, 495–521. Berlin, Heidelberg: Springer Berlin Heidelberg, 2006. http://dx.doi.org/10.1007/978-3-662-03237-4_15.

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Ebanks, William J., and W. L. Watney. "Geology of Upper Pennsylvanian Carbonate Oil Reservoirs, Happy and Seberger Fields, Northwestern Kansas." In Casebooks in Earth Sciences, 239–50. New York, NY: Springer New York, 1985. http://dx.doi.org/10.1007/978-1-4612-5040-1_15.

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Petterson, O., A. Storli, E. Ljosland, and I. Massie. "The Gullfaks Field: Geology and Reservoir Development." In North Sea Oil and Gas Reservoirs—II, 67–90. Dordrecht: Springer Netherlands, 1990. http://dx.doi.org/10.1007/978-94-009-0791-1_4.

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Goh, L. S. "The Logger Field: Geology and Reservoir Characterization." In North Sea Oil and Gas Reservoirs — III, 75–93. Dordrecht: Springer Netherlands, 1994. http://dx.doi.org/10.1007/978-94-011-0896-6_5.

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Bacchiana, C., J. Parpant, and B. Smart. "Management of Chaunoy Oil Field Multilayered Reservoir." In Hydrocarbon and Petroleum Geology of France, 147–53. Berlin, Heidelberg: Springer Berlin Heidelberg, 1994. http://dx.doi.org/10.1007/978-3-642-78849-9_10.

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Srivastava, Ravi Prakash, Nimisha Vedanti, Idar Akervoll, Per Bergmo, Ramesh Chandra Yerramilli, Sanjay Surya Yerramilli, and V. P. Dimri. "Study of CO2 EOR in a Sector Model from Mature Oil Field, Cambay Basin, India." In Springer Geology, 87–98. Cham: Springer International Publishing, 2015. http://dx.doi.org/10.1007/978-3-319-03119-4_3.

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Harff, J., W. L. Watney, G. C. Bohling, J. H. Doveton, R. A. Olea, and K. D. Newell. "Three-Dimensional Regionalization for Oil Field Modeling." In Geologic Modeling and Simulation, 205–27. Boston, MA: Springer US, 2001. http://dx.doi.org/10.1007/978-1-4615-1359-9_11.

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Slatt, Roger M., Sandra Phillips, Jeremy M. Boak, and Martin B. Lagoe. "Scales of Geologic Heterogeneity of a Deep-Water Sand Giant Oil Field, Long Beach Unit, Wilmington Field, California." In Frontiers in Sedimentary Geology, 263–92. New York, NY: Springer New York, 1993. http://dx.doi.org/10.1007/978-1-4757-0160-9_12.

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Veenhof, Epeüs N. "Geological aspects of the Annerveen gas field, the Netherlands." In Geology of Gas and Oil under the Netherlands, 79–92. Dordrecht: Springer Netherlands, 1996. http://dx.doi.org/10.1007/978-94-009-0121-6_8.

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Bruijn, Abraham N. "De Wijk gas field (Netherlands): reservoir mapping with amplitude anomalies." In Geology of Gas and Oil under the Netherlands, 243–53. Dordrecht: Springer Netherlands, 1996. http://dx.doi.org/10.1007/978-94-009-0121-6_20.

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Conference papers on the topic "Oil fields Geology"

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Vasiljeva, E. A., and V. N. Martirosyan. "Applying Cdp Seismic Reflection Data To Detail The Geology Of The Unique Gascondensate Kara Sea Fields." In Arctic Shelf Oil & Gas Conference 2004. European Association of Geoscientists & Engineers, 2004. http://dx.doi.org/10.3997/2214-4609-pdb.185.section2_06.

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Arslan, Izzet, Farzaneh Rajabi, and Fayadhoi Ibrahima. "Practical Automated Detection of Remaining Oil in Mature Fields Using Production and Geology Data." In SPE Western Regional Meeting. Society of Petroleum Engineers, 2019. http://dx.doi.org/10.2118/195321-ms.

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Kendall, Ch G. St C. "Stratigraphic Controls on Carbonate Evaporite Stratigraphy - Importance to Hydrocarbon Exploration: Examples from Middle Eastern Oil Fields and Their Response to Plate Tectonic Cycle, Climate, Basin Position and Sea Level." In Third Arabian Plate Geology Workshop. Netherlands: EAGE Publications BV, 2011. http://dx.doi.org/10.3997/2214-4609.20144053.

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Ryabinkina, N. N., and O. V. Valyaeva. "Oil potential of the Asselian-Sakmarian reefogenic buildups of the Varandey-Adzva zone of the Timan-Pechora Province." In All-Russia Lithological Meeting «Geology of reefs». Institute of Geology FRC Komi SC UB RAS, 2020. http://dx.doi.org/10.19110/98491-013-106-107.

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Massive deposits in reef were discovered in separate fields of Varandey-Adzva zone (Naulskoye, Labaganskoye, etc.). These bodies are represented by organogenic-detrital limestones, fractured with porosity of 8-10%. They have the form of separate buildings, developed locally, wedging out along the strike within the same area. The deposits are confined to the secondary reservoirs of the pore and pore-fracture type.
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Slepak, Zakhar M. "NEW OPPORTUNITIES OF HIGH-RESOLUTION GRAVIMETRY FOR THE STUDIES OF SUBSURFACE GEOLOGY AND PREDICTION OF OIL FIELDS." In 14th SGEM GeoConference on SCIENCE AND TECHNOLOGIES IN GEOLOGY, EXPLORATION AND MINING. Stef92 Technology, 2014. http://dx.doi.org/10.5593/sgem2014/b11/s6.096.

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Okechukwu, Sedoo, Adedoyin Orekoya, Precious Alamina, James Anyaehie, Adekoyejo Sonde, and Uchechukwu Ozoemene. "Uncertainty Management Using Multi-Scenario Modeling in a Partially Appraised Field." In SPE Nigeria Annual International Conference and Exhibition. SPE, 2021. http://dx.doi.org/10.2118/207196-ms.

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Abstract Considering the imminent end of the ‘easy oil’ era, the increasing demand for energy and the global push towards the energy transition, oil and gas companies are more than ever interested in sustainable ways to develop marginal and complex hydrocarbon fields economically, through the application of technology and maximization of data analysis. In small partially appraised fields where the cost of drilling an appraisal well could derail the project economics, it becomes necessary to sweat the limited data available for reservoir modelling. The uncertainty analysis must be robust enough to ensure that the adopted field development strategy would yield a positive net present value despite the wide uncertainties associated with the field. The conventional workflow for subsurface uncertainty modelling involves defining the uncertainty ranges of static and dynamic reservoir parameters based on a single reservoir model concept. This paper focuses on a marginal field case study where the multi scenario modelling approach was adopted. This approach considered alternate reservoir geologic concepts based on different interpretations of the reservoir architecture, taking full cognizance of the available data, reservoir uncertainties and regional geology knowledge. Field Alpha is located onshore of Niger Delta in Nigeria. The geologic setting consists mainly of multi-storey, complex channel-belt systems, incising through Shoreface deposits. The reservoir of interest is an elongated structure with only two well penetrations located at the opposite distal part of the structure. The key reservoir uncertainties are reservoir structure, architecture, connectivity, and property distribution. Two possible distinct architecture were interpreted based on regional correlation and seismic. This paper focuses on how the interpretations and other information informed a robust development strategy that yielded significant (30 %) reduction in development cost and positive net present value.
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Sutadiwiria, Gunawan, and Hadi Prasetyo. "Uncertainty in Geophysic-Geology-Reservoir Modelling for Globigerinid Sand Carbonate in NE-Java Basin, Indonesia; Case Study: Planning vs. Actual of Fields Development at Madura Strait, Indonesia." In SPE Asia Pacific Oil & Gas Conference and Exhibition. Society of Petroleum Engineers, 2006. http://dx.doi.org/10.2118/100957-ms.

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Nazarov, R., P. Zalama, M. Hernandez, and C. Rivas. "Integrated Asset Modeling in Mature Offshore Fields: Challenges and Successes." In SPE Energy Resources Conference. SPE, 2014. http://dx.doi.org/10.2118/spe-169923-ms.

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Abstract Production management in mature fields is a very challenging task which involves a multidisciplinary technical approach to minimize the decline rate and extend the life of the asset/field. Most of the time Integrated Asset Modeling (IAM) techniques are applied to green fields with main objectives of identifying the “bottlenecks” or to forecast production with different development cases. In the case of mature fields it is mostly considered as an optional study with less analytical value due to low operating surface pressures, already existing facilities, known well performance and studied reservoir geology. Nevertheless the processing of the reservoir, production and operational data in mature assets through one integrated workflow facilitates field management overall, thereby helping in the estimation of the remaining reserves and indicating real opportunities for optimization not seen by initial engineering scenarios. Additionally, IAM should be incorporated before getting to EOR studies. This paper describes the applied reservoir engineering workflow and integrated production model for the TSP fields (Teak, Samaan and Poui) located in the South East of Trinidad. TSP fields are jointly owned by by Repsol (70%), Petrotrin (15%) and NGC (15%) and are operated by Repsol. Current production of TSP is 13, 500 bopd. The oil produced from these fields is generally light oil, with an average range of 25-40 API and a solution GOR 200-1400scf/stb. Gas lift is the artificial lift system used in 95% of the wells. Average water cut is around 85%. Interaction of Production Engineering, Subsurface, Drilling, HSE, Facilities, and Maintenance departments is the key aspect to sustain the efficient operability of the TSP fields and operate at peak performance in spite of ageing installations, flow assurance problems and depleted reservoirs. The implementation of Operated Asset Structure in TSP in 2013 reinforced the cooperation between departments to achieve the main goals: minimum production deferrals, production optimization, screening of new opportunities and reserves, process improvement, facilities maintenance and effective logistics. Additionally, the Integrated Asset Modeling has been incorporated as part of the engineering surveillance which includes 3 fields, 100 wells, gas lift injection network, gas compressors, water treatment plant, etc. Real data from different sources and platforms, such as pressure temperature sensors, daily measured well parameters, reported operational figures, monthly welltests and screened remaining reserves are jointly transferred to the integrated model, built in commercial software (GAP/RESOLVE), bringing the field data processing and production management to the state-of-the-art level. Gas lift volume availability and system pressure, performed rigless intervention jobs (including recompletion of new zones), change of the fluid composition in certain wells, reconfiguration of facilities are timely reflected in the TSP integrated model. Based on the sensitivity runs and output results immediate actions are taken to comply with the production target.
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9

Gelvez, Camilo, Gerardo Cedillo, Eric Soza, Doris Gonzalez, Benjamin S. Slotnick, Sol Moreno, Wilson Pineda, et al. "DIGITAL FLUID SAMPLING IN DEEP WATER RESERVOIRS USING RESERVOIR FLUID GEODYNAMICS: THE BEGINNING OF THE DIGITAL FLUID SAMPLING REVOLUTION." In 2021 SPWLA 62nd Annual Logging Symposium Online. Society of Petrophysicists and Well Log Analysts, 2021. http://dx.doi.org/10.30632/spwla-2021-0010.

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Reservoir Fluid Geodynamics (RFG) is a novel thermodynamic methodology that integrates pressure-volume-temperature (PVT), geochemical fingerprinting (GCFP) and reservoir geology with downhole fluid analysis (DFA) data to understand the evolution of reservoir fluids over geologic time. RFG enables the enhancement of reservoir description, estimation of reservoir fluid properties, and optimization of data acquisition plans. Deep-water reservoirs comprise multiple uncertainties in reservoir connectivity, viscous oil and flow assurance. This paper demonstrates the development of digital fluid sampling techniques for deep-water fields using the RFG workflow to predict fluid properties and distribution, to address compartmentalization uncertainties and flow assurance risks, as well as to redefine the well-logging program. Identifying key reservoir concerns is the first step during the implementation of the RFG workflow. Five questions define key reservoir concerns: Do optical density measurements explain the impact of biogenic methane on fluid behavior? Is it feasible to characterize baffling and fault compartmentalization? Can we predict reservoir fluid properties and assess flow assurance risks based on fluid behavior? Is it possible to identify all this in real time? How could we optimize future fluid sampling programs? The next step is to collect the available DFA data and to integrate it with the existing PVT and geochemistry datasets. This paper describes the evaluation of over 150 fluid sampling DFA measurements acquired during the operational history of a Gulf of Mexico field. Fluid behavior and optical density gradients are interpreted from a geological perspective to understand reservoir connectivity. A strong correlation between optical density and asphaltene content enables digital fluid sampling for different PVT and geochemical parameters. Lastly, a general correlation of optical density and asphaltene content is derived for multiple Gulf of Mexico oil fields. Optical density measurements support a consistent characterization of biogenic methane along the studied deep-water field, suggesting a relation to fluid migration and charging from deeper to shallower reservoirs. Likewise, optical density gradients and its integrated evaluation facilitate the identification of mass transport complex (MTC) baffles in the north part of the field and the characterization of fault compartments in the main reservoir sands. In addition, the RFG workflow reveals the difference in fluid behavior of sampled wells located in the area of a water injection project by identifying asphaltene clustering near the oil-water contact. The correlations of optical density and asphaltene content help to predict fluid properties and to estimate its uncertainty, benefiting risk assessment for asphaltenes deposits and flow assurance in deep water operations. Real time analysis of optical density measurements during fluid sampling permits the characterization of fluid properties and reservoir connectivity, optimizing future fluid sampling programs when fluid contamination reaches 10%. Ultimately, this innovative methodology conveys a general correlation to predict asphaltene content based on optical density measurements for deep-water reservoirs in the Gulf of Mexico, enabling the possibility to predict reservoir fluid properties in real time fluid sampling operations.
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10

Espinola Gonzalez, Oswaldo, Laura Paola Vazquez Macedo, Julio Cesar Villanueva Alonso, and Julieta Alvarez Martinez. "Novel Approach to Enhance Field Development Plan Process and Reservoir Management to Maximize the Recovery Factor of Gas Condensate Reservoirs Through Integrated Asset Modeling." In SPE Trinidad and Tobago Section Energy Resources Conference. SPE, 2021. http://dx.doi.org/10.2118/200895-ms.

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Abstract The proper exploitation for a gas condensate reservoir requires an integrated collaboration and management strategy capable to provide detailed insight about future behavior of the reservoir. When a development plan is generated for a field, the reservoir management is not performed integrally, this is, different domains: geology, reservoir, drilling, production, economics, etc., work separately, and therefore, an adequate understanding of the main challenges, leading to issues such as an over dimensioning of surface facilities, excessive costs, among others. Through this paper, a methodology to improve the conventional field development plan is described, which contains 4 main pillars: Collaborative approach, Integrated analysis, engineering optimization and monitoring & surveillance. The methodology involves the description of a hybrid workflow based on the integration of multiple domains, technologies and recommendations to consider all the phenomena and compositional changes over time in the whole production system, aiming to define the optimum reservoir management strategy, facilities and operational philosophy as part of the Field Development Plan (FDP). Conventionally, the used of simplistic models most of times do not allow seeing phenomena in the adequate resolution (near wellbore and porous media effects, multiphase flow in pipelines, etc.), that occur with high interdependency in the Integrated Production System. With this methodology, the goal pursued is to support oil and gas companies to increase the recovery factor of gas condensate fields through the enhancement in the development and exploitation process and therefore, reducing associated costs and seizing available time and resources.
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Reports on the topic "Oil fields Geology"

1

Hite, Roger. South Louisiana Enhanced Oil Recovery/Sequestration R&D Project Small Scale Field Tests of Geologic Reservoir Classes for Geologic Storage. Office of Scientific and Technical Information (OSTI), October 2016. http://dx.doi.org/10.2172/1332270.

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