Relevant bibliographies by topics / Cretaceous oil reservoir

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Academic literature on the topic 'Cretaceous oil reservoir'

Author: Grafiati
Published: 4 June 2021
Last updated: 3 February 2022

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Journal articles on the topic "Cretaceous oil reservoir"

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Kakarash, Tariq, and Qays M. Sadeq. "Development Permeability prediction for Bai Hassan Cretaceous Carbonate Reservoir." UHD Journal of Science and Technology 2, no. 1 (May 25, 2018): 8. http://dx.doi.org/10.21928/uhdjst.v2n1y2018.pp8-18.

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Permeability and porosity are the most difficult parameters to estimate in the oil reservoir because they are varying significantly over the reservoir, especially in the carbonate formation. Porosity and permeability can only be sampled at the well location. However, porosity is easy to estimate directly from well log data, permeability is not. In addition, permeability measurements from core samples are very expensive. Carbonate reservoirs are very difficult to characterize because of their tendency to be tight and heterogeneous due to deposition and diagenetic processes. Therefore, many engineers and geologists try to establish methods to get the best characterization for the carbonate reservoir. In this study, available routine core data from three wells are used to develop permeability model based on hydraulic flow unit method (HFUM) (RQI/FZI) for cretaceous carbonate middle reservoirs of Bai Hassan oil field. The results show that the HFUM is work perfectly to characterize and predict permeability for uncored wells because R2 ≥ 0.9. It is indicating that permeability can be accurately predicted from porosity if rock type is known.
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Xi, Kelai, Yingchang Cao, Keyu Liu, and Rukai Zhu. "Factors influencing oil saturation and exploration fairways in the lower cretaceous Quantou Formation tight sandstones, Southern Songliao Basin, China." Energy Exploration & Exploitation 36, no. 5 (January 2, 2018): 1061–85. http://dx.doi.org/10.1177/0144598717751181.

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Favorable exploration fairway prediction becomes crucial for efficient exploration and development of tight sandstone oil plays due to their relatively poor reservoir quality and strong heterogeneous oil saturation. In order to better understand the factors influencing oil saturation and favorable exploration fairway distribution, petrographic investigation, reservoir properties testing, X-ray diffraction analysis, oil saturation measurement, pressure-controlled mercury injection, and rate-controlled mercury injection were performed on a suite of tight reservoir from the fourth member of the Lower Cretaceous Quantou Formation (K1q4) in the southern Songliao Basin, China. The sandstone reservoirs are characterized by poor reservoir properties and low oil saturations. Reservoir properties between laboratory pressure conditions and in situ conditions are approximately the same, and oil saturations are not controlled by porosity and permeability obviously. Pores are mainly micro-scale, and throats are mainly nano-scale, forming micro- to nano-scale pore–throat system with effective connected pore–throat mainly less than 40%. Oil emplacement mainly occurs through the throats with average radius larger than 0.25 µm under original geological condition. Moreover, the samples with higher oil saturation show more scattered pore and throat distributions, but centered pore–throat radius ratio distribution. Pore–throat volume ratio about 2.3–3.0 is best for oil emplacement, forming high oil saturation. Quartz overgrowth, carbonate cements, and authigenic clays are the major diagenetic minerals. The reservoirs containing about 4–5% carbonate cements are most preferable for oil accumulation, and oil saturation increases with increasing of chlorite as well. The flow zone indicator is a reasonable parameter to predict favorable exploration targets in tight sandstone reservoirs. The reservoirs with flow zone indicator values larger than 0.05 can be regarded as favorable exploration targets in the K1q4 tight sandstones. According to the planar isoline of average flow zone indicator value, the favorable exploration targets mainly distribute in the delta plain distributary channel and deltaic front subaqueous distributary channel.
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Ahmed, Rayan. "Geological Model for Mauddud Reservoir Khabaz Oil Field." Iraqi Geological Journal 54, no. 1D (April 30, 2021): 29–42. http://dx.doi.org/10.46717/igj.54.1d.3ms-2021-04-23.

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The Mauddud reservoir, Khabaz oil field which is considered one of the main carbonate reservoirs in the north of Iraq. Recognizing carbonate reservoirs represents challenges to engineers because reservoirs almost tend to be tight and overall heterogeneous. The current study concerns with geological modeling of the reservoir is an oil-bearing with the original gas cap. The geological model is establishing for the reservoir by identifying the facies and evaluating the petrophysical properties of this complex reservoir, and calculate the amount of hydrocarbon. When completed the processing of data by IP interactive petrophysics software, and the permeability of a reservoir was calculated using the concept of hydraulic units then, there are three basic steps to construct the geological model, starts with creating a structural, facies and property models. The reservoirs were divided into four zones depending on the variation of petrophysical properties (porosity and permeability). Nine wells that penetrate the Cretaceous Formation (Mauddud reservoir) are included to construct the geological model. Zone number three characterized as the most important due to it Is large thickness which is about 108 m and good petrophysical properties are about 13%, 55 md, 41% and 38% for porosity, permeability, water saturation and net to gross respectively. The initial oil and gas in place are evaluated to be about 981×106 STB and 400×109 SCF.
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Fu, Siyi, Zhiwei Liao, Anqing Chen, and Hongde Chen. "Reservoir characteristics and multi-stage hydrocarbon accumulation of the Upper Triassic Yanchang Formation in the southwestern Ordos Basin, NW China." Energy Exploration & Exploitation 38, no. 2 (August 19, 2019): 348–71. http://dx.doi.org/10.1177/0144598719870257.

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The Chang-8 and Chang-6 members of the Upper Triassic Yanchang Formation (lower part) are regarded as the main oil producing members of the Ordos Basin. Recently, new hydrocarbon discoveries have been made in the upper part of the Yanchang Formation (e.g., Chang-3) in the southwestern Ordos Basin, implying that this interval also has a good potential for hydrocarbon exploration. However, studies on the origin of the high-quality reservoir, hydrocarbon migration, and accumulation patterns remain insufficient. In this study, integrated petrological, mineralogical, and fluid inclusion tests are employed to evaluate reservoir characteristics, and reconstruct the history of hydrocarbon migration and accumulation during oil and gas reservoir formation. The results reveal that the Yanchang Formation is characterized by low porosity (8 − 14%), medium permeability (0.5 − 5 mD), and strong heterogeneity; the reservoir properties are controlled by secondary porosity. Two types of dissolution are recognized in the present study. Secondary pore formation in the lower part of the formation is related to organic acid activity, while dissolution in the upper part is mainly influenced by atmospheric fresh water associated with the unconformity surface. The Yanchang Formation underwent hydrocarbon charging in three phases: the early Early Cretaceous, late Early Cretaceous, and middle Late Cretaceous. A model for hydrocarbon migration and accumulation in the Yanchang reservoirs was established based on the basin evolution. We suggest that hydrocarbon accumulation occurred at the early stage, and that hydrocarbons migrated into the upper part of the Yanchang Formation by way of tectonic fractures and overpressure caused by continuous and episodic hydrocarbon expulsion during secondary migration, forming potential oil reservoirs during the later stage.
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Carpenter, Chris. "3D Geological Model Creates Potential for Increased Production in Libyan Field." Journal of Petroleum Technology 73, no. 08 (August 1, 2021): 44–45. http://dx.doi.org/10.2118/0821-0044-jpt.

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This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 201417, “Reservoir Characterization and Geostatistical Model of the Cretaceous and Cambrian-Ordovician Reservoir Intervals, Meghil Field, Sirte Basin, Libya,” by Mohamed Masoud, Sirte Oil Company; W. Scott Meddaugh, SPE, Midwestern State University; and Masud Eljaroshi Masud, Sirte Oil Company, prepared for the 2020 SPE Annual Technical Conference and Exhibition, originally scheduled to be held in Denver, Colorado, 5–7 October. The paper has not been peer reviewed. The study outlined in the complete paper focuses on developing models of the Upper Cretaceous Waha carbonate and Bahi sandstone reservoirs and the Cambrian-Ordovician Gargaf sandstone reservoir in the Meghil field, Sirte Basin, Libya. The objective of this study is to develop a representative geostatistically based 3D model that preserves geological elements and eliminates uncertainty of reservoir properties and volumetric estimates. This study demonstrates the potential for significant additional hydrocarbon production from the Meghil field and the effect of heterogeneity on well placement and spacing. Introduction The reservoir of interest consists of three stratigraphic layers of different ages: the Waha and Bahi Formations and the Gargaf Group intersecting the Meghil field. The Waha reservoir is a porous limestone that forms a single reservoir with underlying Upper Cretaceous Bahi sandstone and Cambro-Ordovician Gargaf Group quartzitic sandstone. The Waha provides excel-lent reservoir characteristics. The Bahi has fair to good reservoir characteristics, while the Gargaf Group has very poor reservoir quality. The Waha and Bahi contain significant amounts of hydrocarbons. The Bahi is composed of erratically distributed detritus from the eroded Gargaf Group. The characteristic of the Gargaf sediments is quartzitic sandstones indurate to a quartzite with low reservoir quality.
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Trewin, Nigel H., Steven G. Fryberger, and Helge Kreutz. "The Auk Field, Block 30/16, UK North Sea." Geological Society, London, Memoirs 20, no. 1 (2003): 483–96. http://dx.doi.org/10.1144/gsl.mem.2003.020.01.39.

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AbstractThe Auk Field is located in Block 30/16 at the western margin of the Central Graben. Block 30/16 was awarded in June 1970 to Shell/Esso, and the discovery well 30/16-1 spudded in September 1970. The well found oil in a complex horst block sealed by Upper Cretaceous chalk and Tertiary claystones. The field contained an original oil column of up to 400 ft within Rotliegend sandstones, Zechstein dolomites, Lower Cretaceous breccia and Upper Cretaceous chalk. Production by natural aquifer drive commenced from a steel platform in 1976, initially from the Zechstein carbonates and now predominantly from the Rotliegend sandstone. Artificial lift was installed in 1988 helping to maintain production at economic levels past the year 2000. A complex reservoir architecture with cross flow between the Rotliegend and Zechstein reservoirs, a strong aquifer causing early water breakthrough via faults, and a limited seismic definition led to significant production variations from the initial forecasts. Equally important for the field, horizontal well technology opened up additional reserves and accelerated production from the complex Rotliegend reservoir; the most recent volumetric estimate for the total field predicts an ultimate recovery of 151 MMBBL for the existing wells from a STOIIP of 795 MMBBL. Full field reservoir simulation and 3D seismic data acquisition took place since mid 1980s but only recently resulted in a satisfactory understanding of the reservoir behaviour.The field is situated about 270 km ESE from Aberdeen in 240-270 ft of water. It covers a tilted horst block with an area of 65 km2, located at the western margin of the Central Graben. The Auk horst is bounded on the west by a series of faults with throws of up to 1000 ft, the eastern boundary fault has a throw of 5000 ft in the north reducing in throw southwards. The best reservoir lithology in the Zechstein is a vuggy fractured dolomite, and in the Rotliegend dune slipface sandstones provide the majority of the production. Both reservoirs and the overlying Lower Cretaceous breccia shared a common FWL at 7750 ft TVDss. The 38° API oil with a GOR of 190 SCF/STB was sourced from organic-rich Kimmeridge Clay.
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YALIZ, A. "The Crawford Field, Block 9/28a, UK North Sea." Geological Society, London, Memoirs 14, no. 1 (1991): 287–94. http://dx.doi.org/10.1144/gsl.mem.1991.014.01.35.

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AbstractThe Crawford Field was discovered in 1975 in UK Block 9/28 and the first oil was produced in April 1989. The field has a complex structural history. The reservoir is located on a down-faulted, westward tilting faultblock along the western margin of the Viking Graben. The eastern margin of the faultblock is severely truncated at Base Cretaceous level. The main producing zones comprise Middle Jurassic (Brent Group equivalent) and Triassic (Skagerrak Formation) sandstones. The seal is formed by Cretaceous marls and limestones. Reservoir quality and thickness are extremely variable, and drainage areas are limited. The reservoir fluid is a medium gravity oil having a thin gas cap. Oil in-place is in the order of 130 MMBBL but recovery factors are expected to be low.
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Naji, Hassan S., and Mohammed Khalil Khalil. "3D geomodeling of the Lower Cretaceous oil reservoir, Masila oil field, Yemen." Arabian Journal of Geosciences 5, no. 4 (November 16, 2010): 723–46. http://dx.doi.org/10.1007/s12517-010-0226-y.

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Pinnock, S. J., A. R. J. Clitheroe, and P. T. S. Rose. "The Captain Field, Block 13/22a, UK North Sea." Geological Society, London, Memoirs 20, no. 1 (2003): 431–41. http://dx.doi.org/10.1144/gsl.mem.2003.020.01.35.

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AbstractThe Captain Field is located in Block 13/22a in the Western Moray Firth Basin of the UK North Sea, 80 miles NE of Aberdeen in a water depth of 340 ft. Hydrocarbons are trapped in two geographical regions, the Main and Eastern closures, both with a significant stratigraphic pinchout component. The principal reservoirs consist of turbidite sandstones of Lower Cretaceous age which have been informally subdivided into two stratigraphic units comprising the Upper and Lower Captain Sandstones. At the base of the preserved Jurassic section the Heather Sandstone, Oxfordian in age, provides a secondary reservoir. Reservoir quality is uniformly excellent in the Lower Cretaceous with in situ, Klinkenberg corrected permeability averaging 7 Darcies and porosity in the range 28-34%. The reservoir is generally poorly consolidated sandstone with the depth to the crest of the field at -2700 ft TVDss. The reservoirs contain a total oil-in-place of 1000 MMBO. The Upper Captain Sandstone has a small associated gas cap containing 16 BCF gas-in-place. The oil is heavy, by North Sea standards, with oil gravity ranging from 19° to 21° API and has high in situ viscosity, 150 to 47 cP, at the mean reservoir temperature of 87°F. The fluid properties and offshore location necessitate the employment of innovative horizontal drilling methods, completion design and artificial lift technology in order to achieve an economically viable field development. Extended reach horizontal wells, with reservoir completion lengths of up to 8000 ft, are drilled for all oil producers and water injectors. Development risks were significantly reduced following two appraisal drilling campaigns in 1990 and 1993 culminating with the successful drilling and extended testing of a prototype horizontal field development well (13/22a-10). The field is being developed in two phases, Area A and Area B. First oil production commenced from the Captain platform in March 1997 from Area A and the field now produces at between 50000 and 70000 BOPD. Area B development is now underway with first oil planned for December 2000. Completion of this phase of the development will increase the plateau production rate to 85000 BOPD.
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Hodgins, B., D. J. Moy, and P. A. Carnicero. "The Captain Field, Block 13/22a, UK North Sea." Geological Society, London, Memoirs 52, no. 1 (2020): 705–16. http://dx.doi.org/10.1144/m52-2018-92.

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AbstractThe Captain Field in Block 13/22a is in the Moray Firth region of the UK North Sea. The primary reservoirs are Lower Cretaceous turbidite sandstones of the Captain Sandstone Member. Upper Jurassic shallower-marine Heather Formation sandstones of Oxfordian age provide a secondary reservoir. Total oil in place exceeds 1 Bbbl; however, the oil is heavy and viscous, requiring the continuous application of innovative technologies to maximize economic recovery from the field. Captain has been producing since 1997, with reservoir waterflood planned from the outset. Captain has been developed using long horizontal producers to maximize reservoir contact. Water injectors provide pressure support, with the aim of full voidage replacement. The Captain development has been phased with facilities consisting of two bridge-linked platforms, a floating production, storage and offloading vessel, and two subsea manifolds. Peak oil rate (100 000 boepd) was achieved in 2002. Average production in 2019 was 28 000 boepd. Captain is executing a chemical enhanced oil recovery (EOR) project, a first for the UK North Sea. Conventional waterflood yields an estimated ultimate recovery of 30–40%. Chemical EOR is expected to improve this by 5–20% in areas of the reservoir under polymer flood.
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Dissertations / Theses on the topic "Cretaceous oil reservoir"

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Thorpe, Dean Timothy. "Controls on reservoir quality in Early Cretaceous carbonate oil fields and implications for basin modelling." Thesis, University of Edinburgh, 2014. http://hdl.handle.net/1842/18014.

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Carbonate reservoirs hold more than 50 % of Earth’s remaining conventional hydrocarbon. However, recovery from these reservoirs is notoriously difficult due to the complex and multiple scales of porosity. This heterogeneity is a function of both the depositional environment and of subsequent diagenetic processes. This thesis examines the processes that have controlled the reservoir quality of three Early Cretaceous carbonate oil fields (A, B, and C), in particular the role of deposition, diagenesis and the timing of oil charge in controlling final properties. Results are then used to help provide a theoretical basis for the modelling and prediction of reservoir quality and to improve the calibration of basin models. Field A and B are stacked and highly compartmentalised giant oil fields in the U.A.E. that are dominated by muddy fabrics and have a highly variable porosity (0- 35 %) and permeability (0.01-830 mD). Although the depositional environment strongly determines the location of reservoirs extensive diagenesis, through cementation and dissolution, has greatly modified the porosity and permeability of the reservoirs. Bulk δ13C values obtained from the main pore occluding calcite and dolomite cements are similar to the δ13C values of bulk micrite for the reservoir interval in which they are now present. This suggests that the cements that are occluding the pore space in each stacked reservoir are locally sourced and implies that each reservoir behaves as a relatively closed system during cement precipitation. In-situ (SIMS) δ18OVPDB values were obtained for the complete calcite cementation history of multiple reservoirs in Field A and B. The δ18OVPDB values for the first (oldest) calcite cement zone in each reservoir can be related to the global δ18OVPDB marine curve during the Hauterivian-Aptian and to million-year scale major climatic cooling events. The δ18OVPDB values for successive cement zones then progressively decrease, which is related to successive precipitation as a result of increasing temperature during burial in a relatively closed system. In-situ (SIMS) δ18OVPDB data together with oil inclusion occurrence suggest that initial oil charge (from the Dukhan Formation), at ~ 55-45 Million years ago (Mya) in Field A, reduced the cementation rate in the oil reservoir and preserved porosity. Whereas in the coeval aquifer a large volume of cement precipitated, after oil entered the oil reservoir, that greatly reduced porosity. Furthermore, the most reduced δ18OVPDB and mMg/mCa values are obtained from the cements in the shallowest (youngest) reservoirs, suggesting that cementation ceased in the deepest reservoirs first. This can be related to hydrocarbon stopping cementation or to the complete occlusion of effective porosity in the older reservoirs prior to the younger. After calcite and dolomite cementation ceased in the reservoirs of Field A and B a large scale dissolution event has been identified which significantly enhanced porosity. This dissolution event is then followed by the precipitation of authigenic kaolinite. Basin modelling reveals that this dissolution event is likely to be related to the thermal maturation of sedimentary organic matter that is present within local intraformational seals and to the migration of organic acids prior to a second hydrocarbon charging event (at ~ 45 Mya). The aluminium, that is required for the formation of kaolinite, would then have been brought into the system by complexing with the organic compounds derived from this maturation event. Field C is an oil field located in offshore Brazil. The field is dominated by high energy facies that have porosities which range from 5 % to 39 %, and permeabilities from 0.1 mD to 8.1 D. The depositional poro-perm properties of the oil reservoir have undergone little diagenetic alteration; however, the aquifer is extensively cemented and the porosity is much reduced. All the cements identified, by both petrography and stable isotopic analyses, in the oil reservoir are early and are thought to have formed from a pore fluid similar to, or slightly evolved from, Early Cretaceous seawater. Basin modelling suggests that oil may have entered the field slightly after deposition (at ~105 Mya) and led to the preservation of high porosities and permeabilities in the oil reservoir by stopping cementation.
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Al, Harthi Amena Dhawi Juma Mayoof. "Dynamics of calcite cementation in response to oil charge and reservoir evolution, Thamama, Group, U.A.E." Thesis, University of Edinburgh, 2018. http://hdl.handle.net/1842/33102.

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Carbonate rocks consider as significant reservoirs for hydrocarbon. More than 60% of the world's hydrocarbon is placed in carbonate reservoirs. Carbonate rocks are heterogeneous and contain complex pore system. This complexity causes the hydrocarbon recovery from these reservoirs difficult; having less than 35% of hydrocarbon is being recovered. The heterogeneity and the variation in pore system are a result of various depositional settings and successive diagenetic overprints. Diagenetic overprints account for most of the pore system complexity in subsurface. This project undertakes one of the important diagenetic processes, calcite cementation, which though to have major impact on reservoir quality. The project aims to better understand the controls on calcite cementation in five Lower Cretaceous Reservoirs, in particular the role of calcite cementation with relation to oil charge in reservoir quality. Other diagenetic processes were also asses including dolomitization, dissolution, micritization and chemical compaction. The five reservoirs (A, B, C, F & G) are from Field A which is located in Abu Dhabi, UAE. The reservoirs comprise of interbedded porous "Reservoir" and low porosity-permeability "Dense" limestones deposited in broad range of settings, ranging from restricted to open marine platform. Reservoir intervals are part of HSTs, deposited during higher sea level time. The dense intervals were deposited during TST and thought to be cemented early resulting in early compartmentalization in all reservoirs. The mMg/Ca and in-situ (SIMS) δ18OVPDB were measured through complete calcite cement stratigraphy obtained from equant, syntaxial and blocky calcite in all reservoirs. Both mMg/Ca and δ18OVPDB of oldest calcite cement zone are matching with published mMg/Ca and δ18OVPDB of Lower Cretaceous, suggesting precipitation from Lower Cretaceous seawater. The mMg/Ca and δ18OVPDB also vary from reservoir to another reflecting change in Cretaceous seawater. These data also coincide with trace element observations particularly Mn and Sr. All these parameters show fluctuations in Cretaceous seawater during 135-123Ma caused by global changes in climate and oceanic crust production rates. Lower reservoirs including F (133Ma) and C (130Ma) were more probably affected by the Hauterivian global cooling which resulted in higher δ18OVPDB in the early precipitated cements. Precipitation in upper Reservoir B (126Ma) was most likely affected by the abrupt warm episode just before the OAE1. Reservoir A (123Ma) precipitation may be affected by the Early Aptian cooling episode and the OAE1. Reservoir G is the only one not recording δ18OVPDB similar of Cretaceous seawater. Cementation in Reservoir G was affected by depleted δ18OVPDB fluids from early stage, perhaps hot, basinal waters. More interestingly, the mMg/Ca, δ18OVPDB Mn and Sr means of younger calcite cement zones which thought to be evolved during burial show similar trend to the oldest cement zones with various offsets. This suggests that calcite cement in each reservoir evolved in a relatively close system inferring by this that the reservoirs are compartmentalized. The compartmentalization is probably due to the sysedimentary or early cemented hardgrounds in the Dense Zones. The Dense Zones acted as seals for the reservoirs from early stage causing the later precipitated calcite cement which is diagenetically affected to behave in predictable and similar way. Moreover, calcite precipitation temperatures inferred from mMg/Ca and δ18OVPDB show progressive increase towards younger cement zones indicating fluid evolution with burial in also relatively close system. In-situ δ18OVPDB and oil inclusions suggest earlier oil charge in the shallower reservoirs compared with deeper reservoirs and coeval water leg. Consequently, cementation in the shallower reservoirs continued with lower rate and hence preserved some primary and secondary pores. Conversely, in the water leg cementation continue to occlude most of the pore spaces. Furthermore, early oil emplacement in the shallower reservoirs increased the cementation temperature of calcite in the oil leg to reach maximum precipitation temperatures of ~144˚C. Whereas, in the water leg and deeper reservoirs, cementation continued to a temperature of ~110˚C. Overall, reservoir quality in Thamama Group was affected by various diagenetic processes. Some have resulted in reservoir quality enhancement such as dolimitization which involves formation of microporosity as a result of replacive rhombic dolomite, dissolution particularly the late one which believed to be due organic acid, and micritization with yield microporosity particularly in Reservoir B. Open fractures might have also enhanced reservoir quality to some extent. Diagenetic events that have deteriorated reservoir quality include calcite and saddle dolomite cementation as well as stylolitization. Greater calcite cementation can be found in water leg compared with oil leg because oil thought to decrease cementation rate.
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Asiashu, Mudau. "Sedimentological re-interpretation of the early cretaceous oil reservoir in the Northern Bredasdorp Basin, offshore South Africa." University of the Western Cape, 2015. http://hdl.handle.net/11394/5047.

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>Magister Scientiae - MSc
This study was aimed at determining the sedimentary environment, its evolution and facies areal distribution of the Upper Shallow Marine (USM, Late Valanginian). The study was conducted in wells E-S1, F-AH4 and E-W1 in the Bredasdorp basin between E-M and F-AH fields, located in a basinwards transect roughly transverse to the palaeocoast. The wells were studied by logging all the cores in detail between the chosen intervals, followed by facies analysis. Each core log was tied with its respective gamma ray and resistivity well logs. The logs were then correlated based on their log signatures, trends and facies interpretation. The Gamma ray logs show a fining-upwards and coarsening-upwards trend (“hour-glass shape”) in E-S1 and F-AH4 while in E-W1 it shows more accommodation space. These trends are believed to have been influenced by relative sea level changes, such as transgression and regression. Facies analysis identified seven facies in the study area: Facies A, B, C, D, E, F and G. Facies A, B and C were interpreted as fair-weather and storm deposits of the offshore-transition zone, shoreface and foreshore respectively. Facies D was considered as lagoonal mud deposits, while Facies E and F were interpreted as tidal channel and tidal bar deposits respectively. Finally Facies G was considered as fluvial channel deposits. The facies inferred that the sedimentary environment of the study area is a wave-dominated estuary or an Island-bar lagoon system. This led to the production of a conceptual model showing the possible locations for the three wells in the Island bar-lagoon system. The conceptual model inferred the previous findings from PGS (1999) report, that the Upper Shallow Marine beds were deposited in a tidal/estuarine to shoreface setting. This model also supports the findings of Magobiyane (2014), which proposed a wave-dominated estuary for the Upper Shallow Marine reservoir between E-M and F-AH fields, located west of the study area.
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Ball, Nathaniel H. Atchley Stacy C. "Depositional and diagenetic controls on reservoir quality and their petrophysical predictors within the Upper Cretaceous (Cenomanian) Doe Creek Member of the Kaskapau Formation at Valhalla Field, Northwest Alberta." Waco, Tex. : Baylor University, 2009. http://hdl.handle.net/2104/5296.

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Elazezi, Mohamed Massoud. "Seismic reflection characteristics of the Precambrian and Upper Cretaceous reservoirs in Nafoora-Augila oil field, Sirte Basin, Libya." Thesis, University of Aberdeen, 1992. http://ethos.bl.uk/OrderDetails.do?uin=uk.bl.ethos.305254.

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The research project aimed to establish the seismic characteristics of the Upper Cretaceous and Precambrian basement reservoirs in the area of the Nafoora-Augila field. The characteristics studied include acoustic impedance, amplitude, phase, and reflection strength, derived from seismic profiles closely tied to well data. The project demonstrates to a certain degree the successful use of combined techniques to assist in the interpretation of the seismic data by improving its quality. The techniques included: one-dimensional and two-dimensional modelling, seismic attributes and seismic inversion techniques. The generated synthetic seismograms show a reasonably good match with observed seismic data at the well locations. The mismatch between reflection interfaces at some intervals indicated that it could be the result of inaccurate sonic measurements. Investigation on the sonic readings was conducted in the laboratory by measuring the transit time for core samples obtained from these intervals. The laboratory measurements generally supported the sonic. Two-dimensional modelling was carried out in order to compare synthetic sections with the observed seismic sections. The comparison indicated that model sections can be used for the recognition and confirmation of the reflection events of interest in the observed seismic sections and especially the seismic expression of the thin layers such as the Rachmat shale and the Bahi sandstone. The presence of multiples on the final seismic sections has obscured the primary reflection events of interest. Velocity analysis using the velocity spectra technique is conducted to improve the stack of the seismic data and minimize the effect of multiples. The newly picked stacking velocities show better results than those picked by the contractor by using the velocity function technique. The post-stack deconvolution was applied to attenutate the existing multiples by testing different deconvolution parameters. The tested parameters gave very encouraging results by bringing out distinctive reflectors and suppressing multiples. Seismic attributes and inverse modelling were used to enhance the interpretation of the seismic data. The use of the attributes on the observed seismic data are generally of little use due to the poor quality of the data. However, the amplitude and the phase displays show a reasonably good response even with the effect of noise and multiples. Comparison of pseudo impedance logs and sections with well impedance logs and seismic sections shows fair to reasonably good comparison.
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Jenkins, C. C. "The organic geochemical correlation of crude oils from early Jurassic to late Cretaceous Age reservoirs of the Eromanga Basin and late Triassic Age reservoirs of the underlying Cooper Basin /." Title page, contents and abstract only, 1987. http://web4.library.adelaide.edu.au/theses/09SM/09smj521.pdf.

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Dokur, Merve. "Reservoir characterization of the Upper Cretaceous Woodbine Group in Northeast East Texas Field, Texas." Thesis, 2012. http://hdl.handle.net/2152/ETD-UT-2012-05-5202.

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East Texas field, a giant U.S. oil-field, produced 5.42 billion stock-tank barrels from discovery in 1930 through mid-2007. The lower part of the siliciclastic Upper Cretaceous Woodbine Group is reservoir rock, and almost all production comes from the upper unit, the operator-termed Main sand. The field could produce 70 million stock-tank barrels (MMSTB) using current strategies, whereas 410 MMSTB of remaining reserves from the Stringer zone (lower unit), along with bypassed pay in both units and unswept oil, is possible. These favorable statistics have increased interest in reservoir characterization of the Woodbine, especially the Stringer zone. This study delineates sandstone geometry and interprets reservoir facies and heterogeneity of the Stringer zone and Main sand in northeast East Texas field. Additional objectives are to define key chronostratigraphic surfaces, such as flooding surfaces and unconformities, and to establish a realistic depositional model for the reservoir succession. To achieve these objectives, well log analysis, core description, and net-sandstone mapping of the Stringer zone and Main sand were conducted. According to sequence-stratigraphic and depositional-system analysis, the Woodbine Group is divided into two genetically unrelated units: (1) the highstand deltaic Stringer zone and (2) the lowstand incised-valley-fill Main sand. Principal reservoir units are Stringer 1 and Stringer 2 sands within the Stringer zone and the Main sand. Stringer 2, best developed in the southwest study area, is the most promising reservoir unit for new production. Well deepening and water-flooding in this more continuous and thicker sand are proposed to increase production in East Texas field.
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Nair, Narayan Gopinathan 1980. "Measurement and modeling of multiscale flow and transport through large-vug Cretaceous carbonates." 2008. http://hdl.handle.net/2152/17994.

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Many of the world's oil fields and aquifers are found in carbonate strata. Some of these formations contain vugs or cavities several centimeters in size. Flow of fluids through such rocks depends strongly upon the spatial distribution and connectivity of the vugs. Enhanced oil recovery processes such as enriched gas drives and groundwater remediation efforts like soil venting operations depend on the amount of hydrodynamic dispersion of such rocks. Selecting a representative scale to measure permeability and dispersivity in such rocks can be crucial because the connected vug lengths can be longer than typical core diameters. Large touching vug (centimeter-scale), Cretaceous carbonate rocks from an exposed rudist (caprinid) reef buildup at the Pipe Creek Outcrop in Central Texas were studied at three different scales. Single-phase airflow and gas-tracer experiments were conducted on 2.5 in. diameter by 5 in. long cores (core-scale) and 5- to 10-ft-radius well tests (field-scale). Zhang et al. (2005) studied a 10 in. diameter by 14 in. high sample (bench-scale). Vertical permeability in the bench-scale varied from 100 darcies to 10 md and in the core-scale averaged 2.5 darcies. The field-scale permeability was estimated to be 500 md from steady state airflow and pressure transient tests. In the bench and core scales a connected path of vugs dominates flow and tracer concentration breakthrough profile. Tracer transport showed immediate breakthrough times and a long tail in the tracer concentrations characterized by multiple plateaus in concentrations. Neither flow nor tracer transport can be explained at these scales by the standard continuum equations (Darcy’s law or 1D convection dispersion equation). However, interpreting field-scale measurements with standard continuum equations suggested that a strongly connected path of vugs did not extend past a few feet. In particular, the tracer experiment in the field scale can be modeled accurately using an equivalent homogeneous porous medium with a dispersivity of 0.5 ft. In our measurements, permeability decreased with scale, while vug connectivity and multi-scale effects associated with vug connectivity decreased with increasing scale. We concluded that approximately 5 ft could be considered the representative scale for the large-touching-vug carbonate rocks at the Pipe Creek Outcrop. The major contribution of this research is the introduction of an integrated, multi-scale, experimental approach to understanding fluid flow in carbonate rocks with interconnected networks of vugs too large to be adequately characterized in core samples alone.
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Books on the topic "Cretaceous oil reservoir"

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Higley, Debra K. Petrology and reservoir paragenesis in the Sussex "B" sandstone of the Upper Cretaceous Cody Shale, House Creek and Porcupine fields, Powder River Basin, Wyoming. Washington: U.S. G.P.O., 1992.

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Tyler, Noel. Genetic stratigraphy and oil recovery in an upper Cretaceous wave-dominated Deltaic Reservoir, Big Wells (San Miguel) Field, south Texas. Austin, Tex: Bureau of Economic Geology, University of Texas at Austin, 1986.

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Hansley, Paula L. Petrology, diagenesis, and sedimentology of oil reservoirs in Upper Cretaceous Shannon Sandstone Beds, Powder River Basin, Wyoming. Washington, D.C: U.S. G.P.O., 1991.

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Book chapters on the topic "Cretaceous oil reservoir"

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Bagnoli, Eduardo. "The Mossoró Sandstone, Canto do Amaro Oil Field, Late Cretaceous of the Potiguar Basin, Brazil: An Example of a Tidal Inlet-Channel Reservoir." In Frontiers in Sedimentary Geology, 183–99. New York, NY: Springer New York, 1993. http://dx.doi.org/10.1007/978-1-4757-0160-9_9.

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LONGACRE, SUSAN A., and ELLIOTT P. GINGER. "EVOLUTION OF THE LOWER CRETACEOUS RATAWI OOLITE RESERVOIR, WAFRA FIELD, KUWAIT-SAUDI ARABIA PARTITIONED NEUTRAL ZONE." In Giant Oil and Gas Fields, 273–331. SEPM (Society for Sedimentary Geology), 1988. http://dx.doi.org/10.2110/cor.88.12.0273.

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WHEELER, DAVID M., EDMUND R. GUSTASON, and MARIAN J. FURST. "THE DISTRIBUTION OF RESERVOIR SANDSTONE IN THE LOWER CRETACEOUS MUDDY SANDSTONE, HILIGHT FIELD, POWDER RIVER BASIN, WYOMING." In Giant Oil and Gas Fields, 179–228. SEPM (Society for Sedimentary Geology), 1988. http://dx.doi.org/10.2110/cor.88.12.0179.

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Gaynor, Gerard C., and Mark H. Scheihing. "SHELF DEPOSITIONAL ENVIRONMENTS AND RESERVOIR CHARACTERISTICS OF THE KUPARUK RIVER FORMATION (LOWER CRETACEOUS), KUPARUIC FIELD, NORTH SLOPE, ALASKA." In Giant Oil and Gas Fields, 333–89. SEPM (Society for Sedimentary Geology), 1988. http://dx.doi.org/10.2110/cor.88.12.0333.

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McBride, Earle F. "INFLUENCE OF BASIN HISTORY ON RESERVOIR QUALITY OF SANDSTONES: UPPER CRETACEOUS OF NORTHERN MEXICO." In Habitat of Oil and Gas in the Gulf Coast. SEPM Society for Sedimentary Geology, 1985. http://dx.doi.org/10.5724/gcs.85.04.0119.

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Strohmenger, Christian J., Ahmed Ghani, Omar Al-Jeelani, Abdulla Al-Mansoori, Taha Al-Dayyani, L. Jim Weber, Khalil Al-Mehsin, Lee Vaughan, Sameer A. Khan, and John C. Mitchell. "High-resolution Sequence Stratigraphy and Reservoir Characterization of Upper Thamama (Lower Cretaceous) Reservoirs of a Giant Abu Dhabi Oil Field, United Arab Emirates." In Giant Hydrocarbon Reservoirs of the WorldFrom Rocks to Reservoir Characterization and Modeling. American Association of Petroleum Geologists, 2006. http://dx.doi.org/10.1306/1215876m883271.

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Hector, Scott, Karen Blake, and Tim Elam. "Petroleum occurrences in the Mount Diablo area, California." In Regional Geology of Mount Diablo, California: Its Tectonic Evolution on the North America Plate Boundary. Geological Society of America, 2021. http://dx.doi.org/10.1130/2021.1217(06).

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ABSTRACT Mount Diablo is flanked on its northeast side by a thick section of Late Cretaceous and Tertiary sedimentary rocks, which produced small hydrocarbon accumulations in the Los Medanos, Willow Pass, Mulligan Hill, and Concord gas fields. The first well was drilled in 1864, and today most of the active wells on the northeast flank are used for gas storage by Pacific Gas and Electric Company. These fields, which also include the Brentwood oil field, lie to the northeast of Mount Diablo and have produced 6.4 million cubic meters (225 billion cubic feet) of natural gas and over 57 million cubic meters (9.1 million barrels) of oil. The main reservoirs for the Sacramento Basin are sandstones in the Late Cretaceous and Paleogene section. The source rock there is primarily from the Upper Cretaceous Dobbins Shale, which began generation 75 m.y. ago, and the Winters Shale, which began generation 35 m.y. ago. The Livermore Basin is located on the western and southwestern sides of the mountain. The only commercial field in that basin is the small Livermore oil field. This field produces primarily from Miocene sandstones. The Livermore Basin is a Neogene basin that was syntectonically formed in the last few million years and continues to grow today. Studies of the black oils found in the Livermore field show that the source rock is likely the Eocene Nortonville Shale, though the Upper Cretaceous Moreno shale is also considered to be a possible source. The Livermore field has produced 12 million cubic meters of oil (1.9 million barrels).
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Uygur, Kadir, Huseyin Is, and M. Arif Yükler. "Reservoir Characterization of Cretaceous Mardin Group Carbonates in Bölükyayla-Cukurtas and Karakus Oil Fields, SE TurkeyA Petrographic and Petrophysical Comparison of Overthrust and Foreland Zones." In Seals, Traps, and the Petroleum System. American Association of Petroleum Geologists, 1997. http://dx.doi.org/10.1306/m67611c11.

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Conference papers on the topic "Cretaceous oil reservoir"

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Venkitadri, Varavur Sankar, Hesham T. Shebl, Toshiaki Shibasaki, Chawki Ali Dabbouk, and Salman Mohamed Salman. "Reservoir Rock Type Definition In A Giant Cretaceous Carbonate." In SPE Middle East Oil and Gas Show and Conference. Society of Petroleum Engineers, 2005. http://dx.doi.org/10.2118/93477-ms.

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Okasha, T. M., J. J. Funk, and S. M. Al-Enezi. "Wettability and Relative Permeability of Lower Cretaceous Carbonate Rock Reservoir, Saudi Arabia." In Middle East Oil Show. Society of Petroleum Engineers, 2003. http://dx.doi.org/10.2118/81484-ms.

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Rassas, Sami, Antonio Valle, and Magdi Metwalli Hassen. "Waterflood Geocellular Model of a Giant Carbonate Reservoir in the Lower Cretaceous." In SPE Middle East Oil and Gas Show and Conference. Society of Petroleum Engineers, 2005. http://dx.doi.org/10.2118/93745-ms.

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Gomes, Jorge, Jane Mason, and Graham Edmonstone. "Value of DTS in Multi-Stacked Reservoirs to Better Understand Injectivity and Water Flood Effectiveness – A Field Example from the UAE." In SPE Annual Technical Conference and Exhibition. SPE, 2021. http://dx.doi.org/10.2118/206103-ms.

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This paper highlights the application of downhole fiber optic (FO) distributed temperature sensing (DTS) measurements for well and reservoir management applications: 1) Wellbore water injectivity profiling. 2) Mapping of injection water movement in an underlying reservoir. The U.A.E. field in question is an elongated anticline containing several stacked carbonate oil bearing reservoirs (Figure 1). Reservoir A, where two DTS monitored, peripheral horizontal water injectors (Y-1 and Y-2) were drilled, is less developed and tighter than the immediately underlying, more prolific Reservoir B with 40 years of oil production and water injection history. Reservoirs A and B are of Lower Cretaceous age, limestone fabrics made up of several 4th order cycles, subdivided by several thin intra dense, 2-5 ft thick stylolitic intervals within the reservoir zones. Between Reservoir A and Reservoir B there is a dense limestone interval (30-50 ft), referred as dense layer in the Figure 1 well sections.
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Aldabal, M. A., and A. S. Alsharhan. "Geological Model and Reservoir Evaluation of the Lower Cretaceous Bab Member in the Zakum Field, Abu Dhabi, U.A.E." In Middle East Oil Show. Society of Petroleum Engineers, 1989. http://dx.doi.org/10.2118/18007-ms.

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Grotsch, Jurgen, Omar Al-Jelani, and Yousif Al-Mehairi. "Integrated Reservoir Characterisation of a Giant Lower Cretaceous Oil Field, Abu Dhabi, U.A.E." In Abu Dhabi International Petroleum Exhibition and Conference. Society of Petroleum Engineers, 1998. http://dx.doi.org/10.2118/49454-ms.

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Mahmoud, Sabry Lotfy, Magdy Ahmed H. Hozayen, and El Sayed Moustafa Radwan. "Seismic Attribute Utilization for FFDP Well Placement Optimization, Upper Cretaceous Fractured Complex Carbonate Reservoir, Onshore Oil Field, U.A.E." In SPE Reservoir Characterization and Simulation Conference and Exhibition. Society of Petroleum Engineers, 2013. http://dx.doi.org/10.2118/166015-ms.

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Davletova, E., K. Zverev, I. Buyakina, and N. Nassonova. "Facies Analysis and Reservoir Properties of Early Cretaceous Beds in Samotlor Field, West Siberia Basin." In Tyumen 2013 - New Geotechnology for the Old Oil Provinces. Netherlands: EAGE Publications BV, 2013. http://dx.doi.org/10.3997/2214-4609.20142755.

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Duran, O., K. Gürgey, and I. Sezgin. "Reservoir Characterization, Source and Crude Oil Properties of Upper Cretaceous Rocks in SE Anatolta." In 57th EAEG Meeting. Netherlands: EAGE Publications BV, 1995. http://dx.doi.org/10.3997/2214-4609.201409622.

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Strohmenger, Christian Johannes, Taha Al-Dayyani, Andrew Brampton S. Clark, Ahmed A. Ghani, and Hafez H. Hafez. "Sequence Stratigraphy-Based Geological Modeling of Upper Thamama (Lower Cretaceous) Reservoirs of a Giant Abu Dhabi Oil Field, United Arab Emirates." In SPE/EAGE Reservoir Characterization and Simulation Conference. Society of Petroleum Engineers, 2007. http://dx.doi.org/10.2118/111401-ms.

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Reports on the topic "Cretaceous oil reservoir"

1

Chidsey, Thomas C., David E. Eby, Michael D. Vanden Berg, and Douglas A. Sprinkel. Microbial Carbonate Reservoirs and Analogs from Utah. Utah Geological Survey, July 2021. http://dx.doi.org/10.34191/ss-168.

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Multiple oil discoveries reveal the global scale and economic importance of a distinctive reservoir type composed of possible microbial lacustrine carbonates like the Lower Cretaceous pre-salt reservoirs in deepwater offshore Brazil and Angola. Marine microbialite reservoirs are also important in the Neoproterozoic to lowest Cambrian starta of the South Oman Salt Basin as well as large Paleozoic deposits including those in the Caspian Basin of Kazakhstan (e.g., Tengiz field), and the Cedar Creek Anticline fields and Ordovician Red River “B” horizontal play of the Williston Basin in Montana and North Dakota, respectively. Evaluation of the various microbial fabrics and facies, associated petrophysical properties, diagenesis, and bounding surfaces are critical to understanding these reservoirs. Utah contains unique analogs of microbial hydrocarbon reservoirs in the modern Great Salt Lake and the lacustrine Tertiary (Eocene) Green River Formation (cores and outcrop) within the Uinta Basin of northeastern Utah. Comparable characteristics of both lake environments include shallowwater ramp margins that are susceptible to rapid widespread shoreline changes, as well as compatible water chemistry and temperature ranges that were ideal for microbial growth and formation/deposition of associated carbonate grains. Thus, microbialites in Great Salt Lake and from the Green River Formation exhibit similarities in terms of the variety of microbial textures and fabrics. In addition, Utah has numerous examples of marine microbial carbonates and associated facies that are present in subsurface analog oil field cores.
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Jennie Ridgley. ANALYSIS OF OIL-BEARING CRETACEOUS SANDSTONE HYDROCARBON RESERVOIRS, EXCLUSIVE OF THE DAKOTA SANDSTONE, ON THE JICARILLA APACHE INDIAN RESERVATION, NEW MEXICO. Office of Scientific and Technical Information (OSTI), May 2000. http://dx.doi.org/10.2172/834191.

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Jennie Ridgley. ANALYSIS OF OIL-BEARING CRETACEOUS SANDSTONE HYDROCARBON RESERVOIRS, EXCLUSIVE OF THE DAKOTA SANDSTONE, ON THE JICARILLA APACHE INDIAN RESERVATION, NEW MEXICO. Office of Scientific and Technical Information (OSTI), January 2000. http://dx.doi.org/10.2172/834192.

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Ridgley, Jennie, and Robyn Wright Dunbar. Analysis of oil-bearing Cretaceous sandstone hydrocarbon reservoirs, exclusive of the Dakota Sandstone, on the Jicarilla Apache Indian Reservation, New Mexico. Office of Scientific and Technical Information (OSTI), June 2000. http://dx.doi.org/10.2172/756282.

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Obermajer, M., C. Jiang, and M. G. Fowler. Organic geochemical data from Western Canada. Part I: gasoline range and saturate fraction gas chromatograms of selected crude oils from Jurassic and Cretaceous reservoirs in southern Alberta. Natural Resources Canada/ESS/Scientific and Technical Publishing Services, 2018. http://dx.doi.org/10.4095/308347.

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Petrology, diagenesis, and sedimentology of oil reservoirs in Upper Cretaceous Shannon Sandstone Beds, Powder River basin, Wyoming. US Geological Survey, 1990. http://dx.doi.org/10.3133/b1917c.

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