Relevant bibliographies by topics / Hydrocarbon reservoirs

Contents

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

Academic literature on the topic 'Hydrocarbon reservoirs'

Author: Grafiati
Published: 4 June 2021
Last updated: 1 August 2024

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Journal articles on the topic "Hydrocarbon reservoirs"

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Lü, Xiuxiang, Weiwei Jiao, Xinyuan Zhou, Jianjiao Li, Hongfeng Yu, and Ning Yang. "Paleozoic Carbonate Hydrocarbon Accumulation Zones in Tazhong Uplift, Tarim Basin, Western China." Energy Exploration & Exploitation 27, no. 2 (April 2009): 69–90. http://dx.doi.org/10.1260/0144-5987.27.2.69.

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Diverse types of marine carbonate reservoirs have been discovered in the Tazhong Uplift, Tarim Basin, and late alteration of such reservoirs is obvious. The marine source rocks of the Cambrian-lower Ordovician and the middle-upper Ordovician provided abundant oil and gas for hydrocarbon accumulation. The hydrocarbons filled various reservoirs in multiple stages to form different types of reservoirs from late Caledonian to early Hercynian, from late Hercynian to early Indosininan and from late Yanshanian to Himalayan. All these events greatly complicated hydrocarbon accumulation. An analysis of the discovered carbonate reservoirs in the Tazhong Uplift indicated that the development of a reservoir was controlled by subaerial weathering and freshwater leaching, sedimentation, early diagenesis, and alteration by deep fluids. According to the origin and lateral distribution of reservoir beds, the hydrocarbon accumulation zones in the Tazhong area were identified as: karsted reservoirs, reef/bank reservoirs, dolomite interior reservoirs, and hydrothermal reservoirs. Such carbonate hydrocarbon accumulation zones are distributed mainly in specific areas of the Tazhong uplift, respectively. Because of differences in the mechanism of reservoir formation, the reservoir space, capability, type and distribution of reservoirs are often different in different carbonate hydrocarbon accumulation zones.
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Li, Xiaoshan, Hong Pan, Yuxiao Wu, Guanxing Luo, Junqiang Song, Liu Yang, Kaifang Gu, et al. "Main Control Factors and Hydrocarbon Accumulation Model of Volcanic Oil Reservoirs with Complex Oil–Water Relationships: A Case Study of the Carboniferous in the Chepaizi Uplift, the Junggar Basin, China." Minerals 12, no. 11 (October 26, 2022): 1357. http://dx.doi.org/10.3390/min12111357.

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In order to study the main control factors of volcanic reservoirs with complex oil–water relationships, the Carboniferous in the Chepaizi Uplift of the Junggar Basin was taken as an example and the lithofacies characteristics, main control factors, and hydrocarbon accumulation model of volcanic reservoirs were investigated by combining the petroleum geology with field testing (data of core analysis, well logging, formation testing, and production testing). The results show that the Carboniferous in the Chepaizi Uplift experienced three stages of volcanic activities and developed seven volcanic lithofacies bodies, distributed in a bead-string connected planar form along the Hongche fault. There is no unified oil–water interface across the whole study area and there are multiple oil–water systems within one fault block. The Carboniferous volcanic reservoir experienced two stages of hydrocarbon accumulation from two different source rocks. The distribution of faults penetrating hydrocarbon kitchens and source rocks controls the macro-scale distribution of reservoirs. The physical properties of reservoirs affect the pattern of oil and water differentiation in volcanic rock bodies, while the lithofacies body-controlled hydrocarbon accumulation mode highlighting “one rock body for one reservoir” determines the distribution of reservoirs. The matching between the paleo-structure and hydrocarbon accumulation stage controls the accumulation and adjustment of hydrocarbon distribution. The Permian source rocks in the Shawan Sag serve as the lateral hydrocarbon supply and hydrocarbons accumulate in the Carboniferous structural-lithologic traps, which are summarized as the two stages of hydrocarbon accumulation of newly generated hydrocarbons into older reservoir rocks. This study of the hydrocarbon accumulation pattern in volcanic rocks aims at guiding the development of Carboniferous reservoirs with complex oil and water relationships in this area.
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Chen, Junqing, Xiongqi Pang, and Zhenxue Jiang. "Controlling factors and genesis of hydrocarbons with complex phase state in the Upper Ordovician of the Tazhong Area, Tarim Basin, China." Canadian Journal of Earth Sciences 52, no. 10 (October 2015): 880–92. http://dx.doi.org/10.1139/cjes-2014-0209.

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Seven hydrocarbon reservoirs have been discovered to date in the Upper Ordovician of the Tazhong Area, a region in which hydrocarbon phase distribution is complex. In the present study, the genesis and controlling factors of the hydrocarbons with complex phase in the Tazhong Area were investigated on the basis of the geological and geochemical conditions required for the formation and distribution of hydrocarbon reservoirs, integrated with the source rock geochemistry, natural gas and oil properties, and oil and gas reservoir fluid tests PVT (i.e., pressure, volume, and temperature tests). The results indicate that hydrocarbon reservoir types in the Upper Ordovician of the Tazhong Area transition from unsaturated to saturated condensate-gas reservoirs from west to east and from condensate-gas reservoirs to unsaturated-oil reservoirs from north to south. The crude oil in the region originated primarily from the mixing of Lower–Middle Cambrian and Middle–Upper Ordovician source rocks, while the natural gas was sourced primarily from the cracking gas of Lower–Middle Cambrian crude oil. This hydrocarbon-phase distribution was controlled primarily by temperature and pressure and has been affected by multiple periods of hydrocarbon accumulation and alteration. The high-quality Lower–Middle Cambrian reservoir–cap assemblage may be an important target for future exploration of natural gas in the Tazhong Area.
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Lerche, Ian. "Hydrocarbon Flow-up Intersecting Faults: Leakage/Production and Bypass Considerations." Energy Exploration & Exploitation 23, no. 4 (August 2005): 225–43. http://dx.doi.org/10.1260/014459805775219157.

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This article considers flow of hydrocarbons up a master fault that bifurcates and allows the hydrocarbons to enter or bypass reservoirs on either side of the bifurcated fault. In addition, leakage (or production) from each reservoir is allowed with a finite time span for the leakage. The rates of leakage from the two reservoirs are also allowed to be different so that the reservoirs either may fill, with concomitant bypass of excess hydrocarbons, or may be drained so rapidly by the leakage that they fill only partially. The timing of the leakage in respect of the timing of hydrocarbon fill is also included so that one can see how the differences in onset and end times of the leakage in relation to end time of the hydrocarbon supply influence the final fill of each reservoir. Uncertainties associated with each of the parameters entering the assessments are also allowed for, so that one can determine which of the uncertain parameters is causing the greatest uncertainty in estimates of the reservoir fill and bypass.
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Ojo, Odunayo Tope. "Petrophysical and Geomechanical Analysis to Delineating Reservoirs in the Miocene Niger Delta Region of Nigeria." Geoinformatica Polonica 22 (December 1, 2023): 105–21. http://dx.doi.org/10.4467/21995923gp.23.009.18608.

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The application of various petrophysical and elastic metrics has advanced reservoir characterization and provided critical geological formation information. Porosity declines with depth, according to sonic, neutron, and density logs. Lithology, pressure, and hydrocarbons all contribute to this. Formation resistivity and fluid saturation are used to identify hydrocarbon-bearing zones. Because oil and gas are non-conductive, hydrocarbon-containing rocks are more resistant than water. In lithological categorization, gamma logs and the Vp/Vs ratio have helped classify reservoirs as Agbada Formation sand-shale reservoirs. Reservoir elastic characteristics, specifically sandstones, have been studied at various depths. These discoveries have an impact on their brittleness, strength, and failure risk in a variety of scenarios. Hydrocarbon accumulation has been influenced by diagenetic compaction equilibrium in pressure-exposed shale source beds. The research advances our understanding of the geological formations of the Niger Delta and gives practical insights for exploration and production. Decisions on oil and gas are based on hydrocarbon reservoir assessments at various depths, including porosity, fluid saturation, and lithology. Well logs from Wells B001, B002, and B003 revealed the diverse properties of several Niger Delta reservoirs. These discoveries have benefited hydrocarbon exploration and production decision-making significantly.
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Peng, Biao, Lulu Zhang, Jianfeng Li, Tiantian Chang, and Zheng Zhang. "Multi-Type Hydrocarbon Accumulation Mechanism in the Hari Sag, Yingen Ejinaqi Basin, China." Energies 15, no. 11 (May 27, 2022): 3968. http://dx.doi.org/10.3390/en15113968.

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With the successful development of unconventional hydrocarbons, the production of unconventional hydrocarbons has increased rapidly. However, a single conventional or unconventional model is not suitable for the mechanism of hydrocarbon accumulation in a given basin or sag. Based on data from drilling, logging, and geophysical analysis, the hydrocarbon accumulation mechanism in the Hari sag in the Yingen-Ejinaqi basin, China, was analyzed. There are three sets of source rocks in the Hari sag: the K1y source rocks were evaluated as having excellent source rock potential with low thermal maturity and kerogen Type I-II1; the K1b2 source rocks were evaluated as having good source rock potential with mature to highly mature stages and kerogen Type II1-II2; and the K1b1 source rocks were evaluated as having moderate source rock potential with mature to highly mature stages and kerogen Type II1-II2. Reservoir types were found to be conventional sand reservoirs, unconventional carbonate-shale reservoirs, and volcanic rock reservoirs. There were two sets of fault-lithologic traps in the Hari sag, which conform to the intra-source continuous hydrocarbon accumulation model and the approaching-source discontinuous hydrocarbon accumulation model. The conclusions of this research provide guidance for exploring multi-type reservoirs and multi-type hydrocarbon accumulation models.
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Mujakperuo, B. J. O., and O. J. Airen. "Pressure volume temperature evaluation of Sapele Field, Niger Delta, Southern Nigeria." Environmental Technology and Science Journal 15, no. 1 (June 24, 2024): 168–75. http://dx.doi.org/10.4314/etsj.v15i1.17.

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Sapele field is a large, brown field with complex subsurface structure that has led to heavy compartmentalization of its reservoirs which has also resulted to low reservoir pressure in some parts of the field leading to low production output. Reservoirs were delineated at various depth, some at near surface area (Benin formation) while others at greater depth (Agbada formation), hence the field was further subdivided into two (Sapele Shallow and Sapele Deep) due to its structural complexity. Pressure Volume Temperature (PVT) laboratory analysis on different wells was available for this study and the viscosity of the reservoir fluid was measured using an Electromagnetic Viscometer (EMV) at reservoir temperatures of 129 0F and 207 0F. These data were used in determining hydrocarbon chemical composition, its viscosity, specific gravity, density, and American Petroleum Institute (API) unit. Sapele Shallow reservoir is made up of heavy oil as its hydrocarbon content as a result of biodegradation process in which micro-organisms degrade the light hydrocarbons due to the shallow nature of the reservoir in the field, making it rich in heavy molecular weight hydrocarbon compounds. While Sapele Deep is made up of heavily compartmentalized reservoirs with gas and light oil as its hydrocarbon content. Hence the field requires different exploitation and production approach to fully annex its reservoir hydrocarbon content.
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Rashid, Muhammad, Miao Luo, Umar Ashraf, Wakeel Hussain, Nafees Ali, Nosheen Rahman, Sartaj Hussain, Dmitriy A. Martyushev, Hung Vo Thanh, and Aqsa Anees. "Reservoir Quality Prediction of Gas-Bearing Carbonate Sediments in the Qadirpur Field: Insights from Advanced Machine Learning Approaches of SOM and Cluster Analysis." Minerals 13, no. 1 (December 24, 2022): 29. http://dx.doi.org/10.3390/min13010029.

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The detailed reservoir characterization was examined for the Central Indus Basin (CIB), Pakistan, across Qadirpur Field Eocene rock units. Various petrophysical parameters were analyzed with the integration of various cross-plots, complex water saturation, shale volume, effective porosity, total porosity, hydrocarbon saturation, neutron porosity and sonic concepts, gas effects, and lithology. In total, 8–14% of high effective porosity and 45–62% of hydrocarbon saturation are superbly found in the reservoirs of the Eocene. The Sui Upper Limestone is one of the poorest reservoirs among all these reservoirs. However, this reservoir has few intervals of rich hydrocarbons with highly effective porosity values. The shale volume ranges from 30 to 43%. The reservoir is filled with effective and total porosities along with secondary porosities. Fracture–vuggy, chalky, and intracrystalline reservoirs are the main contributors of porosity. The reservoirs produce hydrocarbon without water and gas-emitting carbonates with an irreducible water saturation rate of 38–55%. In order to evaluate lithotypes, including axial changes in reservoir characterization, self-organizing maps, isoparametersetric maps of the petrophysical parameters, and litho-saturation cross-plots were constructed. Estimating the petrophysical parameters of gas wells and understanding reservoir prospects were both feasible with the methods employed in this study, and could be applied in the Central Indus Basin and anywhere else with comparable basins.
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Zhao, Shuangfeng, Wen Chen, Zhenhong Wang, Ting Li, Hongxing Wei, and Yu Ye. "Fluid geochemistry of the Jurassic Ahe Formation and implications for reservoir formation in the Dibei area, Tarim Basin, northwest China." Energy Exploration & Exploitation 36, no. 4 (February 22, 2018): 801–19. http://dx.doi.org/10.1177/0144598718759560.

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The condensate gas reservoirs of the Jurassic Ahe Formation in the Dibei area of the Tarim Basin, northwest China are typical tight sandstone gas reservoirs and contain abundant resources. However, the hydrocarbon sources and reservoir accumulation mechanism remain debated. Here the distribution and geochemistry of fluids in the Ahe gas reservoirs are used to investigate the formation of the hydrocarbon reservoirs, including the history of hydrocarbon generation, trap development, and reservoir evolution. Carbon isotopic analyses show that the oil and natural gas of the Ahe Formation originated from different sources. The natural gas was derived from Jurassic coal measure source rocks, whereas the oil has mixed sources of Lower Triassic lacustrine source rocks and minor amounts of coal-derived oil from Jurassic coal measure source rocks. The geochemistry of light hydrocarbon components and n-alkanes shows that the early accumulated oil was later altered by infilling gas due to gas washing. Consequently, n-alkanes in the oil are scarce, whereas naphthenic and aromatic hydrocarbons with the same carbon numbers are relatively abundant. The fluids in the Ahe Formation gas reservoirs have an unusual distribution, where oil is distributed above gas and water is locally produced from the middle of some gas reservoirs. The geochemical characteristics of the fluids show that this anomalous distribution was closely related to the dynamic accumulation of oil and gas. The period of reservoir densification occurred between the two stages of oil and gas accumulation, which led to the early accumulated oil and part of the residual formation water being trapped in the tight reservoir. After later gas filling into the reservoir, the fluids could not undergo gravity differentiation, which accounts for the anomalous distribution of fluids in the Ahe Formation.
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Lerche, Ian. "Hydrocarbon Flow along Intersecting Faults." Energy Exploration & Exploitation 23, no. 2 (April 2005): 107–23. http://dx.doi.org/10.1260/0144598054529996.

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This paper is concerned with the channeling of hydrocarbon flow up a master fault and the diversion of the flow to the left or right at the intersection of the master fault with a second fault. In particular, when reservoirs of different capacities can exist on the master fault and the secondary fault, the question of the retention efficiency of the reservoirs to the hydrocarbon flow is of interest. In addition, given the customary lack of sharp knowledge of the hydrocarbon petroleum system before drilling, the influence of uncertainties in the flow and reservoir properties is discussed in terms of statistical probabilistic representations and the dominant components to the uncertainties of retention and/or bypass are addressed. There is no consideration given in this paper to the possibility of production from the reservoirs before, during, or after fill by the hydrocarbons being supplied along the faults. That problem will be addressed in the next paper.
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Dissertations / Theses on the topic "Hydrocarbon reservoirs"

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Pereira, Leonardo Azevedo Guerra Raposo. "Seismic attributes in hydrocarbon reservoirs characterization." Master's thesis, Universidade de Aveiro, 2009. http://hdl.handle.net/10773/2735.

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Mestrado em Engenharia Geológica
No presente trabalho apresentam-se as vantagens da utilização de atributos sísmicos na interpretação de dados de sísmica de reflexão 3D e na identificação e caracterização de reservatórios de hidrocarbonetos. O trabalho prático necessário para a elaboração desta tese foi realizado durante um estágio de quatro meses na empresa de serviços para a indústria petrolífera, Schlumberger, em Paris, utilizando o software de interpretação sísmica e de modelação de reservatórios de hidrocarbonetos, Petrel 2008.1. Os atributos sísmicos podem ser considerados formas alternativas de visualizar os dados de sísmica de reflexão, que normalmente são representados em amplitude. A sua utilização facilita o processo de interpretação sísmica, uma vez que permite aumentar a razão sinal-ruído, detectar descontinuidades, reforçar a continuidade dos reflectores sísmicos e evidenciar indicadores directos de hidrocarbonetos nos dados sísmicos originais. Os atributos sísmicos podem ainda ser usados para treinar processos de auto-aprendizagem utilizados em redes neuronais na predição da distribuição de facies numa área em estudo. De uma forma geral, a utilização de atributos sísmicos facilita a correlação entre os dados provenientes do método sísmico, dados de poços e a geologia da área em estudo. Neste trabalho foi utilizado um bloco migrado de sísmica de reflexão 3D, com aproximadamente 6000 km2, adquirido no deep-offshore da costa Oeste Africana. Para além de um teste individual dos atributos sísmicos disponíveis no Petrel 2008.1, esta tese incluí uma avaliação preliminar do potencial em hidrocarbonetos de um sistema de canais amalgamados identificado na área em estudo. A sua identificação, interpretação e caracterização foi possível com o recurso a atributos sísmicos que evidenciam a presença de falhas, ou outras descontinuidades, e de atributos sísmicos sensíveis a pequenas variações na litologia e à presença de fluídos nos poros das formações litológicas. ABSTRACT: In this work the advantages related to the use of seismic attributes in the interpretation of 3D seismic data and in the characterization of hydrocarbon reservoirs are discussed. A four months internship at Schlumberger, in Paris, using the Petrel 2008.1 “seismic-to-simulation” software provided the necessary data to perform the work described in this thesis. Seismic attributes are different ways to look at the original seismic data, which normally is displayed in amplitudes. Using seismic attributes during the seismic interpretation process allow a significant improvement in the signal-to-noise ratio, the automatic detection of discontinuities, the enhancement of seismic reflectors continuity and the enhancement of direct hydrocarbon indicators. In the self-learning process for neural networks, seismic attributes can be used as training data to predict facies distribution in the study area. Generally, seismic attributes provide a better correlation between the data provided by the seismic reflection method, well log data and the geology of the study area. In this work, a 3D migrated seismic cube was used, with an approximate area of 6000km2, acquired in the deep-water of West Africa. Besides an individual test of each attribute available in Petrel 2008.1, this thesis also includes a preliminary evaluation of the oil and gas potential of a system of stacked channels identified within the study area. The identification, interpretation and characterization of this potential hydrocarbon reservoir was possible using seismic attributes to enhance faults and other discontinuities, and by using seismic attributes sensitive to subtle lithological variations and the presence of fluids in the pore spaces of the lithological formations.
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Taylor, Katherine Sarah. "Ephemeral-fluvial sediments as potential hydrocarbon reservoirs." Thesis, University of Aberdeen, 1994. http://digitool.abdn.ac.uk:80/webclient/DeliveryManager?pid=123206.

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Although reservoirs formed from ephemeral-fluvial sandstones have previously been considered relatively simple, unresolved problems of sandbody correlation and production anomalies demonstrate the need for improved understanding of their internal complexity. Ephemeral flows occur in direct response to precipitation, receiving little or no water from springs or other long-continued sources. They consequently predominate in dryland regions where precipitation is high in intensity, short lived and of limited areal extent. Resulting flow is high energy, relatively shallow and also restricted in duration and areal coverage. High transmission losses, abundant loose material and sparse vegetation result in highly concentrated flows which dissipate rapidly, causing a downstream decrease in flow discharge. Sediments deposited from these flows include parallel laminated sands, massive sands, scour-fill sands, transitional lower to upper flow regime dunes, and commonly contain numerous erosional discontinuities, scattered mudclasts, rapid grain size changes and deformational features. Large quantities of rainfall falling over longer periods produces steady flows dominated by well sorted, lower flow regime bedforms which have moderately well developed fining-up sequences. High intensity rainfall falling for shorter periods produces unsteady flows which are characterised by more poorly sorted, upper flow regime bedforms and an absence of fining-up sequences. Outcropping ephemeral-fluvial systems have been studied in order to determine the main features and processes occurring in sand-rich ephemeral systems and to identify which features will be of importance in a hydrocarbon reservoir. The Lower Jurassic Upper Moenave and Kayenta Formations of south-eastern Utah and northern Arizona comprise complex series of stacked, sand-dominated sheet-like palaeochannels suggestive of low sinuosity, braided systems.
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Seth, Siddhartha. "Increase in surface energy by drainage of sandstone and carbonate." Laramie, Wyo. : University of Wyoming, 2006. http://proquest.umi.com/pqdweb?did=1221730011&sid=4&Fmt=2&clientId=18949&RQT=309&VName=PQD.

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Owens, John. "Using object-oriented databases to model hydrocarbon reservoirs." Thesis, University of Aberdeen, 1995. http://ethos.bl.uk/OrderDetails.do?uin=uk.bl.ethos.262174.

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Hydrocarbon reservoir modelling plays a central role in the exploration and production of reservoirs. This thesis describes significant improvements in the way that data and knowledge about reservoir modelling is used in comparison with other attempts at such modelling. This thesis describes the development of a flexible reservoir modelling environment which allows users to apply their own knowledge in order to influence the modelling process. The modelling environment allows users to explore their own 'What if ...' hypotheses. A Smalltalk/V functional data model has been used as a front end to an object-oriented database (P/FDM). A technique called transparent object migration has been developed which allows objects from P/FDM to be reconstructed in the Smalltalk/V functional data model. The thesis describes how users can configure their own stochastic modelling algorithms. Common stages in stochastic modelling algorithms have been isolated and a number of alternatives developed for each stage. This has been implemented in an object-oriented architecture which allows users to configure their own algorithms from the re-usable parts supplied. A graphical probability distribution function editor has been developed. This provides a graphical representation of a probability distribution function which can be easily modified by the user, without the user having to provide a quantitative description of the changes that are required. By using this technique as part of a feedback loop, the user can develop reservoir models which they have more belief in.
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Zoccarato, Claudia. "Data Assimilation in Geomechanics: Characterization of Hydrocarbon Reservoirs." Doctoral thesis, Università degli studi di Padova, 2016. http://hdl.handle.net/11577/3424496.

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The prediction of the stress field distribution induced by the pore pressure change in deep hydrocarbon reservoirs and the consequent compaction of the porous rock formation is modeled with the aid of a Finite-Element (FE) geomechanical model. Despite the reliability of the model, which has been tested in several previous applications, many sources of uncertainty may affect the model outcome in terms of ground surface displacements. The uncertainty are mainly related to the mathematical model itself, that is an approximation reproducing a real and complex system, the initial and boundary conditions, the forcing terms, and the model parameters. The latter are the physical properties of the reservoir that are usually a-priori poorly known. A proper estimation of these parameters using a deterministic approach is discouraged as several parameters combinations may equally reproduce the observed data. Instead, the reservoir characterization is here performed by establishing a stochastic approach providing also for the quantification of the uncertainties affecting the parameter calibration. For this purpose, an ensemble-based data assimilation algorithm, i.e., the Ensemble Smoother, is elected among the available literature approaches. The methodology is investigated and tested in both synthetic cases and in real case applications by assimilating the available observations from in-situ measurements of ground-surface displacements. The characterization of the reservoir rock properties is provided for an Underground Gas Storage (UGS) reservoir and an offshore producing gas reservoir. Different set of parameters are estimated depending on the available information on the different fields. The parameters of a transversely isotropic model are calibrated using horizontal and vertical displacements from Persistent Scatterer Interferometry (PSI) measured above the UGS field, while vertical displacements from a time-lapse bathymetry are used to calibrate the uniaxial vertical compressibility of an isotropic constitutive law characterizing the behaviour of the offshore gas reservoir. Generally, it is obtained a satisfactory estimation of the geomechanical parameters with a significant spread reduction of the prior probability distributions when synthetic measurements, i.e., the displacements generated by an independent model run, are assimilated. However, more difficulties are encountered using real observations. This study gives indications on the main factors influencing the geomechanical characterization when assimilating movements of the land surface. The numerical results underline the importance of the consistency between the forward model and the assimilated measurements with an appropriate selection of data necessary to eliminate potential biases of the measurements and/or the modeling procedure.
Lo stato tensionale indotto dalla variazione di pressione in giacimenti profondi e la conseguente compattazione delle formazioni geologiche sono simulati con l'ausilio di un modello geomeccanico agli Elementi Finiti (FEM). Nei decenni passati, il citato modello è stato utilizzato in molteplici applicazioni e, tuttavia, le incertezze introdotte nella modellazione sono numerose e possono influire significativamente sulla risposta del modello, in termini di spostamenti superficiali. Le incertezze sono principalmente legate alla semplificazione intrinseca nel processo di modellazione, alle scarsamente note condizioni iniziali e al contorno, alle forzanti esterne e ai parametri del modello, e cioè le proprietà fisiche del giacimento, solitamente non conosciute a-priori. La stima di questi ultimi è ottenuta, in questo lavoro di tesi, attraverso lo sviluppo e l'implementazione di metodologie di tipo probabilistico che permettono di quantificare anche il grado di incertezza associato alla stima dei parametri del modello. Per questo scopo viene utilizzato il cosiddetto Ensemble Smoother, un particolare algoritmo di data assimilation basato su un approccio di tipo Monte Carlo. La metodologia proposta è stata applicata e testata sia su casi sintetici che su casi reali assimilando dati di spostamento superficiale misurati in-situ. I parametri geomeccanici sono stati stimati in due specifici giacimenti. Nel primo caso, si tratta di un sito per lo stoccaggio di gas metano mentre, il secondo caso, riguarda un sito offshore utilizzato per l'estrazione di gas. Nei due casi, per descrivere il comportamento geomeccanico del giacimento, sono state utilizzate leggi costitutive differenti, sulla base delle osservazioni disponibili nei due campi di interesse. In un caso, i parametri di un modello trasversalmente isotropo sono stati stimati usando misure interferometriche satellitari di spostamento superficiale sia orizzontale che verticale disponibili sul sito di stoccaggio. Nell'altro caso, una legge costitutiva più semplice di tipo isotropo è stata calibrata nel sito offshore dove le osservazioni a disposizione forniscono solo la componente verticale dello spostamento, stimata da una mappa differenziale di batimetria. Nei test sintetici, è stato dimostrato che la metodologia permette di valutare in modo soddisfacente i parametri geomeccanici con una riduzione notevole dell'incertezza inizialmente ipotizzata per i parametri in gioco. Tuttavia, la stima degli stessi è più difficile nei casi reali dove la discrepanza tra il risultato del modello FEM e le misure assimilate può suggerire una preliminare selezione delle misure disponibili per eliminare potenziali evidenti errori nelle misure stesse.
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Fang, Chao. "Pore-scale Interfacial and Transport Phenomena in Hydrocarbon Reservoirs." Diss., Virginia Tech, 2019. http://hdl.handle.net/10919/89911.

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Exploring unconventional hydrocarbon reservoirs and enhancing the recovery of hydrocarbon from conventional reservoirs are necessary for meeting the society's ever-increasing energy demand and requires a thorough understanding of the multiphase interfacial and transport phenomena in these reservoirs. This dissertation performs pore-scale studies of interfacial thermodynamics and multiphase hydrodynamics in shale reservoirs and conventional oil-brine-rock (OBR) systems. In shale gas reservoirs, the imbibition of water through surface hydration into gas-filled mica pores was found to follow the diffusive scaling law, but with an effective diffusivity much larger than the self-diffusivity of water molecules. The invasion of gas into water-filled pores with width down to 2nm occurs at a critical invasion pressure similar to that predicted by the classical capillary theories if effects of disjoining pressure and diffusiveness of water-gas interfaces are considered. The invasion of oil droplets into water-filled pores can face a free energy barrier if the pressure difference along pore is small. The computed free energy profiles are quantitatively captured by continuum theories if capillary and disjoining pressure effects are considered. Small droplets can invade a pore through thermal activation even if an energy barrier exists for its invasion. In conventional oil reservoirs, low-salinity waterflooding is an enhanced oil recovery method that relies on the modification of thin brine films in OBR systems by salinity change. A systematic study of the structure, disjoining pressure, and dynamic properties of these thin brine films was performed. As brine films are squeezed down to sub-nanometer scale, the structure of water-rock and water-oil interfaces changes marginally, but that of the electrical double layers in the films changes greatly. The disjoining pressure in the film and its response to salinity change follow the trend predicted by the DLVO theory, although the hydration and double layer forces are not simple additive as commonly assumed. A notable slip between the brine film and the oil phase can occur. The role of thin liquid films in multiphase transport in hydrocarbon reservoirs revealed here helps lay foundation for manipulating and leveraging these films to enhance hydrocarbon production and to minimize environmental damage during such extraction.
Doctor of Philosophy
Meeting the ever-increasing energy demand requires efficient extraction of hydrocarbons from unconventional reservoirs and enhanced recovery from conventional reservoirs, which necessitate a thorough understanding of the interfacial and transport phenomena involved in the extraction process. Abundant water is found in both conventional oil reservoirs and emerging hydrocarbon reservoirs such as shales. The interfacial behavior and transport of water and hydrocarbon in these systems can largely affect the oil and gas recovery process, but are not well understood, especially at pore scale. To fill in the knowledge gap on these important problems, this dissertation focuses on the pore-scale multiphase interfacial and transport phenomena in hydrocarbon reservoirs. In shales, water is found to imbibe into strongly hydrophilic nanopores even though the pore is filled with highly pressurized methane. Methane gas can invade into water-filled nanopores if its pressure exceeds a threshold value, and the thin residual water films on the pore walls significantly affect the threshold pressure. Oil droplet can invade pores narrower than their diameter, and the energy cost for their invasion can only be computed accurately if the surface forces in the thin film formed between the droplet and pore surface are considered. In conventional reservoirs, thin brine films between oil droplet and rock greatly affect the wettability of oil droplets on the rock surface and thus the effectiveness of low-salinity waterflooding. In brine films with sub-nanometer thickness, the ion distribution differs from that near isolated rock surfaces but the structure of water-brine/rock interfaces is similar to their unconfined counterparts. The disjoining pressure in thin brine films and its response to the salinity change follow the trend predicted by classical theories, but new features are also found. A notable slip between the brine film and the oil phase can occur, which can facilitate the recovery of oil from reservoirs.
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7

Coffey, Melody Roy. "Microbially Mediated Porosity Enhancement in Carbonate Reservoirs: Experiments with samples from the Salem, Sligo, and Smackover Formations." MSSTATE, 2004. http://sun.library.msstate.edu/ETD-db/theses/available/etd-10122004-105856/.

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This study used petrographic thin sections, scanning electron microscopy, and confocal laser microscopy to document microbially mediated dissolution of carbonate reservoir rocks. The samples studied came from three carbonate units that are hydrocarbon reservoirs; the Salem, Sligo, and Smackover formations. These samples were inoculated with bacteria, and then treated with nutrient solutions followed by ethanol to promote generation of acetic acid by bacteria. Dissolution occurred in calcite-dominated rocks and in dolomitized rocks. Noticeable changes first occurred after nine weeks of ethanol treatment and significant change only occurred after twelve weeks of ethanol treatment. The size of the vuggy pores created increased from 1 µm or less to over 5 µm, and rarely over 10 µm, in length.
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Obidi, Onochie. "Timescales for the development of thermodynamic equilibrium in hydrocarbon reservoirs." Thesis, Imperial College London, 2014. http://hdl.handle.net/10044/1/24880.

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The full understanding of the initial state of petroleum reservoirs and the fluxes that lead to compositional variations have become of huge interest to the petroleum industry. The compositional variation of reservoir fluid has great commercial impact on reservoir management and field development as it affects the value of the hydrocarbon in place, what recovery mechanisms applied and the treatment process of the extracted fluid if necessary. Lateral and vertical variation in hydrocarbon density and composition between wells are observed in many oil reservoirs under appraisal. These gradations may be due to changes in reservoir filling over geological time, in which case the variations are not in an equilibrium state, or alternatively due to an equilibrium between chemical, thermal and gravity potentials. The mixing of non-equilibrium compositional distributions is affected by Darcy flows (if there is a resulting pressure gradient), gravitational overturning (if there is a density difference) and molecular diffusion. The diffusion flux may also be affected by gravitational and thermal effects. Previous work has focused primarily on convective mixing and simple models of mixing via molecular diffusion. This work focuses on the rate of mixing via molecular diffusion, including the effects of pressure and thermal diffusion, which are modelled using the thermodynamics of irreversible processes for a single phase system. The interaction of diffusional mixing and gravitational overturning is also examined. The timescales to attain steady state are analyzed as well as the resulting compositional profiles. The developed model has been validated using simple transient analytical solution proposed by Carslaw and Jaeger (1959) for the molecular diffusion flux and Gardner et al. (1962) for the natural convection process. The diffusive fluxes in our model are also validated by steady state analytical solutions for species segregating in a thermo-gravitational column. The developed model was used to analyze the experimental results obtained for two ternary mixtures of methane, n-pentane and 1-methylnapthalene; and methane, n-pentane and undecane by Ratulowski et al. (2003). Although 1-methylnapthalene and undecane have similar molar masses, the system containing 1-methylnapthalene resulted in a bigger grading (difference in mole fraction at the top and bottom of the system) than the latter. This analysis demonstrates the impact of real mixture modelling (as opposed to the case when an ideal fluid is assumed) on the segregation-mixing process. Finally, we show how the knowledge of the timescales for observed compositional variations to reach equilibrium can be used to estimate the time since a reservoir filled. The Madison formation in the LaBarge field in Wyoming, U.S.A was studied. This is an unusual gas reservoir, as non-hydrocarbons make up about 80% of the total gas composition, with methane constituting the remainder. The methane composition varies significantly, 22% at the crest of the formation to 5% near the GWC. There are several hypotheses in the literature behind the unusual gas composition and distribution in this formation (De Bruin, 2001; Stilwell, 1989; Huang et al., 2007). We use the fluid mixing model to test the various hypotheses. The results reveal that the geothermal gradient in this field is not sufficient to make the thermal diffusion and thermal convection process in this reservoir override the effect of the molecular diffusion. We conclude that the reservoir is not yet in compositional equilibrium as molecular diffusion will completely homogenize the composition variation in this field. We propose that the currently observe composition profile is as result of the formation being enriched with CO2 at approximately 3 million years ago. This timescale is contemporaneous with the volcanic activity proposed by De Bruin (2001) and Stilwell (1989).
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Calleja, Glecy School of Biological Earth &amp Environmental Sciences UNSW. "Influence of mineralogy on petrophysical properties of petroleum reservoir beds." Awarded by:University of New South Wales. School of Biological, Earth and Environmental Sciences, 2005. http://handle.unsw.edu.au/1959.4/22423.

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Key petrophysical properties of reservoir sequences are determined by their individual mineral compositions, and are routinely evaluated through the analysis of cores and geophysical well logs. However, mineralogical studies are seldom incorporated in reservoir assessment. The objectives of the study were to investigate the influence of mineralogy on petrophysical properties of petroleum reservoir beds and the application of mineralogical studies in reservoir evaluation. Mineralogical analyses were performed on core samples from the Plover Formation, the principal reservoir sequence in the Northwest Shelf area of Australia, intersected in two separate wells in the Laminaria petroleum field. The techniques used included X-ray powder and oriented-aggregate analysis, optical microscopy and whole rock geochemistry. Quantification of each mineral phase based on whole-rock powder data was performed using the Rietveld-based Siroquant technique. Results from the Siroquant assay were used as an indicator of mineralogy for the individual samples and were compared with core plug and geophysical log data. X-ray micro-tomography analysis of selected samples was also performed. The reservoir sequences in both wells were sand-dominated, consisted mostly of quartz, clay mineral matrix and cement of silica, pyrite or calcite. The abundance of clay minerals increased in the shale and shaly sandstone intervals. Comparison of mineralogical and core plug analyses of samples from the same depths showed that the down-hole variations in porosity, permeability, grain density and radioactivity were accompanied by changes in mineralogy. Higher proportion of clay minerals in shales was indicated by higher gamma log signals. The gamma log may be taken as an indicator of shaliness only in intervals where kaolinite is proportional to the quantity of illitic clays. Sonic log and neutron log porosity values are comparable with core plug porosity data in sandstone intervals. However, clay minerals increase the sonic log response, thereby increasing porosity in shaly intervals. Clay minerals tend to decrease the neutron log response causing higher porosity indication in shales, similar to that expected in sandstones. Routine density log analysis underestimated porosity values because of the contribution of dense minerals to the bulk density of the formation. Use of laboratory determined grain and fluid densities resulted in improved density log porosity compared to core porosity. X-ray tomography analysis revealed an overall positive correlation between mineralogy and porosity data. Routine geophysical log evaluation revealed inconsistent results when compared to core analysis data because of the influence of minerals on various logs. It is essential that mineralogical studies be included in reservoir assessment. X-ray tomography may provide an alternative approach in evaluating porosity and mineralogy.
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Berhanu, Solomon Assefa. "Seismic and petrophysical properties of carbonate reservoir rocks." Thesis, University of Reading, 1994. http://ethos.bl.uk/OrderDetails.do?uin=uk.bl.ethos.262633.

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Books on the topic "Hydrocarbon reservoirs"

1

Qiu, Yinan. Continental hydrocarbon reservoirs of China. Beijing: Petroleum Industry Press, 1997.

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Sydansk, Robert D. Reservoir conformance improvement. Richardson, TX: Society of Petroleum Engineers, 2011.

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Hazra, Bodhisatwa, Debanjan Chandra, and Vikram Vishal. Unconventional Hydrocarbon Reservoirs: Coal and Shale. Cham: Springer Nature Switzerland, 2024. http://dx.doi.org/10.1007/978-3-031-53484-3.

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American Association of Petroleum Geologists and American Association of Petroleum Geologists Foundation, eds. Lacustrine sandstone reservoirs and hydrocarbon systems. Tulsa, OK: American Association of Petroleum Geologists, 2012.

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Kerimov, V. I︠U︡. (Vagif I︠U︡nus ogly) and Gorfunkel Michael V, eds. Fluid dynamics of oil and gas reservoirs. Hoboken, New Jersey: Scrivener Publishing/Wiley, 2015.

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G, Bebout Don, Harris Paul M. 1949-, Society of Economic Paleontologists and Mineralogists. Permian Basin Section., University of Texas at Austin. Bureau of Economic Geology., and San Andres/Grayburg Research Conference and Field Trip (1986 : Midland, Tex.), eds. Geologic and engineering approaches in evaluation of San Andres/Grayburg hydrocarbon reservoirs--Permian Basin. Austin, Tex: Bureau of Economic Geology, University of Texas at Austin, 1990.

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I, Osipov V. Glinistye pokryshki nefti︠a︡nykh i gazovykh mestorozhdeniĭ. Moskva: Nauka, 2001.

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R, Braithwaite C. J., Rizzi G, Darke G, and Geological Society of London, eds. The geometry and petrogenesis of dolomite hydrocarbon reservoirs. London: Geological Society, 2004.

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Rocky Mountain Association of Geologists. Symposium. Compartmentalized reservoirs in Rocky Mountain Basins. Edited by Slatt Roger M. Denver, Colo: Rocky Mountain Association of Geologists, 1998.

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A, Robinson, and Geological Society of London, eds. The future of geological modelling in hydrocarbon development. London: Geological Society, 2008.

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Book chapters on the topic "Hydrocarbon reservoirs"

1

Chierici, Gian Luigi. "Hydrocarbon Reservoirs." In Principles of Petroleum Reservoir Engineering, 1–16. Berlin, Heidelberg: Springer Berlin Heidelberg, 1994. http://dx.doi.org/10.1007/978-3-662-02964-0_1.

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Yu, Xinghe, Shengli Li, and Shunli Li. "Basic Features of Clastic Reservoirs." In Clastic Hydrocarbon Reservoir Sedimentology, 49–76. Cham: Springer International Publishing, 2018. http://dx.doi.org/10.1007/978-3-319-70335-0_3.

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Naqi, Mohammad, Ohood Alsalem, Suad Qabazard, and Fowzia Abdullah. "Petroleum Geology of Kuwait." In The Geology of Kuwait, 117–44. Cham: Springer International Publishing, 2022. http://dx.doi.org/10.1007/978-3-031-16727-0_6.

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AbstractKuwait has proven conventional oil reserves of about 100 billion barrels which makes it one of the major oil-producing countries worldwide. Most of this reserve is found in Cretaceous and Jurassic with minor quantities in the Paleogene sedimentary successions. Most hydrocarbon production comes from the siliciclastic Burgan Formation which is the most important reservoir in Kuwait. The Jurassic and Lower Cretaceous exhibit good quality source rocks that charged most of the hydrocarbon reservoirs in Kuwait and entered the oil window in Late Cretaceous to Eocene. Most of the hydrocarbon is trapped in very gentle four-way closure structures that are related to the deep-seated fault system of the Arabian Peninsula such as Khurais-Burgan Anticline. Hydrocarbon reservoirs in Kuwait are sealed and capped mainly by shale rocks and to a less extent by evaporites. In the last 15 years, Kuwait Oil Company (KOC) displayed interest in commercially exploiting unconventional hydrocarbon reserves and started laying significant emphasis on the exploration and development of unconventional resources. The aim of this work is to summarize the different petroleum systems of Kuwait including the Paleozoic, Mesozoic, and Cenozoic systems.
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Head, I. M., S. R. Larter, N. D. Gray, A. Sherry, J. J. Adams, C. M. Aitken, D. M. Jones, A. K. Rowan, H. Huang, and W. F. M. Röling. "Hydrocarbon Degradation in Petroleum Reservoirs." In Handbook of Hydrocarbon and Lipid Microbiology, 3097–109. Berlin, Heidelberg: Springer Berlin Heidelberg, 2010. http://dx.doi.org/10.1007/978-3-540-77587-4_232.

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Dou, Lirong, Kunye Xiao, and Jingchun Wang. "Geological Features of Hydrocarbon Reservoirs." In Petroleum Geology and Exploration of the Bongor Basin, 299–378. Singapore: Springer Nature Singapore, 2023. http://dx.doi.org/10.1007/978-981-19-2673-0_7.

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Nanda, Niranjan C. "Fractured-Basement Reservoirs." In Seismic Data Interpretation and Evaluation for Hydrocarbon Exploration and Production, 293–304. Cham: Springer International Publishing, 2021. http://dx.doi.org/10.1007/978-3-030-75301-6_15.

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Karlsen, Dag A., and Steve Larter. "A rapid correlation method for petroleum population mapping within individual petroleum reservoirs: applications to petroleum reservoir description." In Correlation in Hydrocarbon Exploration, 77–85. Dordrecht: Springer Netherlands, 1989. http://dx.doi.org/10.1007/978-94-009-1149-9_8.

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Hazra, Bodhisatwa, Debanjan Chandra, and Vikram Vishal. "Potential for CO2 Sequestration in Coal and Shale." In Unconventional Hydrocarbon Reservoirs: Coal and Shale, 125–64. Cham: Springer Nature Switzerland, 2024. http://dx.doi.org/10.1007/978-3-031-53484-3_6.

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Hazra, Bodhisatwa, Debanjan Chandra, and Vikram Vishal. "Source-Rock Geochemistry of Unconventional Plays." In Unconventional Hydrocarbon Reservoirs: Coal and Shale, 9–34. Cham: Springer Nature Switzerland, 2024. http://dx.doi.org/10.1007/978-3-031-53484-3_2.

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Hazra, Bodhisatwa, Debanjan Chandra, and Vikram Vishal. "Estimation of Gas Storage Capacity Estimate in Coals and Shales." In Unconventional Hydrocarbon Reservoirs: Coal and Shale, 35–72. Cham: Springer Nature Switzerland, 2024. http://dx.doi.org/10.1007/978-3-031-53484-3_3.

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Conference papers on the topic "Hydrocarbon reservoirs"

1

Khan, Moin Uddin, and Jeffrey Guy Callard. "Reservoir Management in Unconventional Reservoirs." In SPE Hydrocarbon Economics and Evaluation Symposium. Society of Petroleum Engineers, 2010. http://dx.doi.org/10.2118/130146-ms.

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Alrassan, A. I., A. A. Al-Turki, and T. M. Al-Zahrani. "Data-Driven Approaches for Quick Performance Assessment of Hydrocarbon Reservoirs." In International Petroleum Technology Conference. IPTC, 2024. http://dx.doi.org/10.2523/iptc-23944-ms.

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Abstract Hydrocarbon reservoir's heterogeneity, production, injection and aquifer support play a unique role into how field strategies are developed knowing key reservoir properties (e.g. drainage volumes, reservoir energy, rock properties, decline analysis, etc.). Alanood et al. (2022) illustrated applications of Fast Marching Method (FMM) in assessing reservoir performance, identifying reservoir patterns and anomalies from production/injection data, and predicting the reservoir response when considering modeling uncertainty for model calibration. The objective of this paper is to extend the previous work to include more field development controls like voidage replacement, infinite acting reservoirs, and performance prediction of new proposed producers or injectors. The proposed approach in this work is to extend the physics-aware data-driven approach, that uses the diffusive time-of-flight (DTOF) to determine the pressure disturbance caused by production/injection wells to help in comprehending the impact on field development. The previous work by Alanood et al. (2022) is extended to account for voidage replacement, pressure maintenance and infinite acting reservoirs. In addition, this approach has been extended to predict the performance (e.g., rates, bottom-hole pressure and plateau) of proposed injection and production wells to give a quick insight about their performance prior to running the full-physics reservoir simulators. Thus, will give a better understanding in describing the transient flow. That is in addition to helping in inferring faults existence, fracture networks and inter-well connectivity. In this work, SPE10 and NORNE benchmark models were used to test and validate the approach. The results show that this date-driven approach was able to match historical and predicted performance of the reservoirs and wells. The data-driven algorithms were able to generate pressure maps resembling the ones obtained from the full-physics reservoir for infinite acting reservoir models for the first few years before it starts to deviate. They also were able to predict rates and flowing bottom-hole pressure of injectors and producers to up to 80% when compared to reservoir simulation. In addition, several blind tests of placing injectors and producers revealed that the algorithms are capable of capturing the reservoir's pressure changes and wells performance in finite and infinite acting reservoirs. The extended work of the physics-aware data-driven approach using the DTOF is a reliable approach to monitor reservoir pressure in the finite and infinite acting reservoirs (e.g., aquifer support and pressure maintenance injection). It also demonstrated the ability to predict the performance of existing and newly proposed wells to great accuracy. The approach provides a quick assessment of wells and reservoir performance given a certain field development strategy.
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Wilson, S., A. Jupe, and W. Wason. "Microseismic Monitoring of Hydrocarbon Reservoirs." In 1st EAGE North African/Mediterranean Petroleum & Geosciences Conference & Exhibition. European Association of Geoscientists & Engineers, 2003. http://dx.doi.org/10.3997/2214-4609-pdb.8.t015.

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Jupe, A. J., and W. Wason. "Microseismic Monitoring of Hydrocarbon Reservoirs." In Geophysics of the 21st Century - The Leap into the Future. European Association of Geoscientists & Engineers, 2003. http://dx.doi.org/10.3997/2214-4609-pdb.38.f042.

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Rietveld, W. E. A., A. J. Berkhout, and C. P. A. Wapenaar. "Controlled illumination of hydrocarbon reservoirs." In SEG Technical Program Expanded Abstracts 1991. Society of Exploration Geophysicists, 1991. http://dx.doi.org/10.1190/1.1889125.

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6

Kome, Melvin, and Mohd Amro. "Water Influx Predictions in Reservoirs with Aquifer Drive Using the Two-Phase Reservoir Integral Type Pseudo-Pressure with Applicability in Gas Hydrate Reservoirs." In SPE/AAPG Africa Energy and Technology Conference. SPE, 2016. http://dx.doi.org/10.2118/afrc-2570887-ms.

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ABSTRACT The application of the Kirchhoff transformation has proven to be a very effective tool in simplifying and solving complex diffusivity equations in reservoirs. Since its introduction by [1] in addressing the non-linear behavior of compressible fluids, it has seen many modifications and implementations in multiphase systems, from the Perrine type pseudo-pressure to the reservoir integral type pseudo-pressure also called the Mass balance Model (MBM) for pseudo-pressure as discussed by [2]. Its applicability in addressing water influx from aquifers to oil and gas reservoirs has as of now not been addressed. Moreover, the models developed so far to address water influx such as the works of [3], [4], [5], have many limitations, such as imposing constant pressure at the reservoir–aquifer interface, single phase model used, no analytical approach of predicting excessive water cuts. In this paper, the MBM pseudo-pressure is used to address water influx in reservoirs with two-phase flow (Gas/Water or Oil/Water). The model response is derived by developing diffusivity equations for the composite reservoir system to address the communication between the hydrocarbon reservoir and the aquifer. The non-homogenous nature of the diffusivity equation of each phase makes the derivation of the solutions to the equations cumbersome. Nonetheless, the reservoir integral type pseudo-pressure being a very powerful, can be incorporated in the diffusivity equations of the phases and solutions to the models can rigorously be derived. Defining the boundary conditions for each phase is very crucial as the hydrocarbons in the hydrocarbon reservoir depict a no-flow boundary at the aquifer interface, whereas the water phase and the total system response of the hydrocarbon reservoir depict mass conservation at the hydrocarbon reservoir-aquifer interface. Using this approach, the solutions to the phases in the hydrocarbon and aquifer are readily obtained and its applicability in gas hydrate reservoirs highlighted. The effects of the water influx from the aquifer are clearly seen with increasing water cut at the sandface. The effects of different outer boundary conditions in the aquifer are investigated. The novel approach introduced in this work will help tremendously to improve the characterization of the reservoir with multiphase flow, mostly especially for reservoirs with aquifer drive.
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Unalmiser, Servet, and T. J. Swalwell. "A Quick Technique To Define Compressibility Characteristics of Hydrocarbon Reservoir." In Low Permeability Reservoirs Symposium. Society of Petroleum Engineers, 1993. http://dx.doi.org/10.2118/25912-ms.

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F. Worthington, P. "Petrophysical Characterization of Complex Hydrocarbon Reservoirs." In 57th EAEG Meeting. Netherlands: EAGE Publications BV, 1995. http://dx.doi.org/10.3997/2214-4609.201409634.

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E. A. Rietveld, W., A. J. Berkhout, and C. P. A. Wapenaar. "Controlled seismic illumination of hydrocarbon reservoirs." In 53rd EAEG Meeting. European Association of Geoscientists & Engineers, 1991. http://dx.doi.org/10.3997/2214-4609.201411056.

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Makinde, Ibukun, and W. John Lee. "Production Forecasting in Shale Volatile Oil Reservoirs." In SPE/IAEE Hydrocarbon Economics and Evaluation Symposium. Society of Petroleum Engineers, 2016. http://dx.doi.org/10.2118/179965-ms.

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Reports on the topic "Hydrocarbon reservoirs"

1

Michael Batzle. Seismic Evaluation of Hydrocarbon Saturation in Deep-Water Reservoirs. Office of Scientific and Technical Information (OSTI), April 2006. http://dx.doi.org/10.2172/898116.

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Michael Batzle, D-h Han, R. Gibson, and Huw James. SEISMIC EVALUATION OF HYDROCARBON SATURATION IN DEEP-WATER RESERVOIRS. Office of Scientific and Technical Information (OSTI), January 2005. http://dx.doi.org/10.2172/836821.

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Michael Batzle, D-h Han, R. Gibson, and Huw James. SEISMIC EVALUATION OF HYDROCARBON SATURATION IN DEEP-WATER RESERVOIRS. Office of Scientific and Technical Information (OSTI), August 2005. http://dx.doi.org/10.2172/842825.

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Michael Batzle, D-h Han, R. Gibson, and Huw James. Seismic Evaluation of Hydrocarbon Saturation in Deep-Water Reservoirs. Office of Scientific and Technical Information (OSTI), January 2006. http://dx.doi.org/10.2172/876008.

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M. Batzle, D-h Han, R. Gibson, and O. Djordjevic. SEISMIC EVALUATION OF HYDROCARBON SATURATION IN DEEP-WATER RESERVOIRS. Office of Scientific and Technical Information (OSTI), March 2003. http://dx.doi.org/10.2172/816390.

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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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Cesar, J. R., and O. H. Ardakani. Organic geochemistry of the Montney Formation: new insights about the source of hydrocarbons, their accumulation history and post accumulation processes. Natural Resources Canada/CMSS/Information Management, 2022. http://dx.doi.org/10.4095/329788.

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This study consists of a non-traditional molecular and stable isotope approach to analyze organic matter (soluble bitumen and produced oil/condensate) from the Montney Formation low-permeability reservoirs, with the purpose of identifying source(s) of hydrocarbons, accumulation history and post accumulation processes. The same approach bases on the distribution of compound classes such as aromatic carotenoids, polycyclic aromatic hydrocarbons (PAHs), bicyclic alkanes, and oxygen-polar compounds. The geochemical screening has been enhanced with performing compound specific isotope analysis (CSIA) of n-alkanes and selected aromatic hydrocarbons. Widely spread PAHs, the presence of molecular indicators of euxinia, and hydrocarbon mixtures identified using CSIA profiles, are some of the key findings from this research, which will improve our understanding of the Montney petroleum system(s).
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Negri, M. Cristina. Microorganisms Associated with Hydrocarbon Contaminated Sites and Reservoirs for Microbially Enhanced Oil Recovery (MEOR). Office of Scientific and Technical Information (OSTI), October 2013. http://dx.doi.org/10.2172/1118140.

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Bosshart, Nicholas W., Scott C. Ayash, Nicholas A. Azzolina, Wesley D. Peck, Charles D. Gorecki, Jun Ge, Tao Jiang, et al. Optimizing and Quantifying CO2 Storage Resource in Saline Formations and Hydrocarbon Reservoirs. Office of Scientific and Technical Information (OSTI), June 2017. http://dx.doi.org/10.2172/1367566.

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Steven B. Hawthorne. Subtask 1.17 - Measurement of Hydrocarbon Evolution from Coal and Petroleum Reservoirs Under Carbon Dioxide Floods. Office of Scientific and Technical Information (OSTI), December 2006. http://dx.doi.org/10.2172/922247.

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