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Oil Reservoirs (oil + reservoir)
Selected AbstractsA New Understanding of Channel Patterns and Facies Models of the Shallow Lake Delta Facies of Fuyu Oil Reservoir in Songliao Basin, ChinaACTA GEOLOGICA SINICA (ENGLISH EDITION), Issue 3 2008LI Yanping Abstract: In the Fuyu Reservoir of Songliao Basin, there occur a series of well-developed peculiar shallow lake delta facies, which can be divided to such three ones as the upper delta plain subfacies, the lower delta plain subfacies, and the delta front subfacies. Among them the upper delta plain subfacies mainly grows proximal distributary channels; the lower delta plain subfacies mainly grows distal ones. The entire Fuyu Reservoir has mainly developed 7 kinds of distributary channel patterns: proximal/ distal meandering type distributary channels, proximal/distal low-sinuosity type distributary channels, proximal/distal straight type distributary channels, and subaqueous distributary channels. Among these patterns, the proximal and distal meandering type distributary channels have bigger thickness of point bar and better sorting and low content of mud; moreover, they are the major reservoirs and occur in the bottom of Quan-4th member. The sandbars of the subaqueous distributary channels have higher mud content, and serve as the poorer reservoirs, and mainly occur in the top of Quan-4th member. [source] Numerical modelling of regional faults in land subsidence prediction above gas/oil reservoirsINTERNATIONAL JOURNAL FOR NUMERICAL AND ANALYTICAL METHODS IN GEOMECHANICS, Issue 6 2008Massimiliano Ferronato Abstract The stress variation induced by gas/oil production may activate pre-existing regional faults. This may enhance the expected land subsidence due to the generation of mechanically weak points close to the producing field. A class of elasto-plastic interface elements (IE), specifically designed to address the mechanical behaviour of faults over a regional scale, is integrated into a finite element (FE) geomechanical model and used to investigate the role exerted by active faults in anthropogenic land subsidence. The importance of regional faults depends on a variety of factors including depth of the depleted reservoir, fault number, orientation and size, geomechanical properties of porous medium, pore pressure drawdown induced by fluid production, etc. With the aid of some representative examples, a useful indication is provided as to where and how fault activation may influence both magnitude and extent of the land subsidence bowl above producing gas/oil reservoirs, pointing to a generally limited impact on the ground surface. The simulation of a real faulted gas reservoir in a complex 3-D setting shows that the proposed IE can be simply and efficiently incorporated into a FE geomechanical model, thus improving the quality of the stress and displacement prediction. Copyright © 2007 John Wiley & Sons, Ltd. [source] Enabling interactive and collaborative oil reservoir simulations on the GridCONCURRENCY AND COMPUTATION: PRACTICE & EXPERIENCE, Issue 11 2005Manish Parashar Abstract Grid-enabled infrastructures and problem-solving environments can significantly increase the scale, cost-effectiveness and utility of scientific simulations, enabling highly accurate simulations that provide in-depth insight into complex phenomena. This paper presents a prototype of such an environment, i.e. an interactive and collaborative problem-solving environment for the formulation, development, deployment and management of oil reservoir and environmental flow simulations in computational Grid environments. The project builds on three independent research efforts: (1) the IPARS oil reservoir and environmental flow simulation framework; (2) the NetSolve Grid engine; and (3) the Discover Grid-based computational collaboratory. Its primary objective is to demonstrate the advantages of an integrated simulation infrastructure towards effectively supporting scientific investigation on the Grid, and to investigate the components and capabilities of such an infrastructure. Copyright © 2005 John Wiley & Sons, Ltd. [source] Diagenesis of the Amposta offshore oil reservoir (Amposta Marino C2 well, Lower Cretaceous, Valencia Trough, Spain)GEOFLUIDS (ELECTRONIC), Issue 3 2010E. PLAYÀ Abstract Samples from the Amposta Marino C2 well (Amposta oil field) have been investigated in order to understand the origin of fractures and porosity and to reconstruct the fluid flow history of the basin prior, during and after oil migration. Three main types of fracture systems and four types of calcite cements have been identified. Fracture types A and B are totally filled by calcite cement 1 (CC1) and 2 (CC2), respectively; fracture type A corresponds to pre-Alpine structures, while type B is attributed to fractures developed during the Alpine compression (late Eocene-early Oligocene). The oxygen, carbon and strontium isotope compositions of CC2 are close to those of the host-rock, suggesting a high degree of fluid-rock interaction, and therefore a relatively closed palaeohydrogeological system. Fracture type C, developed during the Neogene extension and enlarged by subaerial exposure, tend to be filled with reddish (CS3r) and greenish (CS3g) microspar calcite sediment and blocky calcite cement type 4 (CC4), and postdated by kaolinite, pyrite, barite and oil. The CS3 generation records lower oxygen and carbon isotopic compositions and higher 87Sr/86Sr ratios than the host-limestones. These CS3 karstic infillings recrystallized early within evolved-meteoric waters having very little interaction with the host-rock. Blocky calcite cement type 4 (CC4 generation) has the lowest oxygen isotope ratio and the most radiogenic 87Sr/86Sr values, indicating low fluid-rock interaction. The increasingly open palaeohydrogeological system was dominated by migration of hot brines with elevated oxygen isotope ratios into the buried karstic system. The main oil emplacement in the Amposta reservoir occurred after the CC4 event, closely related to the Neogene extensional fractures. Corrosion of CC4 (blocky calcite cement type 4) occurred prior to (or during) petroleum charge, possibly related to kaolinite precipitation from relatively acidic fluids. Barite and pyrite precipitation occurred after this corrosion. The sulphur source associated with the late precipitation of pyrite was likely related to isotopically light sulphur expelled, e.g. as sulphide, from the petroleum source rock (Ascla Fm). Geofluids (2010) 10, 314,333 [source] Hydrologic and geochemical controls on soluble benzene migration in sedimentary basinsGEOFLUIDS (ELECTRONIC), Issue 2 2005Y. ZHANG Abstract The effects of groundwater flow and biodegradation on the long-distance migration of petroleum-derived benzene in oil-bearing sedimentary basins are evaluated. Using an idealized basin representation, a coupled groundwater flow and heat transfer model computes the hydraulic head, stream function, and temperature in the basin. A coupled mass transport model simulates water washing of benzene from an oil reservoir and its miscible, advective/dispersive transport by groundwater. Benzene mass transfer at the oil,water contact is computed assuming equilibrium partitioning. A first-order rate constant is used to represent aqueous benzene biodegradation. A sensitivity study is used to evaluate the effect of the variation in aquifer/geochemical parameters and oil reservoir location on benzene transport. Our results indicate that in a basin with active hydrodynamics, miscible benzene transport is dominated by advection. Diffusion may dominate within the cap rock when its permeability is less than 10,19 m2. Miscible benzene transport can form surface anomalies, sometimes adjacent to oil fields. Biodegradation controls the distance of transport down-gradient from a reservoir. We conclude that benzene detected in exploration wells may indicate an oil reservoir that lies hydraulically up-gradient. Geochemical sampling of hydrocarbons from springs and exploration wells can be useful only when the oil reservoir is located within about 20 km. Benzene soil gas anomalies may form due to regional hydrodynamics rather than separate phase migration. Diffusion alone cannot explain the elevated benzene concentration observed in carrier beds several km away from oil fields. [source] Evaluation of soluble benzene migration in the Uinta BasinGEOFLUIDS (ELECTRONIC), Issue 2 2005Y. ZHANG Abstract Field sampling and mathematical modeling are used to study the long-distance transport and attenuation of petroleum-derived benzene in the Uinta Basin, Utah. Benzene concentration was measured from oil and oil field formation waters of the Altamont-Bluebell and Pariette Bench oil fields in the basin. It was also measured from springs located in the regional groundwater discharge areas, hydraulically down-gradient from the oil fields sampled. The average benzene concentration in oils and co-produced waters is 1946 and 4.9 ppm at the Altamont-Bluebell field and 1533 and 0.6 ppm at the Pariette Bench field, respectively. Benzene concentration is below the detection limit in all springs sampled. Mathematical models are constructed along a north,south trending transect across the basin through both fields. The models represent groundwater flow, heat transfer and advective/dispersive benzene transport in the basin, as well as benzene diffusion within the oil reservoirs. The coupled groundwater flow and heat transfer model is calibrated using available thermal and hydrologic data. We were able to reproduce the observed excess fluid pressure within the lower Green River Formation and the observed convective temperature anomalies across the northern basin. Using the computed best-fit flow and temperature, the coupled transport model simulates water washing of benzene from the oil reservoirs. Without the effect of benzene attenuation, dissolved benzene reaches the regional groundwater discharge areas in measurable concentration (>0.01 ppm); with attenuation, benzene concentration diminishes to below the detection limit within 1,4 km from the reservoirs. Attenuation also controls the amount of water washing over time. In general, models that represent benzene attenuation in the basin produce results more consistent with field observations. [source] Flows through horizontal channels of porous materialsINTERNATIONAL JOURNAL OF ENERGY RESEARCH, Issue 10 2003A.K. Al-Hadhrami Abstract In this paper, the control volume method (CVM) with the staggered grid system is utilized to solve the two-dimensional Brinkman equation for different configurations of porous media in a horizontal channel. The values of the permeability of sand and clear fluid are considered when performing several numerical investigations which enable the evaluation of the behaviour of the flow through regions that mathematically model some geological features (faults/fractures) present in oil reservoirs or groundwater flows. We have found that the convergence of the CVM can be achieved within a reasonable number of iterations when there is a gap present between a partial barrier of low Darcy number and the channel boundary. However, a complete barrier across the channel results in a very high resistance and hence there is a large pressure drop which causes difficulties in convergence. In order to improve the rate of convergence in such situations, an average pressure correction (APC) technique, which is based on global mass conservation, is developed. The use of this technique, along with the CVM, can rapidly build up the pressure drop across such a barrier and hence dramatically improve the rate of convergence of the iterative scheme. Copyright © 2003 John Wiley & Sons, Ltd. [source] THE GEOLOGY AND HYDROCARBON HABITAT OF THE SARIR SANDSTONE, SE SIRT BASIN, LIBYAJOURNAL OF PETROLEUM GEOLOGY, Issue 2 2000G. Ambrose The Jurassic , Lower Cretaceous Sarir Sandstone Cformerly known as the Nubian Sandstone) in the SE Sirt Basin is composed of four members which can be correlated regionally using a lithostratigraphic framework. These synrift sandstones unconformably overlie a little known pre-rift succession, and are in turn unconformably overlain by post-rift marine shales of Late Cretaceous age. Within the Sarir Sandstone are two sandstone-dominated members, each reflecting a rapid drop in base level, which are important oil reservoirs in the study area. Between these sandstones are thick shales of continental origin which define the architecture of the reservoir units. This four-fold lithostratigraphic subdivision of the Sarir Sandstone contrasts with previous schemes which generally only recognised three members. The sandstones below the top-Sarir unconformity host in excess of 20 billion barrels of oil in-place. The dominant traps are structural (e.g. Sarir C field), stratigraphic (e.g. Messla field), hanging-wall fault plays (e.g. UU1,65 field) and horst-block plays (e.g. Calanscio field). Three Sarir petroleum systems are recognised in the SE Sirt Basin. The most significant relies on post-rift (Upper Cretaceous) shales, which act as both source and seal. The Variegated Shale Member of the Sarir Sandstone may also provide source and seal; while a third, conceptual petroleum system requires generation of non-marine oils from pre-rift (?Triassic) source rocks in the axis of the Sarir Trough. The intrabasinal Messla High forms a relatively rigid block at the intersection of two rift trends, around which stress vectors were deflected during deposition of the syn-rift Sarir Sandstone. Adjacent troughs accommodated thick, post-rift shale successions which comprise excellent source rocks. Palaeogene subsidence facilitated oil generation, and the Messla High was a focus for oil migration. Wrenching on master faults with associated shale smear has facilitated fault seal and the retention of hydrocarbons. In the Calanscio area, transpressional faulting has resulted in structural inversion with oil entrapment in "pop-up" horst blocks. Elsewhere, transtensional faulting has resulted in numerous fault-dependent traps which, in combination with stratigraphic and truncation plays, will provide the focus for future exploration. [source] Mobility control: How injected surfactants and biostimulants may be forced into low-permeability unitsREMEDIATION, Issue 3 2003Richard E. Jackson Recovering dense nonaqueous-phase liquid (DNAPL) remains one of the most difficult problems facing the remediation industry. Still, the most common method of recovering DNAPL is to physically remove the contaminants using common technologies such as total fluids recovery pumps, vacuum systems, and "pump-and-treat." Increased DNAPL removal can be attained using surfactants to mobilize and/or solubilize the pollutants. However, very little is understood of the methods developed by petroleum engineers beginning in the 1960s to overcome by-passed, low-permeability zones in heterogeneous oil reservoirs. By injecting or causing the formation of viscous fluids in the subsurface, petroleum engineers caused increased in-situ pressures that forced fluid flow into low permeability units as well as the higher permeability thief zones. Polymer flooding involves injecting a viscous aqueous polymer solution into the contaminated aquifer. Foam flooding involves injecting surfactant to decontaminate the high-permeability zones and then periodic pulses of air to cause a temporary viscous foam to form in the high-permeable zones after all DNAPL is removed. Later surfactant pulses are directed by the foam into unswept low-permeable units. These methods have been applied to DNAPL removal using surfactants but they can also be applied to the injection of bio-amendments into low-permeability zones still requiring continued remediation. Here we discuss the principles of mobility control as practiced in an alluvial aquifer contaminated with chlorinated solvent and coal tar DNAPLs as well as some field results. © 2003 Wiley Periodicals, Inc. [source] Differences of Hydrocarbon Enrichment between the Upper and the Lower Structural Layers in the Tazhong PaleoupliftACTA GEOLOGICA SINICA (ENGLISH EDITION), Issue 5 2010JIANG Zhenxue Abstract: The Tazhong paleouplift is divided into the upper and the lower structural layers, bounded by the unconformity surface at the top of the Ordovician carbonate rock. The reservoirs in the two layers from different parts vary in number, type and reserves, but the mechanism was rarely researched before. Therefore, an explanation of the mechanism will promote petroleum exploration in Tazhong paleouplift. After studying the evolution and reservoir distribution of the Tazhong paleouplift, it is concluded that the evolution in late Caledonian, late Hercynian and Himalayan periods resulted in the upper and the lower structural layers. It is also defined that in the upper structural layer, structural and stratigraphic overlap reservoirs are developed at the top and the upper part of the paleouplift, which are dominated by oil reservoirs, while for the lower structural layer, lithological reservoirs are developed in the lower part of the paleouplift, which are dominated by gas reservoirs, and more reserves are discovered in the lower structural layer than the upper. Through a comparative analysis of accumulation conditions of the upper and the lower structural layers, the mechanism of enrichment differences is clearly explained. The reservoir and seal conditions of the lower structural layer are better than those of the upper layer, which is the reason why more reservoirs have been found in the former. The differences in the carrier system types, trap types and charging periods between the upper and the lower structural layers lead to differences in the reservoir types and distribution. An accumulation model is established for the Tazhong paleouplift. For the upper structural layer, the structural reservoirs and the stratigraphic overlap reservoirs are formed at the upper part of the paleouplift, while for the lower structural layer, the weathering crust reservoirs are formed at the top, the reef-flat reservoirs are formed on the lateral margin, the karst and inside reservoirs are formed in the lower part of the paleouplift. [source] Alkyl Naphthalenes and Phenanthrenes: Molecular Markers for Tracing Filling Pathways of Light Oil and Condensate ReservoirsACTA GEOLOGICA SINICA (ENGLISH EDITION), Issue 5 2010LI Meijun Abstract: Condensates and light oils are generally characterized by high maturity, low concentration of sterane and terpane biomarkers and low content of non-hydrocarbon fraction. As a result, some commonly-used sterane, terpane and carbazole migration parameters in conventional oil reservoirs may have a certain limitation in condensate and light oil reservoirs for their poor signal-noise ratios in the gas chromatography-mass spectrometry (GC-MS). Naphthalene, phenanthrene and their methylated substituents, however, are present in significant concentrations in condensates and light oils. Taking the Fushan depression (in the Beibuwan Basin, Northern South China Sea) as an example, this paper attempts for the first time to use polycyclic aromatic hydrocarbon (PAH)-related parameters to trace migration directions and filling pathways for condensate and light oil reservoirs. The result shows that TMNr (i.e. 1,3,7-TMN/ (1,3,7-TMN + 1,2,5-TMN), TMN: trimethylnaphthalene)), MPI-1 (i.e. 1.5×(2-MP + 3-MP)/(P + 1-MP + 9-MP), P: phenanthrene MP: methylphenanthrene), MN/DMN (,methylnaphthalene/,dimethylnaphthalene, %) and MN/TMN (,methylnaphthalene/,trimethylnaphthalene, %) can be used to trace the filling pathways of condensate and light oil reservoirs. These parameters, together with geological consideration and other bulk oil properties (e.g. the gas to oil ratio and density), suggest that the condensates and light oils in the Huachang oil and gas field are mainly sourced from the Bailian sag that is located to the northeast of the Huachang uplift in the Fushan depression. [source] Large-scale Tazhong Ordovician Reef-flat Oil-Gas Field in the Tarim Basin of ChinaACTA GEOLOGICA SINICA (ENGLISH EDITION), Issue 1 2009Xinyuan ZHOU Abstract: The Tazhong reef-flat oil-gas field is the first large-scale Ordovician organic reef type oil-gas field found in China. Its organic reefs were developed in the early Late Ordovician Lianglitag Formation, and are the first large reefs of the coral-stromatoporoid hermatypic community found in China. The organic reefs and platform-margin grain banks constitute a reef-flat complex, mainly consisting of biolithites and grainstones. The biolithites can be classified into the framestone, bafflestone, bindstone etc. The main body of the complex lies around the wells from Tazhong-24 to Tazhong-82, trending northwest, with the thickness from 100 to 300 m, length about 220 km and width 5,10 km. It is a reef-flat lithologic hydrocarbon reservoir, with a very complex hydrocarbon distribution: being a gas condensate reservoir as a whole with local oil reservoirs. The hydrocarbon distribution is controlled by the reef complex, generally located in the upper 100,200 m part of the complex, and largely in a banded shape along the complex. On the profile, the reservoir shows a stratified feature, with an altitude difference of almost 2200 m from southeast to northwest. The petroleum accumulation is controlled by karst reservoir beds and the northeast strike-slip fault belt. The total geologic reserves had reached 297.667 Mt by 2007. [source] North-south Differentiation of the Hydrocarbon Accumulation Pattern of Carbonate Reservoirs in the Yingmaili Low Uplift, Tarim Basin, Northwest ChinaACTA GEOLOGICA SINICA (ENGLISH EDITION), Issue 3 2008Lü Xiuxiang Abstract: By analyzing the characteristics of development, structural evolution and reservoir beds of the residual carbonate strata, this study shows that the residual carbonate strata in the Yingmaili low uplift are favorable oil and gas accumulation series in the Tabei (northern Tarim uplift) uplift. There are different patterns of hydrocarbon accumulation on the northern and southern slopes of the Yingmaili low uplift. The north-south differentiation of oil reservoirs were caused by different lithologies of the residual carbonate strata and the key constraints on the development of the reservoir beds. The Mesozoic terrestrial organic matter in the Kuqa depression and the Palaeozoic marine organic matter in the Manjiaer sag of the Northern depression are the major hydrocarbon source rocks for the northern slope and southern slope respectively. The hydrocarbon accumulation on the northern and southern slopes is controlled by differences in maturity and thermal evolution history of these two kinds of organic matter. On the southern slope, the oil accumulation formed in the early stage was destroyed completely, and the period from the late Hercynian to the Himalayian is the most important time for hydrocarbon accumulation. However, the time of hydrocarbon accumulation on the northern slope began 5 Ma B.P. Carbonate inner buried anticlines reservoirs are present on the southern slope, while weathered crust and paleo-buried hill karst carbonate reservoirs are present on the northern slope. The northern and southern slopes had different controlling factors of hydrocarbon accumulation respectively. Fracture growth in the reservoir beds is the most important controlling factor on the southern slope; while hydrocarbon accumulation on the northern slope is controlled by weathered crust and cap rock. [source] | |||||||||||||