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1.
Shale reservoirs of the Middle and Upper Devonian Horn River Group provide an opportunity to study the influence of rock composition on permeability and pore throat size distribution in high maturity formations. Sedimentological, geochemical and petrophysical analyses reveal relationships between rock composition, pore throat size and matrix permeability.In our sample set, measured matrix permeability ranges between 1.69 and 42.81 nanodarcies and increases with increasing porosity. Total organic carbon (TOC) content positively correlates to permeability and exerts a stronger control on permeability than inorganic composition. A positive correlation between silica content and permeability, and abundant interparticle pores between quartz crystals, suggests that quartz may be another factor enhancing the permeability. Pore throat size distributions are strongly related to TOC content. In organic rich samples, the dominant pore throat size is less than 10 nm, whereas in organic lean samples, pore throat size distribution is dominantly greater than 20 nm. SEM images suggest that in organic rich samples, organic matter pores are the dominant pore type, whereas in quartz rich samples, the dominant type is interparticle pores between quartz grains. In clay rich and carbonate rich samples, the dominant pore type is intraparticle pores, which are fewer and smaller in size.High permeability shales are associated with specific depositional facies. Massive and pyritic mudstones, rich in TOC and quartz, have comparatively high permeability. Laminated mudstone, bioturbated mudstone and carbonate facies, which are relatively enriched in clay or carbonate, have fairly low permeability. 相似文献
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The preservation of good petrophysical properties (high porosity/high permeability) at great depth in carbonate rocks may lead to the existence of a deeply buried reservoir (DBR), a target of interest for the oil industry. One of the key processes controlling diagenesis of the burial environment is Pressure Solution Creep (PSC), an efficient compaction process responsible for the evolution of porosity and permeability in many carbonate reservoirs. In this experimental study, we examine the effect of i) the presence of oil in the pore space and ii) its timing of injection on the PSC process and the petrophysical properties of a carbonate rock. The experiments were performed using a flow-through high-pressure cell, allowing the simulation of the pressure/stresses and temperature conditions of a DBR. Multi-disciplinary data (mechanical, chemical, petrographical and petrophysical) demonstrate that, without oil in the pore space, the main diagenetic process is the PSC, a process reducing by three the initial porosity but having no influence on intrinsic water permeability. An early injection of oil prior to water circulation causes the inhibition of PSC by the coating of the grains, leading to the preservation of porosity. Conversely, a late injection of oil does not preserve initial porosity. The dataset obtained from these experiments show the importance of the timing of oil charging in a reservoir in the preservation of initial porosity at great depth by the inhibition of PSC. However, the coating of grains by hydrocarbons may also inhibit further diagenetic processes leading to a creation of secondary porosity at depth. 相似文献
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The recent major discoveries of petroleum in Pre-Salt carbonate reservoirs, of mainly lacustrine origin, offshore Brazil has increased interest in studying these complex non-marine reservoirs, which present many production-development challenges, largely due to their heterogeneous nature. Some of the reservoir carbonate rock-types present in Brazil are limestones composed predominantly of bivalve shells, which are known as ‘coquinas’.The coquinas show a variety of pore types, pore sizes, pore shapes and pore connectivity which define their porosity and strongly influence the permeability and resulting electrical resistivity but this aspect of these relationships in these carbonates has been relatively poorly characterised (particularly in a quantitative manner) in the literature. The petrophysical characterisation of the coquinas of the Morro de Chaves Formation (Barremian-Aptian), exposed in a quarry in NE Brazil, was carried out using the outcrop-selected samples, plugs and petrographic thin-sections to investigate these aspects. Porosity, permeability, grain density and porosity exponent (m) measurements were carried out on the plugs. X-ray microtomography was performed to identify key characteristics of the pore system and for the basis of 3-D modelling.Significant variation in m was observed across the plug data set, which is not unexpected in carbonates, but it suggested that a range of fabrics and pore topology were present in these rocks, which are described only as calcirudites. Modelling of the resistivity using 3D pore scale models was used to understand the role of disconnected macro-pores and dissolution seams in controlling the more extreme variation in petrophysical properties observed in the coquinas. This understanding of the controls on resistivity pathways in this outcrop coquina will help in understanding the pore types in the subsurface and the estimation of saturations in these complex rocks where they are found to be oil-bearing. 相似文献
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Compared to conventional reservoirs, pore structure and diagenetic alterations of unconventional tight sand oil reservoirs are highly heterogeneous. The Upper Triassic Yanchang Formation is a major tight-oil-bearing formation in the Ordos Basin, providing an opportunity to study the factors that control reservoir heterogeneity and the heterogeneity of oil accumulation in tight oil sandstones.The Chang 8 tight oil sandstone in the study area is comprised of fine-to medium-grained, moderately to well-sorted lithic arkose and feldspathic litharenite. The reservoir quality is extremely heterogeneous due to large heterogeneities in the depositional facies, pore structures and diagenetic alterations. Small throat size is believed to be responsible for the ultra-low permeability in tight oil reservoirs. Most reservoirs with good reservoir quality, larger pore-throat size, lower pore-throat radius ratio and well pore connectivity were deposited in high-energy environments, such as distributary channels and mouth bars. For a given depositional facies, reservoir quality varies with the bedding structures. Massive- or parallel-bedded sandstones are more favorable for the development of porosity and permeability sweet zones for oil charging and accumulation than cross-bedded sandstones.Authigenic chlorite rim cementation and dissolution of unstable detrital grains are two major diagenetic processes that preserve porosity and permeability sweet zones in oil-bearing intervals. Nevertheless, chlorite rims cannot effectively preserve porosity-permeability when the chlorite content is greater than a threshold value of 7%, and compaction played a minor role in porosity destruction in the situation. Intensive cementation of pore-lining chlorites significantly reduces reservoir permeability by obstructing the pore-throats and reducing their connectivity. Stratigraphically, sandstones within 1 m from adjacent sandstone-mudstone contacts are usually tightly cemented (carbonate cement > 10%) with low porosity and permeability (lower than 10% and 0.1 mD, respectively). The carbonate cement most likely originates from external sources, probably derived from the surrounding mudstone. Most late carbonate cements filled the previously dissolved intra-feldspar pores and the residual intergranular pores, and finally formed the tight reservoirs.The petrophysical properties significantly control the fluid flow capability and the oil charging/accumulation capability of the Chang 8 tight sandstones. Oil layers usually have oil saturation greater than 40%. A pore-throat radius of less than 0.4 μm is not effective for producible oil to flow, and the cut off of porosity and permeability for the net pay are 7% and 0.1 mD, respectively. 相似文献
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Pore-throat size is a very crucial factor controlling the reservoir quality and oiliness of tight sandstones, which primarily affects rock-properties such as permeability and drainage capillary pressure. However, the wide range of size makes it difficult to understand their distribution characteristics as well as the specific controls on reservoir quality and oiliness. In order to better understand about pore-throat size distribution, petrographic, scanning electron microscopy (SEM), pressure-controlled mercury injection (PMI), rate-controlled mercury injection (RMI), quantitative grain fluorescence (QGF) and environmental scanning electron microscopy (ESEM) investigations under laboratory pressure conditions 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 sandstones in this study showed different types of pore structures: intergranular pores, dissolution pores, pores within clay aggregates and even some pores related to micro fractures. The pore-throat sizes vary from nano- to micro-scale. The PMI technique views the pore-throat size ranging from 0.001 μm to 63 μm and revealed that the pore-throats with radius larger than 1.0 μm are rare and the pore-throat size distribution curves show evident fluctuations. RMI measurements indicated that the pore size distribution characteristics of the samples with different porosity and permeability values look similar. The throat size and pore throat radius ratio distribution curves had however significant differences. The overall pore-throat size distribution of the K1q4 tight sandstones was obtained with the combination of the PMI and RMI methods. The permeability is mainly contributed by a small part of larger pore-throats (less than 30%) and the ratio of the smaller pore-throats in the samples increases with decreasing permeability. Although smaller pore-throats have negligible contribution on reservoir flow potential, they are very significant for the reservoir storage capacity. The pore-throats with average radius larger than 1.0 μm mainly exist in reservoirs with permeability higher than 0.1mD. When the permeability is lower than 0.1mD, the sandstones are mainly dominated by pore-throats with average radius from 0.1 μm to 1.0 μm. The ratio of different sized pore-throats controls the permeability of the tight sandstone reservoirs in different ways. We suggest that splitting or organizing key parameters defining permeability systematically into different classes or functions can enhance the ability of formulating predictive models about permeability in tight sandstone reservoirs. The PMI combined with QGF analyses indicate that oil emplacement mainly occurred in the pore-throats with radius larger than about 0.25–0.3 μm. This result is supported by the remnant oil micro-occurrence evidence observed by SEM and ESEM. 相似文献
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Ancient lacustrine storm-deposits that act as petroleum reservoirs are seldom reported. The Lijin Sag, which is located in the southeastern corner of the Bohai Bay Basin in East China, is a NE–SW trending Cenozoic half-graben basin. Some of its Eocene deposits (Bindong deposits) were interpreted as lacustrine tempestites. The Bindong tempestites, which developed in the lower part of the upper fourth member of the Shahejie Formation (Es41), constitute a new kind of petroleum reservoir and are novel petroleum exploration targets in the Bindong Area. However, the characteristics of the Es41 Bindong tempestite reservoirs and their controlling factors are poorly understood. Point-count analyses of thin sections, scanning electron microscope image analyses, X-ray diffractometry data, and the petrophysical parameters of the Bindong tempestite reservoirs were utilized to estimate the reservoir quality. The reservoirs have undergone significant diagenetic alteration, which can be divided into negative and positive aspects. The negative alteration includes compaction, authigenic minerals, and cementation such as carbonates, clay minerals and overgrowths of quartz and feldspar. The uneven distribution of carbonate cement increased the reservoir’s heterogeneity, with carbonate cement commonly precipitating along the sandstone-mudstone contacts. The primary porosity was severely reduced because of compaction and extensive carbonate cementation. Positive alteration includes dissolution, carbonate cementation, undercompaction and fractures. Carbonate cementation exhibited both positive and negative effects on the reservoir quality. Overall, the objective reservoir quality is quite poor. A quantitative evaluation of the reservoirs’ potential was conducted. The cutoff values of several of the reservoir’s parameters were calculated. The lower limits of the porosity and permeability are 8.35–5.85% and 1.2587–0.2753 × 10–3 μm2, respectively, depending on the depth. The upper limits of the carbonate and mud content are approximately 18.5% and 9–10%, respectively. A fundamental understanding of these characteristics will provide necessary information for extracting hydrocarbons from analogous subsurface reservoirs. 相似文献
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Understanding the pore structure characteristics of tight gas sandstones is the primary purpose of reservoir evaluation and efforts to characterize tight gas transport and storage mechanisms and their controls. Due to the various pore types and multi-scale pore sizes in tight reservoirs, it is essential to combine several techniques to characterize pore structure. Scanning electron microscopy (SEM), nitrogen gas adsorption (N2GA), mercury intrusion porosimetry (MIP) and nuclear magnetic resonance (NMR) were conducted on tight sandstones from the Lower Cretaceous Shahezi Formation in the northern Songliao Basin to investigate pore structure characteristics systematically (e.g., type and size distribution of pores) and to establish how significant porosity and permeability are for different pore types. The studied tight sandstones are composed of intergranular pores, dissolution pores and intercrystalline pores. The integration of N2GA and NMR can be used as an efficient method to uncover full pore size distribution (PSD) of tight sandstones, with pore sizes ranging from 2 nm to dozens of microns. The full PSDs indicate that the pore sizes of tight sandstones are primarily distributed within 1.0 μm. With an increase in porosity and permeability, pores with larger sizes contribute more to porosity. Intercrystalline pores and intergranular/dissolution pores can be clearly distinguished on the basis of mercury intrusion and surface fractal. The relative contribution of intercrystalline pores to porosity ranges from 58.43% to 91.74% with an average of 79.74%. The intercrystalline pores are the primary contributor to pore space, whereas intergranular/dissolution pores make a considerably greater contribution to permeability. A specific quantity of intergranular/dissolution pores is the key to producing high porosity and permeability in tight sandstone reservoirs. The new two permeability estimation models show an applicable estimation of permeability with R2 values of 0.955 and 0.962 for models using Dmax (pore diameter corresponding to displacement pressure) and Df (pore diameter at inflection point), respectively. These results indicate that both Dmax and Df are key factors in determining permeability. 相似文献
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Reservoir quality and heterogeneity are critical risk factors in tight oil exploration. The integrated, analysis of the petrographic characteristics and the types and distribution of diagenetic alterations in the Chang 8 sandstones from the Zhenjing area using core, log, thin-section, SEM, petrophysical and stable isotopic data provides insight into the factors responsible for variations in porosity and permeability in tight sandstones. The results indicate that the Chang 8 sandstones mainly from subaqueous distributary channel facies are mostly moderately well to well sorted fine-grained feldspathic litharenites and lithic arkose. The sandstones have ultra-low permeabilities that are commonly less than 1 mD, a wide range of porosities from 0.3 to 18.1%, and two distinct porosity-permeability trends with a boundary of approximately 10% porosity. These petrophysical features are closely related to the types and distribution of the diagenetic alterations. Compaction is a regional porosity-reducing process that was responsible for a loss of more than half of the original porosity in nearly all of the samples. The wide range of porosity is attributed to variations in calcite cementation and chlorite coatings. The relatively high-porosity reservoirs formed due to preservation of the primary intergranular pores by chlorite coatings rather than burial dissolution; however, the chlorites also obstruct pore throats, which lead to the development of reservoirs with high porosity but low permeability. In contrast, calcite cementation is the dominant factor in the formation of low-porosity, ultra-low-permeability reservoirs by filling both the primary pores and the pore throats in the sandstones. The eogenetic calcites are commonly concentrated in tightly cemented concretions or layers adjacent to sandstone-mudstone contacts, while the mesogenetic calcites were deposited in all of the intervals and led to further heterogeneity. This study can be used as an analogue to understand the variations in the pathways of diagenetic evolution and their impacts on the reservoir quality and heterogeneity of sandstones and is useful for predicting the distribution of potential high-quality reservoirs in similar geological settings. 相似文献
10.
The Oolithe Blanche Formation was studied in three quarries, located at the south-eastern edge of the Paris Basin (France). Heterogeneities in reservoir properties were assessed through a sedimentological, diagenetic and petrophysical study. The relationships between depositional settings, diagenesis and petrophysical properties were analysed using detailed petrographic studies, image analysis, Nano CT-scans and petrophysical measurements.The carbonate reservoir pore network is mainly controlled by intraparticle microporosity which ensures the connectivity with interparticle meso- and macroporosity.Early cementation vs. early compaction processes (mainly grain interpenetration) may have considerable influence on fluid-flow properties and parameters such as permeability, acoustic velocities and tortuosity. Better reservoir properties are found when compaction processes begin before cementation.From statistical analyses, e.g. Principal Component Analysis and Linear Discriminant Analysis, a sedimentological/diagenetic and petrophysical model is proposed that is in a good agreement with the geological model developed from field work. 相似文献
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An integrated petrographical and petrophysical study was carried out on a set of 35 outcrop chalk samples, covering a wide range of lithologies and textures. In this study various chalk rock-types have been characterized, in terms of microtextures and porous network, by integrating both geological, sediment-petrological and petrophysical data, including porosity, permeability, low-field NMR (Nuclear Magnetic Resonance), MICP and specific surface area (BET) measurements. The data allow an in depth understanding of the NMR signal of chalks, with a focus on tight chalks, including all low reservoir quality chalks independently of their sedimentological and/or diagenetic history. The study aims to develop an NMR-based approach to characterize a broad range of chalk samples. The provided laboratory low-field NMR chalk classification can be used as a guide to interpret NMR logging data.Based on the petrographical and petrophysical analysis, 6 groups of samples were identified, each of them characterized by a unique NMR signature: (1) micritic chalks, (2) grainy chalks, (3) cemented chalks, (4) marl-seam chalks, (5) argillaceous chalks and (6) silicified chalk. NMR T2 distributions were linked to pore body size and T2 logarithmic (T2lm) was calculated. It is apparent that tight chalks, whether their characteristics are sedimentological or diagenetic, yield smaller pore body sizes (T2lm < 20 ms), as well as narrower pore throats (average radius < 150 nm) and lower permeability values (typically below 0.2 mD). Grainy chalks possess T2 distributions reflecting larger pore sizes (T2lm > 60 ms) and pore throats (average radius > 290 nm) and higher permeabilities (up to 13 mD). The marl-seam chalk samples yield bimodal T2 distributions, with a first peak related to the micritic matrix pores and a second peak related to intraparticle pores within fossils. For all samples, permeability was inferred from NMR spectra using SDR (Schlumberger Doll Research) model. 相似文献
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The Zagros-Taurus fold and thrust belt hosts a prolific hydrocarbon system. Most hydrocarbon reserves are stored in naturally fractured reservoirs and such fracture systems can therefore have a significant impact on reservoir performance. Fractures are one of the most important paths for fluid flow in carbonate reservoirs, and industrial geoscientists and engineers therefore need to understand and study fracture patterns in order to optimise hydrocarbon production. The observed fracture patterns in outcrops may have implications on fluid flow and reservoir modelling in subsurface reservoirs, and we have therefore undertaken a case study of fracturing associated with regional folding in Iraqi Kurdistan. In this area, some exploration wells currently target Upper Triassic dolostones (Kurra Chine Formation) and/or Lower Jurassic limestones and dolomitised limestones (Sehkaniyan Formation). In both units hydrocarbon production comes mainly from secondary porosity created by dolomitisation, dissolution and fracturing. Both formations have undergone multiple phases of deformation associated with burial, uplift, folding and thrusting. We investigate some fracture pattern characteristics and some petrophysical properties of these units using selected outcrops around the Gara, Ora and Ranya anticlines that form folds directly traceable for 25–70 km. Our outcrop data is compared with subsurface fracture and petrophysical datasets reported from wells in the nearby Shaikhan and Swara Tika Fields. The 1-2-3D fracture attributes collected from outcrops are fracture orientation, type, spacing, intensity, length and cross-cutting and abutting relationships. Fracture orientations show a clear relationship to the local fold axis in both the outcrop and subsurface, although in some cases they appear to relate more to the present day in-situ maximum horizontal stress direction or local strike-slip faulting. Three stages of fracturing are proposed: pre-folding, early-folding and post-folding fractures. In addition, we report petrophysical properties - porosity, permeability and acoustic velocity of both the Kurra Chine and Sehkaniyan formations in relation to their structural position within folds and faults and stratigraphic level. The highest porosities and permeabilities are recorded in the hinges and backlimbs of the Gara Anticline. The best reservoir quality (highest porosity and permeability) is often found in areas associated with replacement dolomite i.e. solution vugs and intercrystalline porosity. The Kurra Chine Formation displays similar trends in velocity-porosity data at both outcrop and the subsurface. However, the Sehkaniyan Formation displays lower acoustic velocity for a given porosity at outcrop compared to the subsurface. 相似文献
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Lacustrine deep-water turbidite plays are a novel area for exploration in the Huimin Depression, Bohai Bay Basin. Turbidites in the Shang 847 block, a typical turbidite play in the Huimin Depression, provide an opportunity to study the factors controlling the reservoir properties and hydrocarbon accumulation in lacustrine turbidite sandstones. The reservoir quality of turbidite sandstones (very fine-grained, moderately to well sorted, mainly lithic arkose) in this study area are mainly controlled by the distribution patterns of carbonate cements and pseudomatrix. Significant inverse relationships exist between the volume of carbonate cement and both porosity and permeability of the turbidite sandstones. Carbonate cement is located preferentially near the margins of the sandstone bodies. Sandstones with distance from the sandstone–mudstone contact surface less than 0.7 m or with thickness less than 1.2 m are commonly tightly cemented (carbonate cement >15%) with low porosity and permeability (lower than 10% and 0.1 mD, respectively). The source of carbonate cement was most likely external, probably derived from the surrounding mudstone. Most pore-filling carbonate cements occurred during late diagenesis at burial depths greater than 2200 m. The petrophysical properties of turbidites have a positive relationship with the content of kaolinite and chlorite, but have a negative relationship with the content of illite. 2-D and 3-D reconstructions of non-oil bearing and oil-bearing layers indicate that dissolution of carbonate cement, feldspars and unstable rock fragments was more developed in oil-bearing layers than in non-oil bearing layers and hance oil-bearing layers have higher porosity and larger pore sizes. Petrophysical property appears to have a significant effect on the hydrocarbon accumulation in the turbidite sandstones. Sandstones with porosities lower than 9% and/or permeabilities lower than 0.78 mD are not prone to contain oil. 相似文献
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Shales from the Lower Silurian Longmaxi Formation in the Sichuan Basin are among the most important shale gas reservoirs in China, and have been investigated because of their great shale gas potential. To understand the pore structure and fractal characteristics of the shales, a series of experiments was conducted on core samples from the Lower Silurian Longmaxi Formation in the Sichuan Basin of China, including X-ray diffraction (XRD), total organic carbon (TOC) content and vitrinite reflectance (Ro) analysis, field emission-environmental scanning electron microscope (FE-ESEM) observation, and low-pressure N2 adsorption-desorption experiments. Frenkel-Halsey-Hill (FHH) method was applied to calculate fractal dimensions. In addition, the pore genesis, the relationships between composition and thermal maturity, the pore structure parameters, and the fractal dimensions are discussed. FE-ESEM observation results show that the Longmaxi Formation shales are dominated by organic-matter (OM) pores along with interparticle (interP) pores, intraparticle (intraP) pores and fracture pores. This study identified the fractal dimensions at relative pressures of 0–0.45 and 0.45–1 as D1 and D2 respectively. D1 ranged from 2.60 to 2.71 and D2 ranged from 2.71 to 2.82. D1 was typically smaller than D2, indicating that the smaller pores in shales were more homogeneous than the larger ones. The formation of these OM pores is owing to kerogen deformation during the thermal maturation, which results in a large number of nanopores. The pore structure of the Longmaxi Formation shales is primarily controlled by TOC content and thermal maturity. TOC content is a controlling factor on the fractal dimensions as it exhibited positive correlations with D1 and D2. Fractal dimensions are useful for the characterization of the pore structures complexity of the Longmaxi Formation shales because D1 and D2 correlate well with pore structure parameters as they both increase with the increase of surface area and the decrease of average pore diameter. 相似文献
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Previous studies have determined many types of pores in shale, such as organic pores, inorganic pores and microfractures. In this study, pores are classified as intergranular, intraparticle, and organic pores based on the location of their occurrence. The heterogeneities of the three pore types and their effects on the occurrence of shale gas, which is of utmost practical importance for shale gas exploration and development, are discussed. In this study, the three types of pores are quantitatively characterized using fractal and multifractal methods. The mean fractal dimension and mean width of the multifractal spectrum of these pores are found to be different, i.e., 1.5985 and 1.665 for intraparticle pores, 1.5869 and 1.475 for intergranular pores, and 1.6 and 1.3725 for organic pores. Intraparticle pores have the highest heterogeneity, intergranular pores have intermediate heterogeneity, and organic pores have the lowest heterogeneity. SEM images show that organic pores have good connectivity, homogeneous distribution, and small range of aperture change but have the lowest heterogeneity even where pores are abundant; thus, they provide the largest shale gas occurrence space. In contrast, intergranular pores are less abundant, have lower connectivity, and have higher heterogeneity than organic pores, thereby providing a relatively smaller shale gas occurrence space. Finally, intraparticle pores are the least abundant and possess the poorest connectivity, largest range of aperture change, and highest heterogeneity of the three pore types, thereby providing the smallest shale gas occurrence space. We conclude that organic pores are crucial to the occurrence of shale gas and can provide a new index for the evaluation of shale gas exploration and development. 相似文献
16.
The Caddo Limestone forms economic carbonate reservoirs in Stephens County, northern Texas. This study demonstrates that, in the Caddo Limestone of the Eliasville and Breckenridge fields, porosity and permeability are best developed in phylloid-algal wackestones and packstones, as well as Komia wackestones and packstones prevalent within the uppermost interval (i.e., Cycle A) of the formation in the study area. The main reservoirs formed in the upper and middle intervals of the Caddo algal mounds because of meteoric dissolution related to subaerial exposure (which created a large volume of secondary pores) and early cementation that prevented mechanical compaction. A great portion of the secondary pores remain open, providing the principal pore spaces of the reservoir interval. Vugs (including moldic voids) are abundant, and dissolution-enhanced intragranular pores are very common within widespread Komia. Intercrystalline pores are prevalent in dolomitized and neomorphised lithofacies where micrite was converted to microsparitic and sparitic calcite. Micropores are abundant in the matrix and within grains (especially Komia fragments). The lower or basal interval of Cycle A is commonly much less porous owing to the substantial loss of primary pores by physical compaction and lack (or rare presence) of secondary pores. Laterally, wells in the areas with thicker Cycle A (interpreted as algal mounds) have higher porosity and thicker net reservoir than those in intermound areas. This work provides a case study of carbonate reservoirs in which Komia wackestones and packstones are the major reservoir rocks. 相似文献
17.
渤东低凸起东营组储集层以低渗为特征,低渗成为制约该区东营组勘探的重要因素.通过多种分析测试方法,研究了渤东低凸起L3构造东营组低渗储集层特征,探讨了低渗储集层成因.L3构造东营组储集层砂岩溶蚀作用发育,斜长石含量低,碳酸盐胶结物含量低,高岭石含量高,石英加大明显.储集层主要以中孔低—特低渗为主,孔径小,连通差,吼道窄,排驱压力大.微量元素分析表明,研究区东营组沉积时为淡水环境;测井和岩心观察证实,地层中含多层碳质泥岩和煤层.早期腐殖酸的溶蚀作用,造成低温下不稳定的斜长石大量溶蚀,这些溶蚀孔隙在后期深埋过程中受压实和成岩作用影响被复杂化、细小化是储集层低渗的主要原因.早期碳酸盐胶结物少,岩石抗压实能力差也是储层低渗的重要原因. 相似文献
18.
东海陆架盆地西湖凹陷古近系花港组储层为典型的低孔、低渗储层。基于大量岩心物性、粒度、薄片、压汞等资料,对N气田目的层储层岩性、物性和孔隙结构特征进行精细评价。结果表明:N气田花港组储层岩性以细砂岩为主,矿物成分构成稳定,以石英为主,黏土含量低,岩性较纯;随着埋藏变深,孔隙变差,粒间孔减少,溶蚀孔增加,孔喉半径减小,连通性变差;局部发育砂砾岩,且渗透率大于细砂岩一个数量级以上,可作为甜点储层开发。基于实验和试油资料统计结果,建立了一套适用于花港组储层的综合分类评价标准,包含孔隙度、渗透率、饱和度和地质特征4类储层重要参数,分类结果特征鲜明,分类依据科学可靠,为该区域低孔、低渗储层勘探开发提供依据。 相似文献
19.
Dongxia Chen Xiongqi Pang Zhenxue Jiang Jianhui Zeng Nansheng Qiu Maowen Li 《Marine and Petroleum Geology》2009
A great difference exists between the hydrocarbon charging characteristics of different Tertiary lacustrine turbidites in the Jiyang Super-depression of the Bohai Bay Basin, east China. Based on wireline log data, core observation and thin-section analyses, this study presents detailed reservoir property data and their controlling effects from several case studies and discusses the geological factors that govern the hydrocarbon accumulation in turbidite reservoirs. The lacustrine fluxoturbidite bodies investigated are typically distributed in an area of 0.5–10 km2, with a thickness of 5–20 m. The sandstones of the Tertiary turbidites in the Jiyang Super-depression have been strongly altered diagenetically by mechanical compaction, cementation and mineral dissolution. The effect of compaction caused the porosity to decrease drastically with the burial depths, especially during the early diagenesis when the porosity was reduced by over 15%. The effect of cementation and mineral dissolution during the late-stage diagenesis is dominated by carbonate cementation in sandstones. High carbonate cement content is usually associated with low porosity and permeability. Carbonate dissolution (secondary porosity zone) and primary calcite dissolution is believed to be related to thermal maturation of organic matter and clay mineral reactions in the surrounding shales and mudstone. Two stages of carbonate cementation were identified: the precipitation from pore-water during sedimentation and secondary precipitation in sandstones from the organic acid-dissolved carbonate minerals from source rocks. Petrophysical properties have controlled hydrocarbon accumulation in turbidite sandstones: high porosity and permeability sandstones have high oil saturation and are excellent producing reservoirs. It is also noticed that interstitial matter content affects the oil-bearing property to some degree. There are three essential elements for high oil-bearing turbidite reservoirs: excellent pore types, low carbonate cement (<5%) and good petrophysical properties with average porosity >15% and average permeability >10 mD. 相似文献
20.
This paper provides an example of an integrated multi-scale study of a carbonate reservoir. The Danian Lower R2 carbonate reservoir is located in the South of the Aquitaine Basin (France) and represents a potential underground gas storage site for Gaz de France. The Danian Lower R2 reservoir was deposited as a prograding carbonate platform bordered by a reef barrier. The effects of sedimentary and diagenetic events on the reservoir properties, particularly dolomitization, were evaluated. In this study, the reservoir quality has been assessed by seismic analyses at the basin scale, by log-analysis at the reservoir scale, by petrographic methods and by petrophysical tools at the pore-core scale.Two dolomitization stages, separated by a compaction event with associated fracturing and stylolites, have been identified. These diagenetic events have significantly improved the Lower R2 carbonate reservoir properties. It is demonstrated that the reservoir quality is mainly controlled by the pore-geometry, which is determined by various diagenetic processes. The permeability values of the reservoir range over 4 orders of magnitude, from 0.1 to 5600 mD and the porosity values range between 2 and 42%. Reservoir unit 4 (a karstic dolomite) shows the best reservoir properties with average porosity values ranging between 11.1% and 19.3% and an average permeability ranging between 379 and 766 mD. Reservoir unit 2 (a fine-grained limestone) shows the worst reservoir properties. The cementation factors range from 1.68 to 2.48. The dolomitic crystal carbonate texture (mainly units 3 and 4) shows the highest value of the cementation factor (1.98–2.48) and formation factor (9.54–36.97), which is due to its high degree of cementation. The saturation exponents vary between 1.2 and 3.4. Using these experimental electrical parameters and the resistivity laterolog tool we predicted the water saturation in the various reservoir units. The permeability was predicted by combining the formation factor with the micro-geometric characteristic length. The best fit is obtained with the Katz and Thompson's model and for a constant of 1/171. 相似文献