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1.
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
2.
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
3.
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
4.
The Upper Triassic Chang 6 sandstone, an important exploration target in the Ordos Basin, is a typical tight oil reservoir. Reservoir quality is a critical factor for tight oil exploration. Based on thin sections, scanning electron microscopy (SEM), X-ray diffraction (XRD), stable isotopes, and fluid inclusions, the diagenetic processes and their impact on the reservoir quality of the Chang 6 sandstones in the Zhenjing area were quantitatively analysed. The initial porosity of the Chang 6 sandstones is 39.2%, as calculated from point counting and grain size analysis. Mechanical and chemical compaction are the dominant processes for the destruction of pore spaces, leading to a porosity reduction of 14.2%–20.2% during progressive burial. The porosity continually decreased from 4.3% to 12.4% due to carbonate cementation, quartz overgrowth and clay mineral precipitation. Diagenetic processes were influenced by grain size, sorting and mineral compositions. Evaluation of petrographic observations indicates that different extents of compaction and calcite cementation are responsible for the formation of high-porosity and low-porosity reservoirs. Secondary porosity formed due to the burial dissolution of feldspar, rock fragments and laumontite in the Chang 6 sandstones. However, in a relatively closed geochemical system, products of dissolution cannot be transported away over a long distance. As a result, they precipitated in nearby pores and pore throats. In addition, quantitative calculations showed that the dissolution and associated precipitation of products of dissolution were nearly balanced. Consequently, the total porosity of the Chang 6 sandstones increased slightly due to burial dissolution, but the permeability decreased significantly because of the occlusion of pore throats by the dissolution-associated precipitation of authigenic minerals. Therefore, the limited increase in net-porosity from dissolution, combined with intense compaction and cementation, account for the low permeability and strong heterogeneity in the Chang 6 sandstones in the Zhenjing area. 相似文献
5.
Shuyun Xie Qiuming Cheng Qicong Ling Bing Li Zhengyu Bao Ping Fan 《Marine and Petroleum Geology》2010
The petrophysical evaluation of the reservoir capacity is of great importance in predicting the reserves and productivity of petroleum fields, which may directly affect petroleum exploration. In the past, such kind of evaluation was mainly based on the experimental measurements of the petrophysical porosity and permeability of reservoir rock samples. Assessing quantitatively the microstructures of carbonates, including irregularities of pore shapes and frequency distributions of pore sizes, is becoming one of the most challenging efforts in pore-scale analysis. Based on the digital analyses of the two-dimensional images from thin sections taken under the environmental scanning electron microscope (ESEM) at various magnification scales, the current paper tries to quantify the pore spaces of carbonate samples by fractal and multifractal methods, which have been demonstrated to be effective. The study area is located in the western Hubei and eastern Sichuan, China. As many as 25 carbonate samples from various members in five formations of the Permian-Triassic periods and 132 ESEM images were chosen in this study. All individual pores had been recognized, and their areas and perimeters had been calculated as well. The box-counting fractal dimensions and four major multifractal parameters associated with the multifractal spectra are used. The results show that the values of the petrophysical porosity and permeability are closely related to the box-counting dimensions and the multifractal parameters, which demonstrates that the textural arrangements of the pores control the porosity and permeability to a certain extent. There is also a link between the reservoiring capabilities of different formations and the fractal and multifractal parameters. The reservoiring capability assessment result is in agreement with the field research analysis. 相似文献
6.
7.
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
8.
Oil-water transition zones in carbonate reservoirs represent important but rarely studied diagenetic environments that are now increasingly re-evaluated because of their potentially large effects on reservoir economics. Here, data from cathodoluminescence and fluorescence microscopy, isotope geochemistry, microthermometry, and X-ray tomography are combined to decipher the diagenetic history of a 5-m-long core interval comprising the oil-water transition zone in a Lower Pennsylvanian carbonate reservoir. The aim is to document the cementation dynamics prior, during, and after oil emplacement in its context of changing fluid parameters. Intergrain porosity mean values of 7% are present in the upper two sub-zones of the oil-water transitions zone but values sharply increase to a mean of 14% in the lower sub-zone grading into the water-saturated portions of the reservoir and a very similar pattern is observed for permeability values. In the top of the water-filled zone, cavernous porosity with mean values of about 24% is found. Carbonate cements formed from the earliest marine to the late burial stage. Five calcite (Ca-1 through 5) and one dolomite (Dol) phase are recognized with phase Ca-4b recording the onset of hydrocarbon migration. Carbon and oxygen cross-plots clearly delineate different paragenetic phases with Ca-4 representing the most depleted δ13C ratios with mean values of about −21‰. During the main phase of oil emplacement, arguably triggered by far-field Alpine tectonics, carbonate cementation was slowed down and eventually ceased in the presence of hydrocarbons and corrosive fluids with temperatures of 110–140 °C and a micro-hiatal surface formed in the paragenetic sequence. These observations support the “oil-inhibits-diagenesis” model. The presence an earlier corrosion surface between phase Ca-3 and 4 is best assigned to initial pulses of ascending corrosive fluids in advance of hydrocarbons. The short-lived nature of the oil migration event found here is rather uncommon when compared to other carbonate reservoirs. The study is relevant as it clearly documents the strengths of a combined petrographic and geochemical study in order to document the timing of oil migration in carbonate reservoirs and its related cementation dynamics. 相似文献
9.
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
10.
Thin-bedded beach-bar sandstone reservoirs are common in the Eocene Shahejie Formation (Es4s) of Niuzhuang Sag, along the southern gentle slope of the Dongying Depression. Here we report on the link between sequence stratigraphy, sedimentary facies and diagenetic effects on reservoir quality. Seismic data, wireline logs, core observations and analyses are used to interpret depositional settings and sequence stratigraphic framework. Petrographic study based on microscopic observation of optical, cathodoluminescence (CL), confocal laser scanning (LSCM) and scanning electron microscope (SEM) and X-ray diffraction (XRD) analyses were used to describe the fabric, texture, allogenic and authigenic mineralogy of these highly heterogeneous sandstone reservoirs. The Es4s interval is interpreted as third-order sequence, composed of a lowstand systems tract (LST), a transgressive systems tract (TST) and a highstand systems tract (HST). On the fourth order, twenty-nine parasequences and seven parasequence sets have been identified. Sand bodies were deposited mainly in the shoreface shallow lake beach-bar (clastic beach-bar), semi-deep lake (carbonate beach-bar) and the fluvial channels. The depositional and diagenetic heterogeneities were mainly due to the following factors: (1) fine grain size, poor sorting, and continuous thin inter-bedded mud layers with siltstone/fine-sandstone having argillaceous layers in regular intervals, (2) immature sediment composition, and (3) even with the dissolution of grains and several fractures, destruction of porosity by cementation and compaction. Secondary pores from feldspar dissolution are better developed in sandstones with increased cementation. Grain coating smectite clays preserved the primary porosity at places while dominating pore filling authigenic illite and illite/smectite clays reduced permeability with little impact on porosity. Due to the high degree of heterogeneity in the Es4s beach-bar interval, it is recognized as middle to low permeable reservoir. The aforementioned study reflects significant insight into the understanding of the properties of the beach-bar sands and valuable for the comprehensive reservoir characterization and overall reservoir bed quality. 相似文献
11.
The South Karaku
oil field is located in southeast Turkey, and produces, from the Late Cretaceous Mardin Group, carbonate reservoirs consisting of the Karababa, Derdere, Sabunsuyu and Areban Formations. The Karababa Formation is divided into three members, of which the productive Karababa-C member, discussed here, is composed of shallow marine bioclastic mudstone to wackestone. It is affected by early to late diagenetic processes that caused modification of the original pore system by cementation, dissolution and fracturing. Two petrophysical-petrologic facies can be discriminated by principal component analysis, and linear, multiple and stepwise multiple regression analysis of petrophysical data. These correspond to vuggy-moldic porosity and microporosity dominated reservoirs. 相似文献
12.
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
13.
Upper Carboniferous sandstones are one of the most important tight gas reservoirs in Central Europe. We present data from an outcrop reservoir analog (Piesberg quarry) in the Lower Saxony Basin of Northern Germany. This field-based study focuses on the diagenetic control on spatial reservoir quality distribution.The investigated outcrop consists of fluvial 4th-order cycles, which originate from a braided river dominated depositional environment. Westphalian C/D stratigraphy, sedimentary thicknesses and exposed fault orientations (NNW-SSE and W-E) reflect tight gas reservoir properties in the region further north. Diagenetic investigations revealed an early loss of primary porosity by pseudomatrix formation. Present day porosity (7% on average) and matrix permeability (0.0003 mD on average) reflect a high-temperature overprint during burial. The entire remaining pore space is occluded with authigenic minerals, predominantly quartz and illite. This reduces reservoir quality and excludes exposed rocks as tight gas targets. The correlation of petrographic and petrophysical data show that expected facies-related reservoir quality trends were overprinted by high-temperature diagenesis. The present day secondary matrix porosity reflects the telogenetic dissolution of mesogenetic ankerite cements and unstable alumosilicates.Faults are associated with both sealed and partially sealed veins near the faults, indicating localized mass transport. Around W-E striking faults, dissolution is higher in leached sandstones with matrix porosities of up to 26.3% and matrix permeabilities of up to 105 mD. The dissolution of ankerite and lithic fragments around the faults indicates focused fluid flow. However, a telogenetic origin cannot be ruled out.The results of this work demonstrate the limits of outcrop analog studies with respect to actual subsurface reservoirs of the greater area. Whereas the investigated outcrop forms a suitable analog with respect to sedimentological, stratigraphic and structural inventory, actual reservoirs at depth generally lack telogenetic influences. These alter absolute reservoir quality values at the surface. However, the temperature overprint and associated diagenetic modification, which caused the unusually low permeability in the studied outcrop, may pose a reservoir risk for tight gas exploration as a consequence of locally higher overburden or similar structural positions. 相似文献
14.
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
15.
The Jiaolai Basin (Fig. 1) is an under-explored rift basin that has produced minor oil from Lower Cretaceous lacustrine deltaic sandstones. The reservoir quality is highly heterogeneous and is an important exploratory unknown in the basin. This study investigates how reservoir porosity and permeability vary with diagenetic minerals and burial history, particularly the effects of fracturing on the diagenesis and reservoir deliverability. The Laiyang sandstones are tight reservoirs with low porosity and permeability (Φ < 10% and K < 1 mD). Spatial variations in detrital supply and burial history significantly affected the diagenetic alterations during burial. In the western Laiyang Sag, the rocks are primarily feldspathic litharenites that underwent progressive burial, and thus, the primary porosity was partially to completely eliminated as a result of significant mechanical compaction of ductile grains. In contrast, in the eastern Laiyang Sag, the rocks are lithic arkoses that were uplifted to the surface and extensively eroded, which resulted in less porosity reduction by compaction. The tectonic uplift could promote leaching by meteoric water and the dissolution of remaining feldspars and calcite cement. Relatively high-quality reservoirs are preferentially developed in distributary channel and mouth-bar sandstones with chlorite rims on detrital quartz grains, which are also the locations of aqueous fluid flow that produced secondary porosity. The fold-related fractures are primarily developed in the silt–sandstones of Longwangzhuang and Shuinan members in the eastern Laiyang Sag. Quartz is the most prevalent fracture filling mineral in the Laiyang sandstones, and most of the small-aperture fractures are completely sealed, whereas the large-aperture fractures in a given set may be only partially sealed. The greatest fracture density is in the silt–sandstones containing more brittle minerals such as calcite and quartz cement. The wide apertures are crucial to preservation of the fracture porosity, and the great variation in the distribution of fracture-filling cements presents an opportunity for targeting fractures that contribute to fluid flow. 相似文献
16.
钻井揭示庙北地区沙一段储层物性较差,该区是否发育优质储层直接影响着下一步的勘探决策。综合利用壁心、薄片、地震、钻井及分析化验等资料,分析储层特征和影响因素,探讨了优质储层分布,分析表明,庙北地区沙一段为低孔、低渗—特低渗储层,储集空间为粒间溶孔和粒内溶孔。碱性水体条件下的碳酸盐矿物强胶结、扇三角洲边缘相带和黏土矿物向伊利石的转化是导致储层物性差的主要因素,溶蚀作用是控制优质储层发育的决定因素。受沉积相带、溶蚀强度及异常高压等条件控制,同沉积断层下降盘的扇三角洲主河道区和水下隆起带上的碳酸盐岩浅滩为优质储层发育的有利区。研究成果对于该区油气勘探具有重要的参考意义。 相似文献
17.
Khalid A. Al-Ramadan Mahbub Hussain Badrul Imam Salih Saner 《Marine and Petroleum Geology》2004,21(10):1221-1234
The Lower Devonian Jauf Formation in Saudi Arabia is an important hydrocarbon reservoir. However, in spite of its importance as a reservoir, published studies on the Jauf Formation more specifically on the reservoir quality (including diagenesis), are very few. This study, which is based on core samples from two wells in the Ghawar Field, northeastern Saudi Arabia, reports the lithologic and diagenetic characteristics of this reservoir. The Jauf reservoir is a fine to medium-grained, moderate to well-sorted quartz arenite. The diagenetic processes recognized include compaction, cementation (calcite, clay minerals, quartz overgrowths, and a minor amount of pyrite), and dissolution of the calcite cements and of feldspar grains. The widespread occurrences of early calcite cement suggest that the Jauf reservoir lost a significant amount of primary porosity at a very early stage of its diagenetic history. Early calcite cement, however, prevented the later compaction of the sandstone, thus preserving an unfilled part of the primary porosity. Based on the framework grain–cement relationships, precipitation of the early calcite cement was either accompanied or followed by the development of part of the pore-lining and pore-bridging clay cement. Secondary porosity development occurred due to partial to complete dissolution of early calcite cements and feldspar. Late calcite cement occurs as isolated patches, and has little impact on reservoir quality of the sandstones.In addition to calcite, several different clay minerals including illite and chlorite occur as pore-filling and pore-lining cements. While the pore-filling illite and chlorite resulted in a considerable loss of porosity, the pore-lining chlorite may have helped in retaining the porosity by preventing the precipitation of syntaxial quartz overgrowths. Illite, which largely occurs as hair-like rims around the grains and bridges on the pore throats, caused a substantial deterioration to permeability of the reservoir. Diagenetic history of the Jauf Formation as established here is expected to help better understanding and exploitation of this reservoir. 相似文献
18.
百色盆地东部坳陷中央凹陷带那读组为陆相碎屑岩沉积地层,其储集层具有岩石结构复杂、物性条件差、低孔低渗、非均质性极强等特点,使用传统方法预测其初始产量比较困难。因此从基础资料入手,分析储层特征,并通过研究储层流体性质的响应特征,提出了运用含油指示参数OID与反映孔隙结构的参数m的交会面积方法来预测初始产量。该方法由于综合了影响该地区储层产量的孔隙度、泥质含量、厚度、含油饱和度、渗透率等关键参数,预测精度和直观性有很大的提高,较好实现对那读组致密储层产量的快速预测,实际应用效果十分显著。 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.
鄂尔多斯盆地王窑地区上三叠统长6油层成岩作用研究 总被引：15，自引：0，他引：15
通过多项测试方法，对安塞油田王窑地区长6油层含油砂体的岩石学、成岩作用、储集物性和孔隙发育特征进行分析和研究。结果表明，该区储集砂体为成分成熟度较低的长石砂岩；主要自生矿物为绿泥石、浊沸石、方解石、石英、钾长石、伊利石和钠长石等；储层次生孔隙发育，主要孔隙类型为粒间孔隙、骨架颗粒溶孔和浊沸石溶孔。孔隙结构具有小孔、细喉的特点；储层成岩演化阶段处于晚成岩A亚期；储层性质明显地受到沉积微相和成岩作用的影响。沉积物粒度较粗、厚度较大的河道砂和河口砂坝砂的储集物性明显优于各种粒度较细、厚度较薄的席状砂体。 相似文献