储集层构造裂缝定量预测方法研究

选用裂缝体积密度作为构造裂缝定量化参数,对基于钻井岩心的裂缝体积密度的计算方法作了改进。统计分析得出,破裂试件裂缝体积密度与试件破裂应变能密度的关系受试件所受的围压变化及试件物性的控制,钻井岩心构造裂缝体积密度与数值模拟应变能密度的关系同试件研究结果有可比之处。在上述研究基础上,建立了利用钻井岩心裂缝参数和数值模拟应变能密度来定量预测碳酸盐岩储层构造裂缝体积密度的方法,并已应用于油田生     

Correlation between rock fabrics and physical properties of carbonate reservoir rocks

 Three carbonate core samples from an oil and gas reservoir of the NW German basin were chosen to study the correlation between rock fabrics and physical properties of reservoir rocks. Detailed fabric analyses and texture investigations were carried out as well as laboratory measurements of different physical properties, e.g. density, porosity, permeability, electrical conductivity, seismic compressional and shear wave velocities. Although the three core samples come from a similar depositional facies, they show great differences in the occurrence and three-dimensional distribution of the rock fabric elements. These heterogeneities are the result of various diagenetic and tectonic processes. For the correlation between the rock fabrics and the physical properties four main rock fabric types have to be considered: (a) major constituents, e.g. fossils, ooides, peloides and crystals; (b) pore space with different pore types; (c) fractures; and (d) stylolites. The results of the correlation clearly show that the values and anisotropies of the petrophysical properties are fairly related to the observed fabric elements, with their different arrangements, spatial distributions and preferred orientations. These results also provide a fundamental understanding of the petrophysical responses, such as seismics, to the different geological features (e.g. fractures) and their dynamic changes with pressure, which can be converted to different depths. The knowledge gained from such correlations may lead to an improved interpretation of geophysical data for hydrocarbon exploration and production and therefore to an advanced reservoir characterization. Received: 28 January 1999 / Accepted: 21 June 1999     

A study of natural and artificially generated light hydrocarbons (C4–C13) in source rocks and petroleum fluids from offshore Mid-Norway and the southernmost Norwegian and Danish sectors

The “free” or “natural” light hydrocarbon composition obtained by thermal extraction-GC of source rock samples is compared with the light fraction generated by pyrolysis products of the kerogens. Even though there are large differences between the composition of the “free” C₄–C₁₃ hydrocarbon fraction and the same fraction generated by pyrolysis, some characteristics have been detected which can be used interchangeably for both data types. Visual inspection of gas chromatograms from thermal extracts and pyrolysates indicates that in particular the relative content of m+p xylene corresponds well between these two analytical methods. The source rock samples used are Upper Jurassic marine shales and Middle and Lower Jurassic coals and coaly shales from offshore Mid-Norway and Denmark. More detailed analysis of the data shows that the most effective parameter which can distinguish between different source rock types in both thermal extracts and pyrolysates is the m+p xylene/nC₈ ratio. This parameter has been used to derive classification diagrams for interpreting the source of light hydrocarbons of both natural petroleum fluids analysed by gas chromatography and the same fraction generated by pyrolysis of asphaltenes from the fluids.The model was first tested on 17 natural petroleum fluids from Mid-Norway since a comprehensive study of light hydrocarbon distributions already has been published. Further, the parameter was applied to correlate with asphaltene pyrolysates of the fluids from Mid-Norway and a total of 22 natural oils and condensates from the southernmost Norwegian and Danish sectors.     

Evaluating sediment yield at King Talal Reservoir from landslides along Irbid–Amman Highway

With a capacity of 86 MCM, King Talal Reservoir is considered a major water supply in Jordan. It was built exclusively to irrigate the land in the Jordan Valley. Unexpectedly, the design capacity of the reservoir was confronted by the elevated sediment inflows during and after the construction of the Irbid–Amman Highway in 1987. Since then the annual sediment inflow measured at the mouth of the reservoir was higher than expected in a similar year. Notably, the over-wet season of 1991/2, as a result of six major landslides along the highway, registered the highest sediment inflow into the reservoir. In the present work the fractional contribution of these landslides to total sediment yield at the reservoir was evaluated. The evaluation was made by applying the well-known erosion model, AGNPS (Young et al., USDA Conservation Research Report 35, 1987). To calibrate the model, it was successively applied from 1980/1 to 1990/1 on the measured sediment data before the occurrence of landslides. With a slight tune-up of some of the King Talal watershed erosion variables, fairly good agreement was obtained in some years. However, the disagreement noticed in other years might be attributed to some conservation measures practised in the watershed. Because the serious landslides occurred in the wet season of 1991/2, the model was run for the two scenarios in this year: with and without landslides. The difference in results represents the contribution of landslides to sediment yield at the reservoir. It is concluded, based on these results, that landslides, if continued without control, will definitely jeopardize the design capacity of the reservoir.     

吴家庄水库库区岩溶渗漏分析

吴家庄水库位于山西省黎城县境内 ,拟建于由西南源和北源汇合而成的浊漳河干流上 ,总库容 3.6亿 m3,属大型水利工程。坝址区基岩为震旦系串岭沟组石英砂岩 ,向上游库区依次出露寒武、奥陶系碳酸盐岩 ,其分布面积占整个库区面积的一半以上 ,岩溶渗漏是库区最主要的工程地质问题 ,它直接影响到建库规模的确定和工程的可行性 ,本文就此进行了分析、评价 ,并对建库规模提出了建议.     

Structural controls on mechanical compaction within sandstones: An example from the Apsheron Peninsula,Azerbaijan

Mechanical compaction of sand-rich reservoirs usually occurs during shallow burial and involves the rearrangement of framework grains and the ductile deformation of soft lithoclasts. The reservoir quality (porosity and permeability) of some Neogene sandstones of the South Caspian Basin has, however, been dramatically reduced by mechanical compaction involving extensive grain-fracturing (i.e. porosity collapse). These sandstones were probably susceptible to pervasive grain-fracturing because they were buried rapidly and experienced compressional deformation prior to reaching 80 °C. Consequently, they did not undergo quartz cementation and were therefore exposed to high stresses while they were extremely weak. Grain-size and structural position are also important controls on the distribution of grain fracturing in the onshore analogue in the Apsheron Peninsula. Microstructural analysis confirms that susceptibility to distributed grain-fracturing increases with increasing grain-size. Structural position has also an important impact on the distribution of porosity collapse. In particular, sandstones within the hinges of folded sections have undergone much more extensive grain-fracturing than within the surrounding area; the increased stresses in this structural position have enhanced distributed grain-fracturing and subsequent deformation band development.     

Reservoir characterization of Scollard-age fluvial sandstones,Alberta foredeep

A detailed laboratory study of 53 sandstone samples from 23 outcrops and 156 conventional core samples from the Maastrichtian-Paleocene Scollard-age fluvial strata in the Western Canada foredeep was undertaken to investigate the reservoir characteristics and to determine the effect of diagenesis on reservoir quality. The sandstones are predominantly litharenites and sublitharenites, which accumulated in a variety of fluvial environments. The porosity of the sandstones is both syn-depositional and diagenetic in origin. Laboratory analyses indicate that porosity in sandstones from outcrop samples with less than 5% calcite cement averages 14%, with a mean permeability of 16 mD. In contrast, sandstones with greater than 5% calcite cement average 7.9% porosity, with a mean permeability of 6.17 mD. The core porosity averages 17% with 41 mD permeability. Cementation coupled with compaction had an important effect in the destruction of porosity after sedimentation and burial. The reservoir quality of sandstones is also severely reduced where the pore-lining clays are abundant (>15%). The potential of a sandstone to serve as a reservoir for producible hydrocarbons is strongly related to the sandstone’s diagenetic history. Three diagenetic stages are identified: eodiagenesis before effective burial, mesodiagenesis during burial, and telodiagenesis during exposure after burial. Eodiagenesis resulted in mechanical compaction, calcite cementation, kaolinite and smectite formation, and dissolution of chemically unstable grains. Mesodiagenesis resulted in chemical compaction, precipitation of calcite cement, quartz overgrowths, and the formation of authigenic clays such as chlorite, dickite, and illite. Finally, telodiagenesis seems to have had less effect on reservoir properties, even though it resulted in the precipitation of some kaolinite and the partial dissolution of feldspar.     

Chemostratigraphy of upper Jurassic reservoir sandstones,Danish Central Graben,North Sea

A chemostratigraphic study of Upper Jurassic sandstones in the northern Danish Central Graben has been undertaken within the framework of a well-defined stratigraphic/sedimentological model based particularly on cored well sections. Two reservoir sandstone units are recognised, the transgressive marginal marine to shoreface sandstone of the Gert Member and the regressive to transgressive shoreface sandstone of the Ravn Member. Both members belong to the Heno Formation, which is equivalent to the Fulmar Formation (UK) and the Ula Formation (Norway).     

Turbidite-reservoir architecture in complex foredeep-margin and wedge-top depocenters,Tertiary Molasse foreland basin system,Austria

We employ an integrated subsurface dataset, including >400 m of drill cores and three-dimensional (3D) seismic-reflection data from >530 km² of the Tertiary Molasse foreland basin system in Austria, to characterize turbidite-system architecture across structurally complex foredeep-margin and wedge-top depocenters and to interpret the influence of tectonic deformation and submarine topography on hydrocarbon-reservoir quality and distribution. Turbidite-system architecture and depositional processes were correlated with associated topographic features in order to identify zones of preferential sediment gravity-flow convergence or divergence. Zones of flow convergence facilitate flow acceleration and accumulative flow behavior, whereas zones of flow divergence facilitate deceleration and depletion. Zones of preferential flow convergence include narrow (<2 km) and steep (<20°) foredeep-margin slope channels along thrust front-segmenting tear faults, and steep, unchannelized piggyback-basin and foredeep margins (local gradients as great as 40° across piggyback-basin margins). The foredeep-margin gradient is exaggerated principally by tectonic deformation that post-dates turbidite-system development, based on a paucity of growth strata. Piggyback-basin-margin gradients are exaggerated as a result of deformation synchronous with and following turbidite-system development, judging from the presence of growth strata. Slope-channel topography facilitated the development of relatively coarse-grained, amalgamated turbidite reservoirs, whereas unchannelized basin-margin topography facilitated deposition of fine-grained, chaotic non-reservoirs. Zones of preferential flow divergence are flat (<1°), unconfined (i.e., large in comparison to sediment gravity flows) piggyback-basin floors, which facilitated the development of relatively coarse-grained, non-amalgamated, upward fining turbidite reservoirs, stratigraphically partitioned by fine-grained mass transport-complex deposits. The results of this study elucidate the influence of foredeep-margin and wedge-top tectonic deformation and topography on turbidite-system and associated reservoir character and distribution across the Molasse foreland basin system in Austria, and can be applied to oil and gas exploration in analogous, structurally complex settings.     

Bacterial methane in the Atzbach-Schwanenstadt gas field (Upper Austrian Molasse Basin), Part I: Geology

Bacterial methane gas accumulations occur in Upper Oligocene to Early Miocene clastic deepwater sediments in the Austrian Molasse Basin. Methane gas is produced from the Upper Puchkirchen Fm. (Aquitanian) in the Atzbach-Schwanenstadt gas field which is one of the largest gas fields in this basin.