共查询到20条相似文献，搜索用时 31 毫秒
1.
Shales comprise more than 60% of sedimentary rocks and form natural seals above hydrocarbon reservoirs. Their sealing capacity is also used for storage of nuclear wastes. The world's most important conventional oil and gas reservoirs have their corresponding source rocks in shale. Furthermore, shale oil and shale gas are the most rapidly expanding trends in unconventional oil and gas. Shales are notorious for their strong elastic anisotropy, i.e., so‐called vertical transverse isotropy. This vertical transverse isotropy, characterised by a vertical axis of invariance, is of practical importance as it is required for correct surface seismic data interpretation, seismic to well tie, and amplitude versus offset analysis. A rather classical paradigm makes a clear link between compaction in shales and the alignment of the clay platelets (main constituent of shales). This would imply increasing anisotropy strength with increasing compaction. Our main purpose is to check this prediction on two large databases in shaly formations (more than 800 samples from depths of 0–6 km) by extracting the major trends in the relation between seismic anisotropy and compaction. The statistical analysis of the database shows that the simultaneous increase in density and velocity, a classical compaction signature, is quite weakly correlated with the anisotropy strength. As a consequence, compaction can be excluded as a major cause of seismic anisotropy, at least in shaly formations. Also, the alignment of the clay platelets can explain most of the anisotropy measurements of both databases. Finally, a method for estimating the orientation distribution function of the clay platelets from the measurement of the anisotropy parameters is suggested. 相似文献
2.
Shiv N. Dasgupta 《Geophysical Prospecting》2005,53(2):215-227
Ghawar, the largest oilfield in the world, produces oil from the Upper Jurassic Arab‐D carbonate reservoir. The high rigidity of the limestone–dolomite reservoir rock matrix and the small contrast between the elastic properties of the pore fluids, i.e. oil and water, are responsible for the weak 4D seismic effect due to oil production. A feasibility study was recently completed to quantify the 4D seismic response of reservoir saturation changes as brine replaced oil. The study consisted of analysing reservoir rock physics, petro‐acoustic data and seismic modelling. A seismic model of flow simulation using fluid substitution concluded that time‐lapse surface seismic or conventional 4D seismic is unlikely to detect the floodfront within the repeatability of surface seismic measurements. Thus, an alternative approach to 4D seismic for reservoir fluid monitoring is proposed. Permanent seismic sensors could be installed in a borehole and on the surface for passive monitoring of microseismic activity from reservoir pore‐pressure perturbations. Reservoir production and injection operations create these pressure or stress perturbations. Reservoir heterogeneities affecting the fluid flow could be mapped by recording the distribution of epicentre locations of these microseisms or small earthquakes. The permanent borehole sensors could also record repeated offset vertical seismic profiling surveys using a surface source at a fixed location to ensure repeatability. The repeated vertical seismic profiling could image the change in reservoir properties with production. 相似文献
3.
This paper describes the measurements of the acoustic and petrophysical properties of two suites of low‐shale sandstone samples from North Sea hydrocarbon reservoirs, under simulated reservoir conditions. The acoustic velocities and quality factors of the samples, saturated with different pore fluids (brine, dead oil and kerosene), were measured at a frequency of about 0.8 MHz and over a range of pressures from 5 MPa to 40 MPa. The compressional‐wave velocity is strongly correlated with the shear‐wave velocity in this suite of rocks. The ratio VP/VS varies significantly with change of both pore‐fluid type and differential pressure, confirming the usefulness of this parameter for seismic monitoring of producing reservoirs. The results of quality factor measurements were compared with predictions from Biot‐flow and squirt‐flow loss mechanisms. The results suggested that the dominating loss in these samples is due to squirt‐flow of fluid between the pores of various geometries. The contribution of the Biot‐flow loss mechanism to the total loss is negligible. The compressional‐wave quality factor was shown to be inversely correlated with rock permeability, suggesting the possibility of using attenuation as a permeability indicator tool in low‐shale, high‐porosity sandstone reservoirs. 相似文献
4.
Honoré Yenwongfai Nazmul Haque Mondol Isabelle Lecomte Jan Inge Faleide Johan Leutscher 《Geophysical Prospecting》2019,67(4):1020-1039
Seismic petro-facies characterization in low net-to-gross reservoirs with poor reservoir properties such as the Snadd Formation in the Goliat field requires a multidisciplinary approach. This is especially important when the elastic properties of the desired petro-facies significantly overlap. Pore fluid corrected endmember sand and shale depth trends have been used to generate stochastic forward models for different lithology and fluid combinations in order to assess the degree of separation of different petro-facies. Subsequently, a spectral decomposition and blending of selected frequency volumes reveal some seismic fluvial geomorphological features. We then jointly inverted for impedance and facies within a Bayesian framework using facies-dependent rock physics depth trends as input. The results from the inversion are then integrated into a supervised machine learning neural network for effective porosity discrimination. Probability density functions derived from stochastic forward modelling of endmember depth trends show a decreasing seismic fluid discrimination with depth. Spectral decomposition and blending of selected frequencies reveal a dominant NNE trend compared to the regional SE–NW pro-gradational trend, and a local E–W trend potentially related to fault activity at branches of the Troms-Finnmark Fault Complex. The facies-based inversion captures the main reservoir facies within the limits of the seismic bandwidth. Meanwhile the effective porosity predictions from the multilayer feed forward neural network are consistent with the inverted facies model, and can be used to qualitatively highlight the cleanest regions within the inverted facies model. A combination of facies-based inversion and neural network improves the seismic reservoir delineation of the Snadd Formation in the Goliat Field. 相似文献
5.
Sensitivity of time-lapse seismic to reservoir stress path 总被引：1，自引：1，他引：1
Colin M. Sayers 《Geophysical Prospecting》2006,54(3):369-380
The change in reservoir pore pressure due to the production of hydrocarbons leads to anisotropic changes in the stress field acting on the reservoir. Reservoir stress path is defined as the ratio of the change in effective horizontal stress to the change in effective vertical stress from the initial reservoir conditions, and strongly influences the depletion‐induced compaction behaviour of the reservoir. Seismic velocities in sandstones vary with stress due to the presence of stress‐sensitive regions within the rock, such as grain boundaries, microcracks, fractures, etc. Since the response of any microcracks and grain boundaries to a change in stress depends on their orientation relative to the principal stress axes, elastic‐wave velocities are sensitive to reservoir stress path. The vertical P‐ and S‐wave velocities, the small‐offset P‐ and SV‐wave normal‐moveout (NMO) velocities, and the P‐wave amplitude‐versus‐offset (AVO) are sensitive to different combinations of vertical and horizontal stress. The relationships between these quantities and the change in stress can be calibrated using a repeat seismic, sonic log, checkshot or vertical seismic profile (VSP) at the location of a well at which the change in reservoir pressure has been measured. Alternatively, the variation of velocity with azimuth and distance from the borehole, obtained by dipole radial profiling, can be used. Having calibrated these relationships, the theory allows the reservoir stress path to be monitored using time‐lapse seismic by combining changes in the vertical P‐wave impedance, changes in the P‐wave NMO and AVO behaviour, and changes in the S‐wave impedance. 相似文献
6.
Depositional ages and characteristics of Middle–Upper Jurassic and Lower Cretaceous lacustrine deposits in southeastern Mongolia 
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下载免费PDF全文 Hitoshi Hasegawa Hisao Ando Noriko Hasebe Niiden Ichinnorov Tohru Ohta Takashi Hasegawa Masanobu Yamamoto Gang Li Bat‐Orshikh Erdenetsogt Ulrich Heimhofer Takayuki Murata Hironori Shinya G. Enerel G. Oyunjargal O. Munkhtsetseg Noriyuki Suzuki Tomohisa Irino Koshi Yamamoto 《Island Arc》2018,27(3)
Lower Cretaceous lacustrine oil shales are widely distributed in southeastern Mongolia. Due to the high organic carbon content of oil shale, many geochemical studies and petroleum exploration have been conducted. Although most of the oil shales are considered to be Early Cretaceous in age, a recent study reveals that some were deposited in the Middle Jurassic. The present study aims at establishing depositional ages and characteristics of the Jurassic and Cretaceous lacustrine deposits in Mongolia. The Lower Cretaceous Shinekhudag Formation is about 250 m thick and composed of alternating beds of shale and dolomite. The Middle Jurassic Eedemt Formation is about 150 m thick and composed of alternating beds of shale, dolomitic marl, and siltstone. The alternations of shale and dolomite in both formations were formed by lake level changes, reflecting precipitation changes. Shales were deposited in the center of a deep lake during highstand, while dolomites were formed by primary precipitation during lowstand. Based on the radiometric age dating, the Shinekhudag Formation was deposited between 123.8 ±2.0 Ma and 118.5 ±0.9 Ma of the early Aptian. The Eedemt Formation was deposited at around 165–158 Ma of Callovian–Oxfordian. The calculated sedimentation rate of the Shinekhudag Formation is between 4.7 ±2.6 cm/ky and 10.0 ±7.6 cm/ky. Shales in the Shinekhudag Formation show micrometer‐scale lamination, consisting of algal organic matter and detrital clay mineral couplets. Given the average thickness of micro‐laminae and calculated sedimentation rate, the micro‐lamination is most likely of varve origin. Both Middle–Upper Jurassic and Lower Cretaceous lacustrine oil shales were deposited in intracontinental basins in the paleo‐Asian continent. Tectonic processes and basin evolution basically controlled the deposition of these oil shales. In addition, enhanced precipitation under humid climate during the early Aptian and the Callovian–Oxfordian was another key factor inducing the widespread oil shale deposition in Mongolia. 相似文献
7.
Sub‐sample time shift and horizontal displacement measurements using phase‐correlation method in time‐lapse seismic 下载免费PDF全文
下载免费PDF全文 Hydrocarbon production and fluid injection affect the level of subsurface stress and physical properties of the subsurface, and can cause reservoir‐related issues, such as compaction and subsidence. Monitoring of oil and gas reservoirs is therefore crucial. Time‐lapse seismic is used to monitor reservoirs and provide evidence of saturation and pressure changes within the reservoir. However, relative to background velocities and reflector depths, the time‐lapse changes in velocity and geomechanical properties are typically small between consecutive surveys. These changes can be measured by using apparent displacement between migrated images obtained from recorded data of multiple time‐lapse surveys. Apparent displacement measurements by using the classical cross‐correlation method are poorly resolved. Here, we propose the use of a phase‐correlation method, which has been developed in satellite imaging for sub‐pixel registration of the images, to overcome the limitations of cross‐correlation. Phase correlation provides both vertical and horizontal displacements with a much better resolution. After testing the method on synthetic data, we apply it to a real dataset from the Norne oil field and show that the phase‐correlation method can indeed provide better resolution. 相似文献
8.
Rui-Zhao Yang Zheng-Guang Zhao Wei-Jun Peng Yu-Bo Gu Zhan-Gang Wang Xi-Qin Zhuang 《应用地球物理》2013,10(2):157-169
The development of unconventional resources, such as shale gas and tight sand gas, requires the integration of multi-disciplinary knowledge to resolve many engineering problems in order to achieve economic production levels. The reservoir heterogeneity revealed by different data sets, such as 3D seismic and microseismic data, can more fully reflect the reservoir properties and is helpful to optimize the drilling and completion programs. First, we predict the local stress direction and open or close status of the natural fractures in tight sand reservoirs based on seismic curvature, an attribute that reveals reservoir heterogeneity and geomechanical properties. Meanwhile, the reservoir fracture network is predicted using an ant-tracking cube and the potential fracture barriers which can affect hydraulic fracture propagation are predicted by integrating the seismic curvature attribute and ant-tracking cube. Second, we use this information, derived from 3D seismic data, to assist in designing the fracture program and adjusting stimulation parameters. Finally, we interpret the reason why sand plugs will occur during the stimulation process by the integration of 3D seismic interpretation and microseismic imaging results, which further explain the hydraulic fracture propagation controlling factors and open or closed state of natural fractures in tight sand reservoirs. 相似文献
9.
Recognition of thin interbedded reservoirs in the middle-shallow strata in the Songliao Basin is a great difficulty. In order to resolve this problem, we present a technique for predicting the distribution of thin reservoirs using a broad frequency band and ultra high resolution seismic. Based on forward modeling, we recognized that a thin bed seismic reflection is characterized by changing amplitude with changing frequency （amplitude versus frequency, AVF）. We calculate the thickness of thin reservoirs from their AVF characteristics and predict the distribution of thin bed reservoir using broad frequency band and ultra high resolution seismic. The technique has been applied in the 3D seismic area of Zhaoyuan in the northern part of the Songliao Basin. The seismic resolution is increased by two or three times over that of conventional seismic and many thin reservoirs have been identified. The technique has extensive application to the exploration and development of oil and gas, such as optimizing the location of exploration wells, the design of wells （especially horizontal wells）, choice of production test layers, analyzing reservoir continuity in development wells, and so on. 相似文献
10.
Differential compaction has long been used by seismic interpreters to infer subsurface geology using knowledge of the relative compaction of different types of sediments. We outline a method to infer the gross fraction of shale in an interval between two seismic horizons using sandstone and shale compaction laws. A key component of the method involves reconstruction of a smooth depositional horizon by interpolating decompacted thicknesses from well control. We derive analytic formulae for decompaction calculations using known porosity–stress relations and do not employ discrete layer iterative methods; these formulae were found to depend not only upon the gross fraction of shale but also on the clay content of the shales and the thickness of the interval. The relative merits of several interpolation options were explored, and found to depend upon the structural setting. The method was successfully applied to an oil sands project in Alberta, Canada. 相似文献
11.
松辽盆地北部扶杨油层河道砂体的地震识别方法研究 总被引：1，自引：0，他引：1
应用地震技术预测和识别扶杨油层河道砂体是当前松辽盆地北部的油气勘探中最为急需的技术之一。本文以GTZ地区为例,探讨了扶杨油层河道砂体的成因特点,指出地震的低分辨率,河道砂体的薄互层、横向变化快、储层非均质性强等地质特点,是当前应用地震技术识别扶杨油层河道砂体的困难所在。文中介绍了当前技术条件下河道识别的两种方法:利用频谱成像技术和叠前方位各向异性技术进行河道识别的方法和思路。以扶余油层为目的层说明了应用上述两种方法识别河道砂体的良好效果,并和已知井资料进行对比,符合率可达80%。 相似文献
12.
An approach is developed to estimate pore‐pressure changes in a compacting chalk reservoir directly from time‐lapse seismic attributes. It is applied to data from the south‐east flank of the Valhall field. The time‐lapse seismic signal of the reservoir in this area is complex, despite the fact that saturation changes do not have an influence. This complexity reflects a combination of pressure depletion, compaction and stress re‐distribution throughout the reservoir and into the surrounding rocks. A simple relation is found to link the time‐lapse amplitude and time‐shift attributes to variations in the key controlling parameter of initial porosity. This relation is sufficient for an accurate estimation of pore‐pressure change in the inter‐well space. Although the time‐lapse seismic estimates mostly agree with reservoir simulation, unexplained mismatches are apparent at a small number of locations with lower porosities (less than 38%). The areas of difference between the observations and predictions suggest possibilities for simulation model updating or a better understanding of the physics of the reservoir. 相似文献
13.
龙马溪组页岩是目前国内页岩气勘探的主要层位之一.由于岩石物理实验结果具有区域性,龙马溪组页岩的岩石特征与其地震弹性性质的响应规律需要开展相关的实验和理论研究工作予以明确.本研究基于系统的微观结构观察(扫描电镜和CT成像技术)和岩石物理实验来分析龙马溪组页岩样品地震弹性性质的变化规律,并依据微观结构特征建立相应的地震岩石物理表征模型.研究结果表明,石英含量对龙马溪组页岩的孔隙度以及有机碳(TOC)含量具有一定的控制作用,TOC和黄铁矿主要赋存于孔隙中;岩石骨架组成亦受控于石英或粘土含量,在石英含量大于40%(对应粘土含量小于30%)时,以石英、粘土共同作为岩石骨架,而粘土含量大于30%时,则以粘土作为岩石的骨架.因此,岩石骨架组成矿物、TOC含量、孔隙度共同制约龙马溪组页岩的地震弹性性质,富有机质储层岩石通常表现出低泊松比、低阻抗和低杨氏模量的特征,但由于支撑矿物的转换,某些富有机质页岩亦可表现为高阻抗特征.粘土矿物的定向排列仍然是造成页岩样品表现出各向异性的主要原因,各向异性参数与粘土含量具有指数关系.基于龙马溪组页岩的岩性特征及微观结构特征,可以利用自洽模型(SCA)、微分等效模量模型(DEM)和Backus平均模型的有效组合较为准确地建立龙马溪组页岩的地震岩石物理模型,实验结果和测井数据验证了模型的准确性.研究结果可为龙马溪组页岩气储层的测井解释和地震"甜点"预测提供依据. 相似文献
14.
Influence of subsurface injection on time‐lapse seismic: laboratory studies at seismic and ultrasonic frequencies 下载免费PDF全文
下载免费PDF全文 Seismic monitoring of reservoir and overburden performance during subsurface CO2 storage plays a key role in ensuring efficiency and safety. Proper interpretation of monitoring data requires knowledge about the rock physical phenomena occurring in the subsurface formations. This work focuses on rock stiffness and elastic velocity changes of a shale overburden formation caused by both reservoir inflation induced stress changes and leakage of CO2 into the overburden. In laboratory experiments, Pierre shale I core plugs were loaded along the stress path representative for the in situ stress changes experienced by caprock during reservoir inflation. Tests were carried out in a triaxial compaction cell combining three measurement techniques and permitting for determination of (i) ultrasonic velocities, (ii) quasistatic rock deformations, and (iii) dynamic elastic stiffness at seismic frequencies within a single test, which allowed to quantify effects of seismic dispersion. In addition, fluid substitution effects connected with possible CO2 leakage into the caprock formation were modelled by the modified anisotropic Gassmann model. Results of this work indicate that (i) stress sensitivity of Pierre shale I is frequency dependent; (ii) reservoir inflation leads to the increase of the overburden Young's modulus and Poisson's ratio; (iii) in situ stress changes mostly affect the P‐wave velocities; (iv) small leakage of the CO2 into the overburden may lead to the velocity changes, which are comparable with one associated with geomechanical influence; (v) non‐elastic effects increase stress sensitivity of an acoustic waves; (iv) and both geomechanical and fluid substitution effects would create significant time shifts, which should be detectable by time‐lapse seismic. 相似文献
15.
Stephen A. Hall † Colin MacBeth Jan Stammeijer Mark Omerod 《Geophysical Prospecting》2006,54(1):63-73
In the Southern Gas Basin (SGB) of the North Sea there are many mature gas fields where time‐lapse monitoring could be very beneficial in extending production life. However, the conditions are not immediately attractive for time‐lapse seismic assessment. This is primarily because the main production effect to be assessed is a pore pressure reduction and frame stiffening because of gas production in tight sandstone reservoirs that also have no real seismic direct hydrocarbon indicators. Modelling, based on laboratory measurements, has shown that such an effect would be small and difficult to detect in seismic data. This paper makes two main contributions. Firstly, this is, to our knowledge, the first time‐lapse study in the SGB and involves a real‐data assessment of the viability for detecting production in such an environment. Secondly, the feasibility of using markedly different legacies of data in such a study is addressed, including an assessment of the factors influencing the crossmatching. From the latter, it is found that significant, spatially varying time shifts need to be, and are successfully, resolved through 3‐D warping. After the warping, the primary factors limiting the crossmatching appear to be residual local phase variations, possibly induced by the differing migration strategies, structure, reverberations and different coherencies of the volumes, caused by differences in acquisition‐structure azimuth and acquisition fold. Despite these differences, a time‐lapse amplitude signature is observed that is attributable to production. The character of the 4‐D amplitude anomalies may also indicate variations in stress sensitivity, e.g. because of zones of fracturing. Additionally, warping‐derived time attributes have been highlighted as a potential additional avenue for detection of pressure depletion in such reservoirs. Although the effects are subtle, they may indicate changes in stress/pressure in and around the reservoir because of production. However, to fully resolve the subtle time‐lapse effects in such a reservoir, the data differences need to be better addressed, which may be possible by full re‐processing and pre‐stack analysis, but more likely dedicated 4‐D acquisition would be required. 相似文献
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17.
The Fuyang oil-layer in North Songliao Basin is characterized by thin interbedded sands and shales, strong lateral variation, strong reservoir heterogeniety, and so on. The thickness of individual sand layers is generally 3 - 5 m. Identifying the channel sand-bodies of the Fuyang oil layer using seismic techniques is very difficult due to the low seismic resolution. Taking the GTZ area as an example, we discuss the genetic characteristics of the channel sand-bodies and point out the real difficulty in using seismic techniques to predict the channel sand-bodies. Two methods for the identification of channels are presented： frequency spectrum imaging and pre-stack azimuthal anisotropy. Identifying the channel sand-bodies in Fuyu oil-layer using the two seismic methods results in a success rate up to 80% compared with well data. 相似文献
18.
针对松辽盆地北部中浅层薄层识别难的问题,我们研究了用宽频带高分辨率地震预测薄层储层分布的方法。通过正演数据分析,发现薄层地震反射具有振幅随频率变化而变化的特征-简称为AVF特征,并提出利用储层反射AVF特征计算薄层储层的厚度,用薄层厚度对应的宽频带高分辨率地震方法预测薄层储层分布。该方法在松辽盆地肇源3D地区的实际应用中,大大提高了地震分辨率,查明了一大批薄层储层。该方法在油气勘探与开发中也有着广泛的应用领域,例如,井位设计,尤其是水平井设计,试油层位选择,开发井油层连通性分析等。 相似文献
19.
The possibility of using 4D seismic data for monitoring pressure depletion in the low‐porosity, tight gas‐bearing Rotliegende sandstones of the UK Southern Gas Basin is investigated. The focus here is on whether fractures in the upper part of the reservoir, known to enhance productivity, can also enhance the time‐lapse seismic response. The study uses laboratory data to evaluate core‐plug stress sensitivity, published data for the stress behaviour of the fractures, followed by petro‐elastic and 4D seismic modelling of both the fractured and unfractured formation. The magnitude of the resultant 4D signatures suggests that production‐induced changes in the unfractured sands are unlikely to be observed except perhaps with highly repeatable time‐lapse surveys. On the other hand, the presence of fractures could render production effects visible in dedicated 4D acquisition or prestack parallel processed data. If present however, the signature will be sporadic, as fractures in the area are known to exist in clusters. The 4D signature may be enhanced further by certain classes of vertical geological variability and also areas of high reservoir pressure. The strongest evidence of depletion is expected to be time‐shifts seen at the base of the Rotliegende reservoir. 相似文献
20.
Mechanical compaction in heterogeneous clastic formations from plastic–poroelastic deformation principles: theory and applications 下载免费PDF全文
下载免费PDF全文 Ran Bachrach 《Geophysical Prospecting》2017,65(3):724-735
Mechanical compaction or loss of porosity due to increase in effective stress is a fundamental geological process that governs many of the rock elastic and transport parameters, all of great importance in exploring and developing subsurface reservoirs. The ability to model the compaction process enables us to improve our understanding of the seismic signature of the basin and better relate the geology of deposition to current porosity, velocity, pore pressure, and other mechanical parameters that depend on the state of compaction of the sediment. In this paper, a set of mathematical equations that can be used to model the plastic deformation associated with primary and secondary loading curves is presented. Compaction laws are posed in terms of natural strain increment formulation often used in plasticity theory to model large deformation. Laboratory and field estimates of constitutive plastic deformation relations for sand–shale mixtures are used in a numerical model that generates estimates of porosity under various pore pressures, shale content, and loading scenarios. These estimates can be used in a variety of settings to predict various basin and reservoir properties associated with different loading conditions and/or sedimentation processes. 相似文献