Reservoir geophysics
SEG 0016-8033 geophysics/volume66/Issue 1
by Wayne D. Pennington
INTRODUCTION
The concept of petroleum reservoir geophysics is relativelynew. In the past, the role of geophysics was largely confined toexploration and, to a lesser degree, the development of discoveries.As cost-efficiency has taken over as a driving force in the economics of the oil and gas industry and as major assets near abandonment, geophysics has increasingly been recognized as a tool for improving the bottom line closer to the wellhead.The reliability of geophysical surveys, particularly seismic, has greatly reduced the risk associated with drilling wells in existing fields, and the ability to add geophysical constraints to statistical models has provided a mechanism for directly delivering geophysical results to the reservoir engineer.Several good examples of reservoir geophysics studies can be found in Sheriff (1992) and in the Development and Production special sections of THE LEADING EDGE (e.g., March 1999 and March 2000 issues).
DIFFERENCES BETWEEN EXPLORATION AND RESERVOIR GEOPHYSICS
There are several specific differences between exploration geophysics and reservoir geophysics, as the term is usually intended. These include the assumption that well control is available within the area of the geophysical survey, that a welldesigned geophysical survey can be conducted at a level of detail that will be useful, and that some understanding of the rock physics is available for interpretation.
Well control
In exploration, we often require extrapolating well data from far outside the area of interest, crossing faults, sequence boundaries,and occasionally worse discontinuities.The availability of“analogs” is an important component of exploration, and the level of confidence on the resulting interpretation is necessarily limited. In reservoir geophysics, it is generally assumed that a reservoir is already under production (or at least at a late stage of development) and that wells are available for analysis. These wells provide a variety of information. From the petrophysicist,we receive edited and interpreted well log data, describing the lithology (including the mineralogy, porosity, and
Michigan Technological University, Department of Geological Engineering and Sciences, Houghton, Michigan 49931. E-mail:
wayne@mtu.edu.c°2001 Society of Exploration Geophysicists. All rights reserved.perhaps even the morphology of the pore spaces), the fluid content (sometimes related to logged conditions, sometimes to virgin reservoir conditions), and detailed depth constraints on geologic horizons. From the production and reservoir engineers,we receive an estimate of the proximity to boundaries,aquifers, or other features of interest. The reservoir engineer
can also provide a good estimate of the total volume of the reservoir, and the asset team relates this to the geologic interpretation,determining the need for surveys at increased resolution.From a combination of sources, we obtain additional information about the in-situ conditions of the reservoir, including the formation temperature, pressure, and the properties of the oil, gas, and brine. The geophysicist should be familiar with the usefulness and limitations of petrophysical and reservoirengineering studies, and should be able to ask intelligent questions of the experts in those fields. But the geophysicist need not become an expert in those areas in order to work with the specialists and to design a new experiment to solve reservoir problems. A good introduction to reservoir development and engineering practices, accessible to geophysicists as well as nontechnical personnel, can be found in Van Dyke (1997); a classical text in reservoir engineering is that by Craft and Hawkins(1991, revised). Other petroleum engineering texts often appreciated by geophysicists include ones by Dake (1978), Jahn et al. (1998) and Coss´e (1993). A detailed reference work for petroleum engineering is Bradley (1987). Good references for well logging and formation evaluation include Dewan (1983)and Asquith (1982).
Rock physics control
One of the major questions a geophysicist is asked, or should ask independently, is this: Will the geophysical technique being proposed be able to differentiate between the competing reservoir models sufficiently well to be worth the effort and cost? The answer lies not just in the geophysical model, but in the rock physics—or the “seismic petrophysics”—of the reservoir rock and neighboring formations (Pennington, 1997). The presence of wells and the possibility that some core samples are available greatly improve the capability of the reservoir geophysicist to address this question. Logs, particularly sonic logs
Geophysics in the new millennium of compressional and shear velocities combined with image logs providing fracture information, can be used (carefully) to provide basic seismic properties, which in turn are modeled for varying lithologic character, fluid content, and in-situ conditions (such as pore pressure). The core samples can be used to provide the basis for a theoretical framework, or measurements on them can be used (again, carefully) to provide the same basic seismic properties. The geophysicist must always be on the alert for accidental misuse of the input data, and concerned with scaling properties, particularly the possibility that physical effects observed at one scale (such as the squirt flow mechanism for saturated rocks at high frequencies) not be mistakenly applied at other scales. Sometimes, a little knowledge can be a dangerous weapon; an incomplete
evaluation of the seismic petrophysical aspects of the formation can lead either to incorrect results or interpretations (see one pitfall demonstrated and accounted for in Dvorkin et al.,1999).A number of the fundamental papers dealing with rock physics and seismic response can be found in the compilations by Nur andWang (1989) andWang and Nur (1992); a summary of rock physics formulas and their use is presented by Mavko et al. (1998).
Survey design
Once a field has been discovered, developed, and under production for some time, quite a bit of information is available to the geophysicist to design a geophysical survey in such a manner
as to maximize the likelihood that the data collected will optimize the interpretation. That is, if the goal of the survey is to define the structural limits of the field, a 3-D seismic survey can be designed with that in mind. If, however, the goal of the survey is to define the extent of a gas zone, the geophysicist may be able to use log data, seismic petrophysical modeling,and old (legacy) seismic data to determine whether a certain offset range is required to differentiate between the water and gas zones. If highly accurate well ties or wavelet-phase control are needed, an appropriately placed vertical seismic profile (VSP) may be designed. Or, if an acquisition footprint had been observed in a previously acquired seismic data set and that footprint obscured the attributes used to define the reservoir target, the geophysicist can design the new survey to eliminate the troublesome artifacts. In short, the fact that the target is well known gives the reservoir geophysicist a distinct advantage
over the exploration geophysicist by allowing the survey to be designed in a more enlightened manner than a typical exploration survey ever can be. It is often easier to justify the expense of a properly conducted seismic survey for reservoir characterization purposes because the financial impact of the survey can be calculated with greater confidence and the financial returns realized more quickly than is typically the case for exploration seismic surveys. Procedures for planning 3-D seismic surveys have been undergoing rapid change over the past few years, but good introductions to the subject are available in books by Evans (1997), Stone (1994), and Liner (1999). Some recent studies demonstrating the incorporation of seismic data, well-log control, and VSP results and production information where available, and for which much of the data are publicly available, are found in Hardage et al. (1994, 1996, 1999).
3-D SEISMIC
Most reservoir geophysics is based on reflection seismic data, although a wide variety of other techniques are employed regularly on specific projects. Almost all seismic data collected for reservoir studies is high-fold 3-D vertical-receiver data; however, the use of converted-wave data with multiple component geophones on land and on the sea floor, and multicomponent source (on land) is increasing. In particular, in order to image below gas clouds that obscure P-wave imaging of reservoirs,converted waves are now being used, and the technology to obtain multiple-component data from the ocean bottom is continually improving. The importance of fractures in many reservoir development schemes has led to a number of experimental programs for multicomponent sources and receivers in an effort to identify shear-wave splitting (and other features) associated with high fracture density. Some of these techniques will find continually increasing application in the future, but at the present, most surface seismic studies designed to characterize existing reservoirs are high-quality 3-D vertical-componentreceiver surveys. Many good case histories of the use of 3-D seismic data for reservoir development purposes can be found in the collection byWeimer and Davis (1996). Case histories using 3-D seismic for unconventional reservoir characterization purposes include MacBeth and Li (1999) and Lynn et al. (1999). A current example for the use of converted waves in ocean-bottom surveys over a poor-data area (the result of a gas chimney) is provided by Thomsen et al. (1997).
Attributes
In most exploration and reservoir seismic surveys, the main objectives are (in order) to correctly image the structure in time and depth, and to correctly characterize the amplitudes of the reflections in both the stacked and prestack domains. From these data, a host of additional features can be derived, and used in interpretation. Collectively, these features are referred to as seismic attributes (Taner et al. 1979). The simplest attribute, and the one most widely used, is seismic amplitude,and it is usually reported as the maximum (positive or negative) amplitude value at each common midpoint (CMP) along a horizon picked from a 3-D volume. It is fortunate that, in many cases, the amplitude of a reflection corresponds directly to the porosity of the underlying formation, or perhaps to the density (and compressibility) of the fluid occupying pore spaces in that formation. The assumption is that amplitude is proportional to RO, and the simple convolutional model is often appropriate for interpretation of the data in such cases. But it isn’t always this simple, and many mistakes of interpretation have occurred by making this assumption. For one thing, the convolutional model may not be appropriate for use in many instances, particularly if the offset dependence of a reflection
is important in its interpretation. Likewise, the interpretation of porosity or fluid properties as the cause of a true impedance change is often overly optimistic, especially in sands containing clays or in rocks with fractures. The use of seismic attributes extends well beyond simple amplitudes. Most of the “original” seismic attributes were based on the Hilbert transform and consisted of the instantaneous amplitude (or amplitude of the wave envelope), the Geophysics in the new millennium
instantaneous phase (most useful for accurate time picking),and the instantaneous frequency (probably most often associated with thin-bed reverberations, but often interpreted, perhaps incorrectly, as resulting from attenuation due to gas bubbles). Variations on these attributes evolved, and other classes of attributes came into use. For example, coherence is the attribute of waveform similarity among neighboring traces and is often used to identify fractures (Marfurt et al., 1998). Dip and
azimuth describe the direction of trace offset for maximum similarity and can yield finely detailed images of bed surfaces. There are now over two hundred attributes in use in some geophysical processing or interpretation software packages (Chen and Sidney, 1997); many of these attributes result from slightly differing approaches to determining a specific property, such as frequency or amplitude. Care must be taken in applying traditional attribute analysis in thin-bed areas, where the interference from the thin beds themselves can obscure the traditional attribute interpretations (see the section in this paper on “ultra-thin beds” for more details).
Well calibration
With so many attributes available to choose from, it is vital hat the reservoir geophysicist make careful use of calibration at wellbores, using log data, core data, and borehole seismic information available in order to test the correlation of attributes with rock properties. Again, the reservoir geophysicist enjoys significant advantages over the exploration geophysicist, who cannot always tie the seismic data and its character (attributes) to properties of the formation as evidenced from the well data. It is important that the reservoir geophysicist make use of all the information and expertise available within the asset team to provide the tightest possible calibration; otherwise, the advantage
of performing reservoir geophysical studies is lost. It is simple to correlate the attribute of interest with the well-log (or log-derived) data of interest; a strong correlation between, say, seismic amplitude and porosity is often enough to convince many workers that the correlation is meaningful and that seismic amplitude can be used as a proxy for porosity in reservoir characterization. There are many potential pitfalls in this approach, as one may imagine (Kalkomey, 1997; Hirsche et al.,
1998). Statistical tests should be performed on the well correlations, and geologic inference should be brought in to test the reasonableness of the results and, most importantly, the physical basis for the behavior of an observed attribute.
Geostatistics
In reservoir characterization, the asset team usually has a number of wells at its disposal from which to draw inferences about the reservoir in general. With the availability of these wells comes a dilemma: How do you make use of the spatial distribution of the data at hand? Simple averaging between wells can easily be seen to lead to misleading results, and a technique called kriging was developed for use when features can be observed to correlate over certain distances. The technique
has been refined to include the use of data that provides additional “soft” evidence between the “hard” data locations at wells, and seismic data often provides that soft evidence. Essentially, if a statistical (and physically meaningful) correlation is found to exist between formation parameters observed at wells and some seismic attribute observed throughout the study area, geostatistical techniques are available that allow the hard data at the wells to be honored and to be interpolated
(generally using kriging techniques) between the wells, while honoring the seismic interpretation to a greater or lesser degree. In the absence of seismic data, various “realizations” of the possible interwell regions can be generated using advanced geostatistical techniques, each realization being just as likely to occur as any other. But in the presence of seismic data with reliable predictive capabilities, the range of such models can be greatly reduced. The problem of reservoir characterization then can become less stochastic and more deterministic, although the correlations are never perfect, and a range of likely models should always be considered.A number of good references exist from which one can learn geostatistical approaches. These include Dubrule (1998);Jensen et al. (1997), and Isaaks and Srivastava (1989). A good collection of case histories is presented by Yarus and Chambers(1995).
Ultra-thin beds
In recent years, a couple of techniques in particular have been developed that appear to help the interpreter identify properties of extremely thin beds, well below what has traditionally
been considered the quarter-wavelength resolution of seismic data. These techniques make use of the various frequency components within a band-limited seismic wavelet; one operates in the frequency domain, and the other in the time domain. The frequency-domain approach (see, for example, Partyka et al., 1999) called spectral decomposition, looks for notches in the frequency band representing a sort of ghost signal from the interference of the reflections from the top and bottom of the thin bed. The frequency at which that ghost, or spectral notch, occurs corresponds to twice the (two-way) time thickness of the bed. Because the seismic wavelet contains frequencies well above the predominant frequency, spectral notches can be indicative of extremely thin beds.The thinning out of a channel or shoreline, for example, can be observed by mapping the locations of successively higher-frequency notches in the spectrum.The time-domain approach involves matching wavelet character, often using a neural-network technique (Poupon et al.,1999); the wavelet along a given horizon can be classified intoseveral different wavelets, perhaps differing from each other only in subtle ways. The resulting map of classified wavelets can often resemble a map of the geologic feature being sought. The classification tends to compare relative amplitudes (side lobes versus main lobes, for example), “shoulders” on a main peak or trough, or slight changes in period, for example, and therefore often responds to interference from features below wavelet resolution. Both of these techniques run the risk of leading to incorrect interpretations if seismic petrophysical modeling is not performed to direct the analysis and interpretation or to confirm the results. It is becoming increasingly easy for a reservoir geophysicist to make use of advanced computer programs asblack boxes that provide a pretty picture and thereby be lulled into a false sense of security in the interpretation. Fortunately, most software packages currently available include the modeling capabilities required to test the results, but the tests are only as complete as the reservoir geophysicist is able to make them.
Focused approaches
Because the good reservoir geophysicist has analyzed the target of the study, has calibrated legacy seismic data to wells,and has investigated the seismic petrophysical responses of the various scenarios anticipated in the reservoir, there is an opportunity to collect that data, and only that data, which will be required to observe the features of interest. For example, one could collect, say, only far-offset seismic data if one were convinced that the far offsets contained all the information that
was essential to the study (Houston and Kinsland, 1998). It is not clear that such highly focused approaches are being used,however, probably because the cost savings do not warrant the added risk of missing an important piece of data. There may also be a natural aversion to collecting, purposefully, data that are not as “good” or “complete” as conventionally acquired seismic data, even though this approach would be a good marriage of the scientific method (collect data that is designed to support or disprove a hypothesis) and engineering pragmatism (get the job done, and produce hydrocarbons in a timely and efficient manner).
BOREHOLE GEOPHYSICS
The reservoir geophysicist not only has the advantage of using well data for correlation, the advantage extends to using those wells for the collection of novel geophysical data, from below the noisy surface or weathered zone, and very close to the target itself. New techniques for acquisition of seismic data from within wellbores are available, and may become important tools in the arsenal of the reservoir geophysicist in the near future. The seismic sources and/or receivers can be placed in
one well or in neighboring wells or on the surface, and the object of the analysis can be either the velocity field or the detailed reflection image near the wells. In order to qualify as borehole geophysics, either the source or the receiver, at least, must be in a wellbore; beyond that, almost as many geometrical arrangements as can be imagined have been tested or seriously proposed.
VSPs, checkshots, sonic logging, and through-casing sonic logging
The more conventional borehole geophysical techniques include VSPs, checkshot surveys, traditional sonic logging, and sonic logging through casing. All of these techniques were developed
primarily to assist in the tie between surface seismic data and well observations, but they have been extended beyond that in many cases. VSPs provide the best data for detailed event identification and wavelet determination (including phase); but they can also be used to image the near-wellbore environment, and the image can be improved if a number of offsets are used for the source location. Modern sonic logging tools can provide a good measure of compressional and shear
velocities, values required for the calibrated study of the effect of fluid substitution on seismic data; of course, the interpreter must be careful to know if the data represent invaded or uninvaded conditions, and make appropriate corrections if necessary. And modern sonic logging tools can often provide reliable values for velocities through casing; often, the mostreliable figures for soft shales can only be found behind casing due to the inability to log open-hole the depths in which shales
are flowing or collapsing.Crosswell, RVSP, and single-well imaging Recent extensions of borehole geophysical techniques involve placing a powerful seismic source in one well; the receivers
may be in another well (crosswell seismic), on the surface reverseVSP(RVSP)], or in the same well at some distance from the source (single-well imaging). Images have been created from data collected in experiments using such tool placement,and the time required for acquisition, the time required for data processing, and the cost of the entire operation haveall dropped to a point where the techniques may be considered commercially, not just experimentally. A few years ago, the only crosswell seismic technique in use was tomography which, while providing a valid representation of the velocity of the interwell region, did not provide a detailed image. Currently, tomographic techniques are often used to provide the velocity information for the production of a highly detailed reflection
image between (and beneath) the two wells in crosswell reflection programs (Lazaratos et al., 1995). Sources powerful enough to provide useful RVSP data have only recently become available, but a few early studies indicate that the potential for such technology is tremendous for imaging detailed structure in the vicinity of a well (Paulsson et al., 1997). Single-well imaging (Hornby et al., 1992), although not yet widespread, may provide a useful tool for detailed close-up structural studies, such as salt proximity studies designed to assist in the planning of a development sidetrack from an exploration well, particularly in the deepwater environment.
PASSIVE SEISMIC MONITORING
In recent years, the mechanical response of reservoir host rocks has been studied in some detail, prompted in part by the dramatic subsidence observed at the Ekofisk platform in the North Sea (Teufel and Rhett, 1992), although studies relating earthquakes to oil and gas production (Kovach, 1974; Pennington et al., 1986; Segall, 1989; McGarr, 1991) and injection practices (Raleigh et al., 1976; Davis and Pennington,1989) had previously been published in the scientific and earthquake
literature. Earthquake monitoring (called passive monitoring because the geophysicist does not activate a seismic source) has become more precise and accurate, even at low levels of seismicity, largely due to the placement of geophones downhole, away from surface noise and closer to the sources of seismic energy (Rutledge et al., 1994). As reservoir host rocks are stressed during the production (and/or injection) of fluids and the accompanying changes in fluid pressure, small (and
occasionally large) earthquakelike events occur, representing shear failure along planes of weakness; these can occur at pressures well below the reservoir-engineer’s “parting” pressure for
tensile failure. In some detailed studies, very small events seem to indicate patterns and locations of fracture systems responsible for oil migration (e.g., Phillips et al., 1998). Passive seismic
monitoring and surface tilt observations during hydraulic fracturing have led to improved reservoir development in a number of cases (for example, Castillo and Wright, 1995; Li et al., 1998). Both techniques of hydraulic-fracture monitoring have become nearly routine in the industry (that is, they are no longer experimental) and can be applied where appropriate.
SUMMARY
As geophysical techniques have matured over the years, they have provided an increasingly fine level of detail and are now used almost routinely for many purposes related to reservoir production. The most widely used technique, just as in exploration, is reflection seismic, where it is almost exclusively 3-D. Emerging techniques, having successfully proven their capabilities but in various stages of commercial availability, include crosswell, forward and reverse VSP, single-well imaging, and
passive seismic monitoring (gravity, electromagnetic, and other techniques are described elsewhere in this issue). The distinct advantage provided to reservoir geophysics over exploration geophysics lies in the quantity and quality of existing data on the reservoir target, enabling surveys to be focused on specific targets and allowing calibration (necessary in order to have confidence in the results, as well as to improve imaging) of the geophysical observations to the formation. As geophysical
techniques become more familiar to the engineer, and as engineering practices become more familiar to the geophysicist, continuing and increased use of reservoir geophysical techniques can be expected.
ACKNOWLEDGMENTS
This paper was prepared with support provided by a contract from theU.S. Department of Energy through the National Petroleum Technology Office in Tulsa, Oklahoma, DE-AC26- 98BC15135, “Calibration of Seismic Attributes for Reservoir Characterization,” under project manager Purna Halder.
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油藏地球物理
Wayne D Penningten
前言
油藏地球物理是一个相对较新的概念。过去，地球物理的角色大多局限于勘探，而在油藏的开发中应用程度则很低。随着效益成为油气工业经济发展的主要动力，随着一些主要油气田的枯竭，人们越来越认识到，地球物理是一种可以用来降低油气开发成本的手段。地球物理测量特别是地震测量的可靠性，极大地降低了现有油田与钻井有关的风险，把地球物理约束条件加到统计模型中去的能力，提供了一种直接向油藏工程师传送地球物理结果的机制。油藏地球物理研究的几个好的例子可参见Sheriff(1992)以及The Leading EDGE 杂志开发和生产专辑（如1999年第三期和2000年第三期专辑）。
勘探地球物理和油藏地球物理的差异
勘探地球物理和油藏地球物理之间存在着一些具体的差异，通常它们指意不同。这些差异包括假设在地球物理勘探区域内的井控数据是可以利用的，也就是说一次设计周到的地球物理测量在经过细调水平的处理后将会是有效的，而且对一些已经了解的岩石物理成分可以在解释时加以利用。
井控制
在勘探中，我们通常要向远离目标探区的交叉断层，层序界面和偶尔一些更差的不连续面外推一些井控数据，这些“类比”的有效性在勘探中是一种重要组成部分，而导致解释结果的可信度也必然的受限。在油藏地球物理中，一般都是假设一个油藏已生产不足（或者至少已经开发到最后阶段），并且可以对这些油井的资料进行分析。这些油井提供各种信息。从岩石物理学家那里，我们可以得到编辑好了的解释用的油井资料，岩性描述（包括矿物成分、孔隙度，也许还有孔隙间的形态学），流体含量（通常和测井条件有关，一般都是末开采的油藏）， 地质层位上详细的井深约束条件。从钻井和油藏工程师那里，我们可以得到边界，含水层，或者其他相关特点的近似估算值。油藏工程师也可以提供一个储集层总量的理想估算值，综合研究队通过这些数值和地质解释的联系来决定增加分辨率勘探的需求。通过组合震源，我们可以获得油藏现场条件下包括地层温度、压力及油、气、卤水的一些性质的额外信息。物理勘探队员应该了解石油物理和油藏工程研究中的一些好处和限制，能够向这些领域的专家提出一些见解深刻的问题。但是物探队员却没必要成为这些领域的专家，而是与这些专家在一起协同工作，设计新型实验解决油藏问题。
在Van Dyke (1997) 的书中油藏地球物理学家和非技术人员可以找到一些好的关于油藏发展和工程实践的介绍；在 Craft Hawkins (1991,修正版)的著作中可以找到一篇关于油藏地球物理的经典文章。其他一些经常被物探人员推崇的还有 Dahe (1978) 和 Jahn (1998) 等人和Coss’e (1993)写的关于石油工程的文章 .Bradley (1987)的石油工艺详细参考咨询工作指导,还有Dewan (1983) 和Asqueth (1982) 关于测井和地层评价的优秀参考文献。
岩石物理学控制
地球物理学家所要回答的主要问题之一或必须独立地回答的问题是：地球物理技术能否区分出什么样的油藏模型具有更好的效益和较低的成本？这个答案不仅取决于地球物理模型，而且还取决于岩石的物理成分——或者“地震岩石物理学”——的储油岩层和邻近地层（PENNINGTON,1997）。由于现存油井和钻井取芯的可行性很大的提高了油藏地球物理学家们发现问题所在的能力。测井，特别是声波测井的纵波速度和横波速度联合了测井曲线图形提供的裂缝信息，能够被用来（仔细地）提供基本的地震属性，依次形成不同的岩石性质、流体含量、现场条件下（例如孔隙压力）的模式。岩心样本能够提供基本的理论框架，或者对这些基于理论框架的测量值（再一次，仔细地）利用，同样也可以提供这些基本的地震属性。地球物理学家必须对这些输入数据保持警觉而不滥用，单独的剥离出相关的属性，特别可能是在某一尺度观察到（比如饱和状态下岩石的高频喷流机制）而不会错误的应用到其它尺度处。通常，了解不够可能是一种很危险的方法，对于由地震引起的石油物理方面的不完整的地层估测值，可能导致错误的结果或解释。
在NUR和WANG（1989）及WANG和NUR（1992）的编辑中能找到许多处理岩石物理成分和地震响应的基础论文；还有MAVKO（1998）等人编写的岩石物理学的相关公式的运用的著作。
测量设计
一旦发现油田，不管是已开发的还是生产不足的，油藏地球物理学家在对地球物理勘探设计时有大量的可使用信息，为了使得相似程度最大化，以便采集到的资料能使解释得到最优化。也就是说，如果勘探的目标只是限定在构造区域内，那么一个三维的地震勘探就已经在心里设计好了。但是，如果探测目标是界定一个含气区域的范围，那么物探人员也许能使用测井数据，由地震引起的岩石物理模型及（前期的）地震资料来确定区分在含气区与含水区所要求的偏移距范围。如果需要高精度井或子波——相位控制，就应该在适合的位置设计使用垂直地震剖面法了。或者，如果在前期的地震资料中发现了勘探痕迹，并且这些前人的勘探足迹混淆了利用这些属性界定的目标油藏，那么物探人员就应设计新型勘测方法来去除那些因人为因素而导致的麻烦了。简而言之，目标油藏探测区域给油藏工程师们的是不同于勘探地球物理学家对探测结果能做出的和大家平时所熟知的传统设计结果，而是更具启发性的设计方式。由于比传统的地震勘探对金融冲击的预算更可信，金融回报更快捷，所以常常更加方便的就能对油藏表征所做的地震勘探的开支预算做合理的调整了。
对于规化三维地震勘探程序在过去的几年中已经取得了长足的进步，然而对于这个课题在EVANAS(1997),STONE(1994) 和 LINER(1999)T等人的书中有很好的介绍。近代的一些研究证明了对地震资料、井控、垂直剖面法的结果和生产信息在HARDAGE (1994,1996,1999)等人的一些公开发表物中可以获得。
三维地震
大多数油藏地球物理学都是基于反演地震数据。虽然在一些特别项目中，其它工艺也被广泛的应用。几乎所有的为油藏研究采集的地震资料都是高度叠加的垂直接收的数据，然而，在陆地和海上对多组分检波器以及（陆上）多震源的转换波数据资料的利用也在逐渐增加。特别地，现在也正在利用转换波在油藏中含气区之下利用P波成像，这种从海底获得多分量数据的工区也在不断改进，在很多油藏的发展计划中，由于裂缝的重要性，也导致了很多试图识别横波分裂（和其它的特点）与高密度的裂缝发育有联系的多源多波试验的进行。这些工艺在将来会不断的被更多的应用，但现在，大多数的地震勘探都是针对现存的以陆上为特征设计的高质量垂直分量接收的地震勘探。
在WEIMER 和DAVIS（1996）以及LYNN.ET.AL(1999)等人的著作中，你也能发现利用三维地震资料对以非传统油藏为特色的案例。
THOMSEN ET AL（1997）也提到了一些现代利用转换波在海底对一些资料不好的区域进行勘探的最新实例。
属性
在多数的对油藏进行的储集层勘探和地震勘探中，最主要的目的就是对时间——深度域的构造正确成像及用振幅正确的对叠加和叠前域进行反演。在解释时能从这些资料中衍生出附加的特征。这些特点，共同地，指地震属性（TANER 等 1997）。最简单的也是应用最广的地震属性就是振幅，而且，通常所说的振幅是指从三维地震中的一个层位上的共中心点上采集到的最大振幅值（正值或负值）。幸运的是，很多情况下振幅值直接反映下伏地层的孔隙度或地层中占据孔隙空的流体的密度（可压缩性）。在这种情况下，地震资料在解释时，假设振幅值成比例并是简单的褶积模型。当然，也并不总是这么简单，在做这种假设时解释也会发生错误。因为，在有些案例中，褶积模型也许并不适用，特别是解释时反射中很重要的炮检距关系曲线。同样的 ，特别是砂岩中包含粘土或者岩石发育裂缝，那么，解释时孔隙度或液体性质也会因为阻抗变化的原因而被过度乐观认为。
地震属性的利用远远不止是振幅，大多数的“原始”的地震属性都基于HILBERT变换和瞬时振幅的组成（波形振幅包络），瞬时相位（对时间拾取最有用）和瞬时频率（最可能的利用就是联系薄层的交频混响，但解释时常常发生错误，并由于气泡而导致衰减）。由于这些属性演化的变分，其它属性分类也被使用。例如，相干性就是利用附近道中相似波形来识别裂缝（MARFURLET 等 1999）.倾角和方位角就是描述道间距最大相似性的方位并最终产生层面的详细图像。现在已经有超过200种属性在一些地球物理工艺设计和解释的微软程序包中使用（CHEN和SIDNEY 1997），很多属性都是起因于这些细微不同的方法而决定了一种具体的性质，比如频率或振幅。在薄层应用传统的属性分析时必须小心，因为来自薄层本身之间的这些干扰会模糊这些利用传统的属性作的解释（详细内容见本文“超薄层”章节）
井标定
有这么多的属性可以选择利用，那么，为了测试岩性的相关性，合理的进行井校准，对录井资料的使用及岩心资料和裸眼井的地震资料的利用对研究储层的油藏地球物理学家来说就尤为重要了，另外，油藏地球物理学家相对勘探地球物理学家而言，享有更大的优势，至少，勘探地球物理学家们不能总是将地震资料和地层特征（属性）联系起来，而将其作为一种证据从测井资料中提取出来。对于油地球物理学家而言，合理利用好所有的信息与勘探队里的专家意见，提出缜密的可行的校准尤为重要。否则，油藏地球物理学家也就失去了这种表演的研究优势了！利用测井资料把属性做相干很简单，在强相位之间，也就是说，常常地震振幅和孔隙度就足够使很多工作者相信相干是有意义的，并且，地震振幅在储集层的特征描述中可以被孔隙代替。你可以想像这种方法存在很多潜在的风险（KALKMAN,1987,HIRCHE 等人1998 ）.井孔的统计关系必须执行统计检验，这些合理的结果也必须得到地质推断的验证，最重要的就是这些被观察到的地震属性的物理基础的验证。
地质统计
油藏的特征描述，勘探队通常是通过在储集层处理一些油井从而得到一般的推断，但是对于从这些井得到的一些模棱两可的资料：你怎么才能利用好你手头这些资料的空间分布呢？简单的在井间求平均数很容易就能看出得到的是错误结果。当观察到这些被特征在某个距离时相干，就能利用克里格法了。但这种方法有一定的局限性，它包含利用这些资料从“硬”井位资料和一些地震资料常常提供附带的证据中提供辅助的“软”证据。本质上，如果统计相关（和物理意义上）发现在整个研究区域贯穿着观察到的井间地层参数和某些地震属性是相关的，那么就允许这些井间的“硬性”资料利用地质统计技术在井间以内插值替换（通常用克里格法），而使地震解释更重要或更次要。在缺少地震资料的情况下，可以用改进的地质统计技术，在可能的井间区域里产生各种“实现”。而在有地震资料的前提下，使准确的预测成为可能，这种模型的范围也被很大程度的减少了。油藏特征描述的问题也变得不再那么随机而是更具确定性了，虽然相干分析永远不可能做到完美，仍然有很多的模型要考虑。
人们仍然能从一系列好的参考文献中获得一些地质统计方法。比如DUBRULE(1989)，JENSEN 等人 (1997)和ISAAKS和SRIVASTAVA(1989)的著作。还有很多好的案例收集在YARAS和CHAMBERS（1995）的著作中。
超薄层
近年来，特别开发了一些方法来帮助解释人员识别超薄层的性质，像对于地震资料里考虑的小于传统的1/4波长的地震数据分辨率。这些技术通过在有限带宽的地震子波里利用不同的频率，一种是频率域的，一种是时间域的。
频率域的方法称为光谱分析（比如说，你可以在PARTYKA 等人,1999的著作中找到相关案例），通过寻找频率带内的陷频衰减来代表薄层里从项部到底部的反射干扰中的虚反射信号。这种频率的虚反射或频率衰减，对应着层厚度的双程时间厚度。因为地震波包含的频率高于主频，频率衰减则指示着超薄层的存在，比如说，河道或海岸线上的尖灭，可以在光谱中用连续高频衰减在图上观察具体位置。时间域的方法涉及子波特性的匹配。常用的有神经网络工程技术（POUPON 等人， 1999）. 波从一个的层面上通过可以分为几类不同的子波，也许它们之间只是有一些细微的差别。这些分类子波产生的图形常常能够在地质构造图中找到。这种分类的目的有助于比较相对振幅（比如说旁瓣与主瓣的比较），比如主峰或主峰的“肩峰”，或某个时期内的微变，因此，常常与子波分辨率之下地质特征造成的干涉相对应。
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如果由地震引起的石油物理模拟不能执行直接的分析或解释或者证实结果，那么这两种机制都有导致解释错误的风险。对于一个油藏地球物理学家而言，已可以更加简单的把高级电脑程序包作为黑盒使用，来提供质量更好的图片，以至在解释时不会产生错误的安全感。庆幸的是，现在能买到的大多数的软件包都包含了对测试结果析模拟能力。但是这些测试结果也仅仅只是这些油藏物理学家们自己测试出来的罢了！
聚焦方法
因为作为优秀的油藏地球物理学家，他们已经对研究的对象进行了解析，对地震资料及井孔进行了校正，并且调试了在储层中由地震引起的石油物理响应的几种预期方案，这样才有可能采集到资料。也只有这种资料都是合乎我们观察地震特征需要的。举个例子说，也就是只有相信远炮检距包含研究所必须的所有信息这样一个前提，人们才会采集远炮检距地震道信息(HAOUSTON和KIMSLAND,1998)。然而，可能因为增加成本还不能保证不缺失重要资料的风险，所以，这种被高度聚焦的方法还不确定是否使用。同样的，对于有目的的采集和不同于可获得的传统的地震资料那样“良好的”或“完整的”资料使人很烦恼，即使这将会是一种把科学方法（收集资料就是为了设计对理论的支持或反证）和工程设计的实用性（及时有效的完成生烃工作）相结合的技术。
井中地球物理
油藏地球物理学家们不仅有将井资料做相关的优势，还利用这种优势在嘈杂的地表下或风化带并在最接近目标区域从井间采集异常地球物理资料。在井里用新方法获得地震资料是可行的，也许在不久的将来会成为油藏地球物理学家们的一种重要工具。震源或（和）检波器可以安置在一口井或相临井中或地面上，分析的目标可以在速度区域，可以详细的反射成像。为了可以用地球物理油井学，至少震源或检波器必须安置在井中，而且，几乎所有可以想像的几何图形排列都要认真的提出和调试。
垂直地震剖面法，校验炮，声波测井，套管井声波测井
地球物理学方法是更常规的固井包括垂直地震剖面法，校验炮勘测，传统的声波测井和套管井声波测井。开发这些方法主要是为了使表面地震资料和对井的观测联系起来，然而这些方法却远远超过了现在这些案例的应用范围了。垂直地震剖面法能够为确定子波（包括相位）和识别详细的波至提供良好的资料。它们也能对井眼附近区域成像，而且当把一些检波器和震源位置互换时，会提高成像质量。现代的声波测井工具能更好的测量纵波和横波速度，测量值要求替代流体对地震数据作用进行校正。当然了，解释人员也必须小心搞清楚数据反应的是侵入区域还是非侵入区域，在必要的时候作一些合适的修正。同时，现代声波测井工具也常通过套管提供可靠的速度值。通常，由于软页岩在一定深度内的流动或断裂而不能进行裸眼井测井，这时，人们发现，只有对软页岩下套管井后，测量结果才可信。
井间，反地震垂直剖面法和单井成像
现代地球物理固井方法已被拓展了，像将一个强震源放在井中，检波器放在另外一个井中（井间地震），在地面上（反VSP法），或者在同一口井中不同位置放置震源（单井成像）。利用这些工具，在实验中采集资料制作图形。时间也必须探测并经过数据处理，这种方法在整个操作过程中都必须把投资降至最少。这样的话，这种方法才能投入生产而不是只作为实验进行了。几年前，井间地震方法的使用还仅限于在井间区域提供有效速度的映射进行层析成像，还不能提供实像。现在，层析成像技术常用来提供两口井之间反射成像程序的速度信息使反射成像更精确（LAZARCTOS 等 1995）。强震源虽然可以提供足够有用的反地震垂直剖面法需要的资料，但只到最近才得到利用。在一些早期的研究中指出了这种方法在井口附近区域对构造精确成像有很大的发展潜力（PAULSSON 等 1997）.单井成像（HORNBY 等 1992）虽然现在还没普及，但也许会成为详细的闭合构造研究的有利工具。例如，如果盐丘侧翼研究，它有助于从某一勘探井进行开发侧钻的设计，尤其是在深水环境。_m_i |#C6|*m-z
非人工震源地震监控技术
近年来，对储集层围岩的机械响应作了较详细的研究，在北海的EKOFISK平台观察到在某种程度上的明显沉陷（FEUFEL和RHETT,1992）.虽然油气生产与天然地震的相关研究（KOVACH,1974;PENNINGTON 等人，1986；SEGALL,1989;MCGARR,1991）和注入实践（RALEIGH 等人，1976;DAVIS和PENNINGTON, 1989）在科学与天然地震文献中已付印出版。天然地震监控（因为地球物理学家不用激活一个人工震源而称为无源监控。）已经更加明确和精准了。即使在低地震强度下，这主要是缘于在井底安置检波器，避免了地面噪声而更接近震源能量了（RUTLEDGE 等人，1994）。由于注入钻井液，因而储集层围岩受压，伴随流体压力变化，小型（偶尔大型）地震事件的发生，表示层面上软弱带的剪切破坏；这些剪切破坏能够在低于油藏工程师用于拉张破坏的分裂压力很多时产生。在很多详细的研究中，很多小事似乎都指示了在石油运移过程中裂缝系统的模式与位置（例如，PHILLIPS 等人，1998）。在水压致裂中，无源地震监测和倾斜界面上的观测结果，很多案例已经导致了储集层发展的提高（例如，CASTILLO 和 WRIGHT,1995;李等人，1998）。水压致裂监测方法已经在石油工业中作为一种常规方法（也就是说，不再是凭经验了）在合适的地方加以应用了。
总结
随着地球物理方法的日趋完善，由于油藏地球物理学家已经可以提供逐渐精细了解的水平并已将之作为与油藏开发相关的各种常规应用，这些应用最广的方法，就像地震勘探中的反射波法地震勘探，几乎全是三维的。这些方法，已经成功的证明了它们在工业效益中不同阶段的潜在能力，包括交叉测井，正反垂直地震剖面法，无源地震监控技术（重力，电磁的，和一些其它的方法，在本刊的其它文章中都有介绍）。油藏地球物理学家明显优势依赖于对目标油藏现存资料的质与量，使得测量集中在上体目标上，对于地层的地球物理观测结果进行校正（为了对结果有必要的可信度，同时为了提高成像质量）。由于工程师对地球物理方法和油藏地球物理学家对工程设计的实践的掌握更加自如，油藏地球物理方法的应用将会更多更广。
致谢
美国能源部在俄克拉荷马州的塔乐萨国家原油工艺技术局提供的一份合同的支持下起草了这篇论文，“对油藏特征进行的地震属性校准”是项目经理PURNA HALDER完成的。
参考文献
[ 此贴被chengjun在2008-05-07 12:10重新编辑 ]
