Friday, August 10, 2018

Geophysical Interpretation: From Bits and Bytes to the Big Picture

Well logs measure reservoir properties at interval of a few inches, providing a high density of information mostly in the vertical direction. But the volume of reservoir sampled by logs represents only one part in billions. Seismic data, on the other hand, cover the overwhelming majority of reservoir volume but at lower vertical resolution. A processed three-dimensional (3D) seismic survey may contain a billion data points sampling a couple of trillion m3 and some surveys are 10 times bigger. The geophysical interpreter must handle this massive amount of information quickly and produce a clear 3D picture of the reservoir that can guide reservoir management decisions.

In the overall seismic scheme, interpretation builds upon the preceding work of acquisition and processing. Fast new ways to simultaneously visualize and interpret in three dimensions are changing how interpreters interact with geophysical data. Seismic interpretation packages band together a collection of tools designed to simplify seismic interpretation and smooth the road from input to output. GeoQuest's seismic interpretation tools -Charisma, IESX systems - offer a variety of levels of user-friendliness and sophistication. These packages complete the process in roughly four steps-data loading, interpretation, time-to-depth conversion, and map output. This article takes a look at how they help the geophysical interpreter harness a seismic workstation filled with a billion data points -and make it fun.

 Getting Data in the Right Place

By the time 3D data arrive at the interpretation workstation, they have already undergone numerous quality control checks, and are ready to be loaded. The objective in data loading is to ensure that as much of the available data as possible is loaded onto the computer, and that these data points are correctly positioned. Data loading continues to be simplified by software advances.

Fitting all the data onto the computer has been difficult because disk space has been expensive. To work around the problem, most data loading routines convert seismic traces from SEG-Y format to a compressed workstation format. This compression can be perilous, because it reduces dynamic range of the trace data. SEG-Y data are usually represented in 32-bit floating point format, which allows a range of +/- 10 ^37 . Data in 16 bit format have a range of +/- 32,768. Converting data from 32-bit to 8-bit reduces computer storage requirements by a factor of four, but also reduces dynamic range. Reducing dynamic range may negate much of the care and money that went into acquisition and processing of the seismic data. Although the dynamic range of compressed data is usually more that the human eye can perceive, computer-driven interpretation can be made to take advantage of 32-bit data. Some specialist recommend that data never be compressed, and since disk space is becoming less expensive, that will eventually become a more widespread option.

When compression is necessary, workstations can help the interpreter do it intelligently through scaling. Scaling ensures that data amplitudes are properly sized so that the most important information is preserved when trace values are converted from SEG-Y format to compressed format. In the Charisma system, scaling must be user-controlled and different scale factors can be tested; this allows flexibility, but usually requires practice. In the IESX systems, scaling is done automatically, trace by trace. The scaling factor is stored in the header of each trace. The factor is reapplied to the each trace it is read from the data base. This results in a reconstructed 32-bit seismic section, regardless of the storage format. 

Loading seismic data in the righ place in the computer involves assigning a geographic location to each trace. For 3D data this is simpler than for 2D: inputs are the spatial origin and orientation of the volume, the order and spacing of the shot lines, and the trace spacing. From these few numbers, geographic coordinates for each of thousands or millions of traces can be computed. 

If there are older 2D or 3D data, or offset seismic profiles (OSPs) to be interpreted with the currently loaded 3D survey, data loading becomes more complicated. Trace locations for each 2D line or OSP must be accessed from separate navigation files or from the trace header themselves. Data of different vintages, amplitudes and processing chains must also be reconciled. This is not a trivial task, but is greatly eased with today's workstations. 




Additional data that can be loaded include well locations, well deviation surveys, log data, formation tops, stacking velocities from seismic processing, time-depth data from well seismic surveys and cultural or geographic data such as lease boundaries or coastlines. 

In 3D surveys, the seismic lines shot during the survey are called inline sections or rows, Vertical slices perpendicular to these , called crossline sections or columns, can be generated from the inline data . In 3D land surveys, the acquisition geometry can be more complicated than marine surveys, but usually the inline direction is taken to be aling receiver lines. In both cases, horizontal slices cut a constant time are called time slices. 




The way seismic data are stored by different systems affect the time required to generate new sections and display or perform other poststack processing. In the Charisma and IES systems, inline sections, crossline sections and time slices are stored separately, so a single data value may be stored up to three times. In the IESX system, every inline trace is stored only once, decreasing data storage volume. In such a volume there is no need to generate crosslines because arbitrary vertical sections may be cut in any orientation in real time. Horizontal seismic data are stored in a separate file.

Until recently, 3D data loading routines were not user friendly, often requiring a computer specialist. But new applications are beginning to make this step more straightforward, allowing interpreters to load their data alone or with support over the telephone. However, most companies still employ dedicated data loaders, or use contract workers.

Tracking Continuities and Discontinuities

Now we come to the real interpretation part of the job- identifying the reservoir interval and marking, either manually or automatically, important layer interfaces above, with and below it. The interfaces, called horizons, are reflections that signify boundaries between two materials of different acoustic properties. Interpretation also includes identifying faults, salt domes and erosional surfaces that cut horizons.




Some interpreters first pick horizons as far as possible horizontally on a set of vertical sections, the outline faults. Other interpreters pick faults first, then pick horizons up to their intersections with faults. The choice depends on personal preference and experience. Horizon shallower than the reservoir should be interpreted because they affect horizons below. Interpretation of horizons outside the reservoir interval is important if they correspond to regional markers that can be picked from logs. Interpreting several horizons that bracket the target zone may also be used to enhance time-to-depth conversion and give clues to geologic history.

Knowing which horizons correspond to the reservoir comes from previous experience in the area, such as earlier 2D seismic lines. This is usually accomplished by tying 3D data to an existing 2D line or well. Tying a seismic line to a well is done by comparing an expected seismic trace at the well with real seismic data. This is achieved with synthetic seismograms. To create a synthetic, the sonic and density logs are converted to time, often by using a check-shot survey. Next, the sonic and density logs are combined to give an acoustic impedance log- the product of velocity and density. Then, through an operation called convolution , a pulse trace that mimics the seismic source is used to change the acoustic impedance log into a synthetic seismic trace.


Now it's time to compare the synthetic with the seismic data at the well. Geologic boundaries , such as top of the reservoir, are identified in the original logs. The boundaries are then correlated with the time-converted logs, acoustic impedance log and then the synthetic seismogram. Waveform charaacteristics of the synthetic are compared with the real seismic trace to determine the seismic representation and travel time to the geologic boundaries at the well location. However, at seismic wavelengths -50 to 300 ft -what appears to be one layer in the seismic section will normally be several layers in the logs. A main use, then, of tracking horizons in seismic data is not to distinguish thin layers, but to provide information about the continuity and geometry of reflectors to guide mapping of layer properties between wells. 

To track a horizon, trace characteristics are followed horizontally across the whole seismic survey. Common characteristics used to track an event are the polarity or change in polarity of the trace. At any time, a trace will be of either negative or positive polarity, or a zero crossing. A positive polarity reflection, or peak, indicates an increase in acoustic impedance, while a negative polarity reflection or trough, indicates a decrease in acoustic impedance. A zero crossing is a point of no amplitude, usually between a negative and positive portion of a seismic trace. The amplitude of the peaks and troughs is usually color coded. A wide range of color schemes allows interpreters to accent features to be tracked.

A horizon may be tracked in a variety of ways. Points on the horizon may be manually picked by clicking with the mouse on a visual display of a vertical section. If the seismic signal is sufficiently continous, the horizon may be tracked automatically using a toll called an autotracker. Autotracking  requires the interrpeter to specify the signal characteristics of the horizon to be tracked. These include polarity, a range of amplitude and a maximum time window in which to look for such a signal. Given a few seed points, or handpicked clues, autotrackers can pick a horizon along a single seismic line or through the entire data volume. In faulted areas, autotrackers can usually be used if seed points are picked in every fault block. Horizons picked with autotrackers must be quality checked manually and may require editing by an interpreter. Still, the time savings is huge compared to manually picking thousands of lines.

If the horizon is difficult to follow, the data can be manipulated using processing applications available within most interpretation systems. The charisma processing toolbox, for example, includes a variety of filters and other options to produce data that are easier to interpret, without expensive reprocessing. Dip filters suppress noise outside a specified dip range and highpass filters can reveal discontinuities. Other processes include deconvolution to extract an ideal impulse response from real data, time shifts to align traces, polarity reversals and phase rotations to match data with different processing histories, scaling to boost amplitudes of deep reflections, and time varying filters to compensate for wave attenuation.

Some horizons defy reprocessing efforts, and remain too complex to track with  conventional autotrackers. Three examples are: (1) reflections that change polarity along the horizon in response to a lateral change in lithology or fluid content; (2) a local minimum that is positive or a local minimum that is positive or a local maximum that is negative; and (3) horizons that are laterraly discontinuous. Surfaceslice volume interpretation helps track these tricky horizons by displaying what might be thought of as "thick" time slices. The SurfaceSlice application was developed at Exxon Production Research and has been incorporated into GeoQuest's IESX system. 

The surfaceslice method can be thought of as scanning the 3D cube to create a new seismic volume that contains only samples that meet some criteria set by the interpreter, such as local troughs with a given amplitude range. Thick slices through the volume are displayed in a chosen color scheme. The slices contain only data on the t ypes of horizons of interest. SurfaceSlice slices resemble a series of contour maps, and are therefore convenient for geologist to interpret. Slice thickness is interactively controlled by the interpreter , and is usually chosen to be less than the wavelength of the reflection in order to stay on the chosen horizon. Multiple windows show a series of slices at increasing times in which the horizon can be rapidly tracked in areal swaths rather than line by line. 

Once picked, either manually, by autotracking or by surfaceslice analysis, the horizon serves multiple purposes. Shallow horizons can be flattened to give a rendition of the underlying volume at the time of their deposition. A horizon, really a set of time values draped on a grid of trace locations, may be linked to a formation marker identified in well logs. If the marker has been picked in several wells, this serves as a consistency check on the seismic interpretation. This link may be used later for time-depth conversion or for extending formation properties away from wells. 

Faults and other discontinuities may be picked manually with the mouse in two ways. As in 2D interpretation, classic fault interpretation is done on vertical sections - either inline, crossline or other sections retrieved at any desired azimuth. A fault picked on one section can be projected onto nearby sections to give the interpreter an idea where to look for the next fault pick. Thrust fault and high-angle structures such as salt domes require special handling, because a given horizontal location may have multiple vertical values. A new way of picking faults, made possible by 3D workstations, allows the interpreter to identify faults from discontinuities in time slices. 

Another interpretation technique that takes advantage of the 3D nature of data storage is called atribute analysis. Every seismic trace has characteristics, or attributes, that can be quantified, mapped and analyzed at the level of the horizon. And through mapping a horizon is based more or less on the continuity of the seismic reflection, attributes can vary in many ways along the horizon. Traditional trace attributes include the amplitude of the reflection, its polarity, phase and frequency.  These trace atributes were introduced years ago to highlight continuities and discontinuities in 2D seismic section. Now , with the addition of high-speed 3D workstations, interpreters have the freedom to explore new types of attributes. Attributes such as dip and azimuth of horizons can instantly reveal discontinuities and faults that could take weeks to interpret manually. Interpreters are also using attributes to apply attributes to apply sequence stratigraphy to 3D data. 







The reservoir takes shape

An advantage of 3D workstations is their speed  compared to a pencil-and-paper job; autotrackers lift some of the workload from interpreters, letting them do more in less time. Other advantages , such as time slices, surfaceslice displays and attribute maps, are techniques made possible because the data reside in 3D on a workstation. But the seismic sections are still 2D representations of 3D information, and interpreters still perform quantitative interpretation of 2D.

This is changing as more interpreters use the full 3D-visualization capabilities of new workstations. The ability to see the data volume, to zoom and change perspective, gives interpreters new insight into the features they interpret on horizons. Proper illmination makes surfaces easier to understand. Changing the light source to a grazing elevation can highlight subtle features such as faults and fractures, for the same reason that the best aerial photos of the earth's surface are shot in early morning or late afternoon to maximize shadows. More advanced workstations allow interpreters to illuminate horizons with lights from different locations and change the reflective properties of surfaces. Interpreters can spend less time figuring out what the structure is, and more time understanding how it can affect development decisions. A rainbow colored contour map, once a marvel of the seismic screen, pales next to a 3D rendering of the same surface. 


Structures that appear obscure or disconnected when examined in 2D seismic views may become clear or continuous in 3D. Or just as importantly, features that appear connected in one perspective may be disjointed in another. Seismic properties between two deviated wells, either existing or proposed, can be examined by extracting the seismic image on the twisted plane between them. This gives reservoir planners a toll for verifying reservoir connectivity, whether for exploration purposes or for planning improved recovery campaigns. Well logs, interpreted horizons, faults and other structures can be viewed and moved, alone, or along with the seismic data. 

Today, the most powerful 3D visualization products provide real-time interaction with the 3D image for lighting, shading , rotation and transparency. However, interaction with the image for creating and editing interpretation has typically been limited.

Time-to-Depth Conversion

Once horizons and structures are interpreted in time, the next step is to convert the interpretation to depth. The relationship between time and depth is velocity, so a velocity model is needed. Different workstation systems exhibit varying degrees of sophistication in their creation of velocity models for time-to-depth conversion. Most systems offer simple geometrical conversions based on velocity models that may vary vertically and horizontally. These convert points from time to depth by moving them in straight vertical lines. The Charisma DepthMap package includes geophysical modeling in the form of seismic ray tracing and permits lateral translation of points ot perform time-to-depth conversion with increasing reliability.

If more than one horizon is to be converted to depth, an average velocity to each horizon must be estimated, or the average velocity to the shallowest horizon and the velocity between each horizon down to the target horizon.





In the absence of logs or well seismic surveys, seismic stacking velocities can subtitute for average vertical velocities. Stacking velocities are derived from seismic data during processing, and used to combine seismic traces to produce data that are easier to interpret. They contain large components of horizontal velocity and are usually available at 500-m to 1-km spacing across the survey area. These data are interpolated to the same sample interval as the seismic time horizon grid. Then the velocity grid is multiplied by the time grid to give a depth grid. The key limitation of stacking velocities is their lack of accuracy, especially in regions of complex velocity or of complex structure. 

Time-depth data from a check-shot survey give an accurate vertical velocity model, but only at the check-shot location. In the absence of other data, this velocity can be used uniformly across the field to convert the seismic times to depth. Stacking velocities can be calibrated at the well using check-shot surveys.

A synthetic seismogram built from sonic and density logs can provide a comparison trace for time-to-depth conversion. Disadvantages of this technique are the limited extent of logs- most logs do not provide information all the way to the surface -and the discrepancy between velocities measured at sonic frequencies. Synthetics are most useful when calibrated with a check-shot survey, which improves the time-to-depth conversion.

Velocity models and images from VSPs are the most powerful data for converting surface seismic times to depth. VSPs sample velocities at more depths than check shots, and unlike synthetic seismograms created from sonic logs, VSPs have a frequency content similiar to that of surface seismic waves. And above all, VSPs provide images that can be matched directly to surface seismic sections. 

Putting it all on the map

Once data about reservoir structures are stored, 2D and 3D map images can be generated for reservoir characterization. Surfaces may be mapped in time, or , if there is a velocity model, in depth. Basic mapping tools for this reside within most seismic interpretation packages, and there are also separate, stand-alone mapping packages that accept seismic interpretations for map generation.



 




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