1-D Seismic Data
One-dimensional seismic data (1-D seismic data) is a single seismic trace recorded at one point on the surface, representing the acoustic response of the earth directly below that location as a function of two-way travel time. A single trace records pressure or particle velocity at the geophone as seismic energy travels down from a source, reflects off subsurface boundaries, and returns to the surface. The trace gives vertical information about the rock column beneath one point but no spatial information about the lateral extent or geometry of those reflectors. One-dimensional seismic data is the simplest form of seismic measurement and the building block of all more complex seismic surveys: a 2D line is a series of 1D traces acquired along a surface traverse, a 3D survey is a dense grid of 1D traces acquired over an area, and a vertical seismic profile (VSP) is a set of 1D traces recorded at depth inside a wellbore.
Key Takeaways
- A 1-D seismic trace is typically displayed as amplitude versus two-way travel time (TWT), measured in milliseconds. Each peak or trough on the trace corresponds to a reflection from a boundary between rock layers with different acoustic impedances (impedance = velocity × density). A strong positive reflection marks a boundary where impedance increases downward (e.g. shale over sandstone with higher velocity). A strong negative reflection marks a boundary where impedance decreases downward (e.g. sandstone with gas replacing brine, which lowers velocity).
- Synthetic seismograms are constructed from well log data (sonic velocity and density logs) to create a modelled 1-D trace that represents what the seismic response at the well location should look like. The synthetic is then compared to the actual 1-D seismic trace extracted at the well location to calibrate the seismic-to-well tie: confirming which seismic event corresponds to which geological horizon in the well. The quality of this tie controls the reliability of seismic interpretation across the rest of the survey where no well control exists.
- In early seismic exploration (before the 1950s), 1-D data was essentially what operators had: single-shot records from a geophone at a known offset from the shot point, read manually from film records. The introduction of multichannel recording and common-depth-point (CDP) stacking in the 1960s transformed exploration by combining many 1-D traces from different source-receiver pairs that image the same subsurface point, dramatically improving signal-to-noise ratio through stacking. Modern 3-D seismic surveys produce millions of 1-D stacked traces assembled into a volume.
- One-dimensional seismic modelling is an important tool in prospect evaluation. Given a reservoir model (porosity, fluid type, depth), the geophysicist can calculate what the 1-D seismic response should look like at that well location, then scan the seismic volume for traces that match that signature. This is called seismic amplitude versus offset (AVO) analysis or rock physics forward modelling: using 1-D physics to predict the seismic signature of a target, then searching for it in the 3-D volume.
- Vertical seismic profiles (VSPs) are a specialized application of 1-D seismic data where geophones are clamped to the borehole wall at intervals inside a well while a seismic source fires at the surface. Each geophone records a 1-D trace, and the set of traces at known depths calibrates the relationship between travel time and true depth at the wellbore location. VSP data provides higher resolution than surface seismic because the wave travels only one way through the attenuating near-surface section rather than twice.
From One Trace to a Volume
The simplest way to picture seismic data is to imagine dropping a stone in a pond and watching the ripples. In reflection seismology, a seismic source (dynamite, air gun, vibroseis truck) generates a pulse of energy that radiates down into the earth. When that energy hits a boundary between two rock layers with different acoustic properties, some of it reflects back toward the surface, where geophones or hydrophones record the returning signal.
One geophone at one location records one trace: a waveform that shows which reflections arrived and when. That is 1-D seismic data: the vertical structure of the earth beneath one surface point. The limitation is obvious. A single trace cannot tell you whether the reflector it records is 100 metres wide or 10 kilometres wide. It cannot tell you whether a bright reflection is a gas sand or a coal seam or a tufa deposit. It cannot image the flanks of a structure because those dip away from vertical.
To get spatial information, you need many traces arranged in a line (2-D) or a grid (3-D). But every 2-D or 3-D dataset is assembled from individual 1-D measurements, and understanding what a single trace tells you and what it cannot tell you is the foundation of seismic interpretation.
Fast Facts
The first commercial reflection seismic survey was acquired in the United States in 1924 by Geophysical Research Corporation, a subsidiary of Amerada (later Hess). The survey used a single geophone at one location and recorded the reflection from a salt dome in Oklahoma. The single-trace 1-D record showed a coherent reflection arrival that allowed the geologists to identify the presence of the salt structure before drilling. This led directly to the discovery of the Orchard Salt Dome field in Texas, the first oil field found using reflection seismology. The shot record from that survey showed 1-D data in its purest form: one trace, one shot, one structure confirmed. Amerada went on to drill the field and proved the commercial value of seismic exploration for the first time.
Using 1-D Seismic Data in Well Tie and Horizon Picking
Well tie is the process of connecting the geological information in a wellbore to the seismic image above it. A wireline log suite (sonic travel time, density) is converted to acoustic impedance at each depth. The contrast in impedance between adjacent layers is the reflection coefficient, and a series of reflection coefficients convolved with the seismic wavelet (the shape of the seismic pulse) produces the synthetic seismogram: a modelled 1-D trace.
The interpreter extracts the actual seismic trace at the well location (or the average of a few traces in a small region around the well) and compares it to the synthetic. When the peaks and troughs align, the interpreter knows which seismic event corresponds to which geological boundary. Once the tie is established, the interpreter can pick a seismic horizon across the entire 3-D volume using that calibration. Without a good 1-D well tie, seismic interpretation of a formation is essentially guesswork about which event to pick.
Synonyms and Related Terminology
One-dimensional seismic data is also called a seismic trace, a shot record (before stacking), or a stacked trace (after CDP stacking). Related terms include seismic trace (the basic unit of seismic data; a record of ground motion amplitude versus time at a single location; the building block of 2-D and 3-D seismic surveys), synthetic seismogram (a modelled seismic trace constructed from well log data by converting sonic and density logs to a reflection coefficient series and convolving with a seismic wavelet; used to tie well stratigraphy to the seismic image), vertical seismic profile (VSP, a set of seismic traces recorded by geophones clamped inside a wellbore while a surface source fires; provides higher resolution and direct depth calibration than surface seismic), two-way travel time (TWT, the time for a seismic pulse to travel from the surface to a reflector and back; the horizontal axis of a seismic trace and seismic section; converted to depth using velocity), and acoustic impedance (the product of seismic velocity and density; the contrast in acoustic impedance between two rock layers determines the amplitude of the reflected seismic wave recorded on a 1-D trace).
How a Single 1-D Trace Identified a Viking Sand Anomaly Before a 3-D Survey Was Acquired
A small independent operator held undeveloped acreage in the Provost area of east-central Alberta, overlying a known Viking Formation gas trend. The company could not afford a full 3-D seismic survey over the acreage before the expiry of their land rights. Instead, they commissioned a reprocessing and detailed analysis of the single 2-D seismic line that crossed the acreage, which had been shot in 1987 and never fully interpreted for Viking targets.
The geophysicist extracted the 1-D seismic trace at the location of an existing offset well that had produced Viking gas 8 kilometres to the northwest. Using the offset well's sonic and density logs, she built a synthetic seismogram for the Viking interval and tied it to the 2-D line. She then tracked the Viking reflection along the line and identified a bright amplitude anomaly 2.8 kilometres south of the existing edge of Viking production. The amplitude was approximately 40 percent stronger than background, and it showed a polarity reversal consistent with gas-bearing Viking sand (soft kick, negative impedance change).
The operator drilled a vertical well targeting the anomaly. The well encountered 9 metres of gas-bearing Viking sand with 22 percent porosity and 28 percent water saturation, confirming the amplitude as a direct hydrocarbon indicator. The well produced at an initial rate of 32 thousand cubic metres per day. Total cost of the 1-D trace analysis and synthetic seismogram work: CAD 18,000 in consulting fees. The well cost CAD 1.1 million to drill and complete. The discovery triggered a follow-up 3-D survey that outlined six additional Viking locations. The entire program would not have been initiated without the 1-D trace analysis that identified the anomaly first.