Author: Mike Cline, T/X Resources
As I mentioned in the previous post on seismic inversion, using zero-phase seismic data as an input for inversion, is one of the most critical elements for accurate results. However, this brought up the question of “how bad is bad”, when it comes to phase-matching errors? So, to answer this question, I had an idea to test the sensitivity of inversion results based on the phase of the input data.
Below, is a series of inversion images which were produced from the same initial synthetic seismogram. However, prior to generating the inversion, I rotated the phase of the input data in the amount indicated at the bottom of each image—that is: 0, 45, 90, 180, 270, and 315 degrees.
See the larger Adobe Reader pdf file.
Author: Mike Cline, T/X Resources
I recently wondered why I hardly ever see anyone using the Seismic Inversion tool, found in SMT’s TracePak module? Maybe you’ve thought about using it, but didn’t understand it well enough, or maybe tried it once, and the results didn’t match anything in the well(s). Like anything new, if you don’t under- stand it, it’s going to be difficult to use it properly. So, I thought that it would be helpful to explain some of the benefits and pitfalls of using inversion, for those interested.
First, for those unfamiliar with inversion, what is it, and how do we use it in our interpretation? You could think of seismic inversion as the reverse of a synthetic seismogram processing flow, and we use inversion to get some idea about rock properties. For an example, the portion of the seismic inversion in the image below, was generated from a synthetic seismogram in the well at the center of the line. Normally, you would generate the inversion from an actual seismic line, but I wanted an optimum response for this example. I’ve also posted three well logs from this well: the spontaneous potential (aka. SP log) in blue, the deep resistivity (RES log) log in magenta, and the acoustic impedance (AI log) in red.
See the larger Adobe Reader pdf file.
Author: Mike Cline, T/X Resources
No, the title isn’t about those difficult teenage years, it is related to the subtle details of seismic phase determination. Sorry if you thought that I was going to solve one of life’s little mysteries. 
How many times have you correlated two different sets of intersecting seis- mic data, and had difficulty trying to decide which phase rotations produce the best character match? For example, when you were trying to tie a syn- thetic seismogram with a seismic line, or correlate two seismic lines of various vintages. I have (many times), and until I figured this out, I sometimes had nagging doubts about my selections.
Here’s how I do it now. The four columns of traces below were taken from a larger synthetic in a singe wellbore, and they represent four different phase rotations. From left-to-right: zero degrees, 90 degrees, 180 degrees, and 270 degrees. Note that the synthetic time interval that I chose for this example has no particular significance, other than it was relatively compact, and had many of the phase details that I wanted to illustrate.
See the larger Adobe Reader pdf file.
Author: Mike Cline, T/X Resources
For those who read my previous posting, “Making the Case for Synthetic Seismograms“, but didn’t currently have a program to generate your own synthetics, I thought that I would include a few links to the programs that I knew about. All of the programs listed below, except SMT’s SynPak, are stand-alone programs, or part of a group of software related to synthetics (log editing, AVO modeling, etc.)—at least that I could determine from their websites.
Please note that I have only used the first two programs in the list, and cannot recommend any of the remaining software, relative to how accurate they are, how well they perform, etc. The list is provided for your informa- tion, and convenience only.
Author: Mike Cline, T/X Resources
Why bother using synthetic seismograms (aka. synthetics) to calibrate well info to our seismic data? Simple answer, TO REDUCE DRILLING RISK !
For example, I’ve seen prospects “evaporate” because the originator was mapping the wrong event—or just as bad, started mapping on the correct event, but ended up on the wrong event due to a character, or response change in the seismic data. This only became evident after a couple of synthetic correlations!
I also continue to see prospects that are being sold on the strength of an amplitude, or avo response, that is somehow related to a key wellbore. However, often a synthetic hasn’t been used to tie (correlate) the well to the seismic data. How could they even know for sure what was causing the anomaly, without a synthetic tie?
So, with these recent real-life examples in mind, I thought that it would be a good idea to cite some reasons why we should use synthetics, with a blog posting.
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Author: Mike Cline, T/X Resources
Since the first posting, I’ve gotten nothing but encouraging comments. Here are a few:
“Good work Mike.” (Michael M.)
“This is very interesting!” (David W.)
“Excellent idea.” (Teri B.)
“I think it’s a great idea.” (Sara V.)
“Works!” (Yvon H.)
“Wow! You did it.” (Mark C.)
“Thanks a lot for your blog, brilliant idea.” (Julien F.)
From the sound of it, visitors may be starting to realize the potential usefulness of the blog (at least I hope so), and how the old SMT User email forum might mesh with it. I also just checked my website stats, and the number of “hits” is up by orders of magnitude–so I know it has gotten some interest from viewers.