Welcome to the AAPG Learn! Interview Series. We are launching an interview series with AAPG members and also participants in our events so that you can learn about what they're doing and potentially get in contact, collaborate, and advance your knowledge. Our interviews also tie to our events such as a great new
workshop that addresses ways to be profitable in a downturn. Today we have an interview with William D. Chandler, whose work on the wellsite has led to the development of innovative new ways to identify productive zones.
1. What is your name and your experience in the oil industry?
My name is William D. Chandler. I have served the oil industry as a well site geologist for thirty seven years. I started out in the Permian, and have worked for many years in the Mid-Continent, as well in the Arkoma basin. For the last 7 years I have served primarily in the Fort Worth basin. Five years ago in April I dedicated my endeavors to this methodology, and the evolution of Formation Logging. This workflow extracts chromatography data from the drill cuttings as opposed to the mud stream.
2. What are some of the overlooked properties of cuttings?
Extracting gas from drill cuttings and following the prescribe formula, the data always tracks density porosity. The chromatography from drill cuttings can reveal water/oil contracts, and high grade resistivity curves in shale, sands and limestones.
The data from drill cuttings can create solid reliable models, from well to well. Data taken from the drill cuttings is not affected by produced or background gas, that affects the mud gas system. The chromatography signature of "Oil in a Rock" gives 20/20 optics, and overcome false negatives produced by other high tech data. Drill cuttings can confirm or deny commercial quality reservoirs by deriving the content inside the cuttings.
3. Do you have to derive the information from the cuttings while they're being drilled, or is it possible to go a core / cuttings repository and run tests?
Yes, we derive all data in the field while the well is being drilled, and the intervals are always above, during, and after, zones of high interest. This methodology is labor intense, and sample quality, and collection is critical, and focused. All data is given to the end user in the field, in a timely manner.
4. What is your new methodology? What is involved?
The methodology requires protocol, and follow the recipe from sample collection, and high grading the cuttings before testing. Reducing practical size will release trap hydrocarbon within the drill cuttings. Capture the gasses, and imputing the rock gas in a chromatograph that is designed for our process. After the data been acquired from the cuttings, the raw data is processed using a algorithm that gives us our unique data points that track density, and resistivity curves. The final data is then plotted on a log, and tied to the well bore with other LAS data supplied by the operator. (Gamma, drill time, e-log data). This is not a function of mud logging services due to dedication to the process. We tried it, and it was a disaster every time.
5. How did you get the idea to combine the methods and create a new workflow?
This method was used by this industry around 40 years ago. It was still being implemented my first year in the field after collage. It was pack up, and burred away soon afterwords. I dug it up just as it was left with one curve, 5 years ago. Back then gas was run from a blender to a Wheatstone bridge filament, and the gas was measured in units, just as mud gas systems still use today. The industry called it cuttings gas. After many challenges we now have a workflow that works well in tighter formation, with eight curves, (C1 to NC5) and delivers robust data that uses percent's, and a algorithm designed by Geophysicist. The method is in the low tech arena of ideals, but tracks and validates high tech data, and we call it Formation Logging. What was old and tired, is now new an timely for the economics of our industry, and increases our reservoir intelligence for the tighter formations we prospect for.
6. Where does it work best? What are a few examples?
It works in all consolidated sandstones and conglomerates.We are measuring matrix gas and the grains need to be cement either by limestone or silica cement. In sandstone the data can be lost if the samples in not processed within a very short time of being caught. You must expedite all sandstones, conglomerates, and granite washes.
It works very well in all carbonates, from dolomite to all limestone formations. Its finds low permeability oil legs, as well as good primary porosity zones with amazing accuracy.
It works in shale with non oil-based muds, and will track density porosity like fingers in a glove. This method is effected to some degree by oil base mud, and should not be used.
This method is used to geo-steer in oil windows in sandstones, and limestone lateral wells with amazing success. Gamma dose not see oil, and this method sees oil very well.
This method can identify open subterraneal fractures by comparing matrix gas increases, with mud gas increase. If mud gas increase, and the rock gas dose not. The mud gas increase came from a open fracture.
7. What are your plans for the future?
This is a easy question, Dr. Nash. I have only one plan: To keep evolving this methodology, and pushing the envelope with the ever opportunity that comes my way. The bigger challenge will be to vet the data with the oil producers around the different basins. I know this industry needs the best data available from low tech, and high tech. It is my passion to be the face of Formation logging, and see it come to it full capabilities. To promote its ability to overcome false positives, false negatives and integrate this with petrophysical data for solutions that effect challenging formations.