When interviewing potential senior-petrophysicist recruits, we exchange pleasantries to break the ice and then I ask an easy, yet fundamental technical question: “How would you explain Archie’s law to an inexperienced colleague?” Then, I sit back in expectation of a slick answer from the candidate. Imagine my surprise when the interviewee takes a sharp intake of breath, looks up at the ceiling, scratches his head, and, finally, exhales audibly before launching into a ramble with more “errs” than a David Beckham post-match press conference.
“Sorry, I do know it. Honestly, I use it every day in my petrophysical interpretation program. It’s just that I haven’t been asked to describe it before. Sorry,” mumbles the candidate. Unfortunately, the scene I have just described is an all-too-common one. I was genuinely taken aback that some experienced petrophysicists were unable to state Archie’s law chapter and verse.
I was expecting to hear something like, “Archie’s law relates the in-situ electrical conductivity of a sedimentary rock to its porosity and brine saturation. It is purely empirical, describing ion flow (mostly sodium and chloride) in clean, consolidated sands, with varying intergranular porosity of moderate to high values. Electrical conduction is assumed not to be present within the rock grains or in fluids other than water.”
Hence, I was gladdened by the news that, from next September, the University of Aberdeen in Scotland is to offer a master’s degree in petrophysics and formation evaluation.
Hopefully, the next generation of petrophysicists not only will answer my question without hesitation but also will appreciate the danger of blindly applying Archie’s law.
At a recent conference organized by the London Petrophysical Society to celebrate 70 years since Gus Archie gave his seminal paper, attendees were reminded of the various influences on calculated water saturation. It was shown that, with a classic Archie rock of 20% porosity and formation and water resistivities of 10 and 0.1 Ω∙m, respectively, the resulting computed water saturation of 50% will have a fractional uncertainty of 7%, which increases rapidly for porosities less than 10%. The uncertainty depends on the combination of reservoir parameters. At high porosity, the major contributor to uncertainty is formation resistivity. At intermediate porosity, the major contribution is from the cementation exponent. And, at low porosity, the most significant parameter is porosity itself.
Archie’s work is one of many fine papers in the archives of SPE and the Society of Professional Well Log Analysts that deserve to be read, to understand the methods described therein, where they can be applied, and, possibly more importantly, where they cannot. Simply knowing how to drive expensive interpretation software is no substitute for a solid understanding of the fundamental theory behind the key strokes.
This Month's Technical Papers
Core-Analysis Elephant in the Formation-Evaluation Room
Relative Permeability Hysteresis: Water-Alternating-Gas Injection and Gas Storage
Advances in Special-Core-Analysis Data Interpretations of Multiscale Measurements
Reservoir-Fluid Characterization From Tests on Tight Formations
Recommended Additional Reading
SPE 158545 A Greater Dolphin Area Case Study Part 1: Defining Geological Uncertainty by K.S. Taylor, BG, et al.
SPE 163973 Gas/Condensate Flow Behavior Within Tight Reservoirs by Mahmood Al-Harrasi, Petroleum Development Oman, et al.
SPE 164884 Modeling Net-to-Gross in Deepwater Reservoirs by Jiajie Chen, Marathon, et al.
IPTC 16808 The Eagle Ford Shale Play, South Texas: Regional Variations in Fluid Types, Hydrocarbon Production, and Reservoir Properties by Yao Tian, Texas A&M University, et al.
