Screening With the Template
Learning objectives
- Use the template in reverse: drop a measured point on the mesh and read its porosity and fluid together
- Classify clean cases: at porosity 0.25 the brine, oil, and gas points fan out in velocity ratio near 1.91, 1.64, and 1.48
- Separate the trap case: a gas sand and a soft brine sand sharing an impedance near 5.7 split cleanly at velocity ratios 1.49 and 1.97
- Close the part: calibration freezes a model of the rock as it is, but production changes the rock, which is Part 8
Using the Chart in Reverse
The template was built forward, from a model to a mesh. Screening runs it backward. You bring a point, an impedance and a velocity ratio measured on a log interval or picked from an inverted seismic volume, and you drop it on the mesh. Where it lands reads out two things at once: which fluid curve it sits nearest names the fluid, and where along that curve it falls names the porosity. One plotted point, two answers, and the whole apparatus of the previous five sections is what makes those answers trustworthy, because the mesh under the point is a physical model calibrated to the field it screens, not a guess.
Clean Reads and the Fan of Fluids
Start with points the mesh handles cleanly. Take three intervals that all invert to a porosity near 0.25 but differ in fluid. The brine one lands at with ; the oil one at with 1.64; the gas one at with 1.48. Same porosity, three fluids, and they fan out across the velocity-ratio axis in a fixed order: brine high, oil dropping sharply, gas lowest. A reader who knows the mesh sees the fan and names the fluid before doing any arithmetic. The impedance then places each along its curve and reads the porosity. This is the everyday use of the template, a fast, physical first pass over a whole reservoir that turns two seismic attributes into a porosity-and-fluid map.
The Trap the Second Axis Catches
Now the case that justifies the whole two-axis design. Consider a porous brine sand at a porosity of 0.30, which lands at and , and a less porous gas sand at 0.20, which lands at and . Their impedances are all but identical, near 5.7. On an impedance map, or on any single-attribute inversion, these two rocks are the same pixel, and a screening that looked only at impedance would call them both the same thing and be wrong about one of them. The velocity ratio pries them apart without ambiguity: 1.97 for the brine sand, 1.49 for the gas sand, a gap no measurement error can close. The soft brine sand and the gas sand share an impedance and can never share a velocity ratio, and the template puts that fact on a chart you can read at a glance. This is why a gas discovery is confirmed on , not on impedance alone.
What Calibration Cannot Freeze
Part 7 took the model families of Parts 5 and 6 and turned them into instruments. Empirical backbones supplied the missing shear and density logs; calibration pinned a physical model to the Ogbon-1 sand and read the misfit honestly; the template gathered that calibrated model into a chart that reads porosity and fluid from two attributes. Every one of those steps describes the rock as it is, at one moment, at one pressure, with one fluid in its pores. What none of them can freeze is the rock changing. Produce the reservoir and the pore pressure falls, the effective stress on the frame rises, and the very stiffness the calibration measured begins to move. Sweep it with water or gas and the saturation the template read starts to shift interval by interval. A calibrated model is a portrait, and the reservoir will not hold still. Part 8 takes up exactly this: how pressure and stress change the frame, how saturation changes with production, and how a time-lapse survey watches the rock move.
References
- Odegaard, E., & Avseth, P. (2004). Well log and seismic data analysis using rock physics templates. First Break, 22(10), 37-43.
- Avseth, P., Mukerji, T., & Mavko, G. (2005). Quantitative Seismic Interpretation. Cambridge University Press.