Southwest Research Institute J.O. Parra and C.L. Hackert. Southwest Research Institute P.C. Xu, Datatrends Research H.A. Collier,Collier Consulting M. Jervis, TomoSeis Acoustic and CT Images to Characterize Vuggy Carbonates In South Florida Aquifers: From the Pore to the Field Scales

Based on standard core measurements and image analyses, we determined that the carbonate rock from the Ocala Limestone, South Florida, is formed by moldic, vuggy, intergranular, intraparticle and intercrystalline pores. Thin section analysis provided information on the matrix porosity, and X-ray computed tomography (CT) provided information on the vuggy porosity. We constructed vuggy porosity models to calculate synthetic ultrasonic responses based on the finite difference method, and we compared the synthetic with the ultrasonic data. The results explained velocity changes associated with vugs in the carbonate rock at the core scale. We cross plotted ultrasonic velocities with permeability based on whole core measurements for different flow units of the carbonate aquifer and found that velocity correlates well with permeability for each carbonate flow unit. To determine whether we could assess the degree of connectivity between vugs or between the matrix and the vugs based on acoustic data, we calculated the squirt-flow lengths using a poroelastic model. The results showed a good correlation between squirt-flow lengths and the increase in permeability for each flow unit. Summary

Summary, con’t To predict relations between velocities and permeability at the borehole scale, we determined the sonic velocities from full waveform monopole data and permeability and porosity from NMR well log data. Saturated and desaturated NMR core plug measurements aid in estimates of the irreducible water in the rock and the variable T 2 cut-offs for the NMR well log calibration. The measurements established empirical equations to extract permeability from NMR well logs. In addition, different empirical relations were determined between the sonic P-wave velocities and the NMR-derived permeability and porosity logs. Based on crosswell seismic measurements conducted between two wells in the formation, we determined velocity and reflection images at the field scale. Both images correlate well with the lithology. Empirical equations developed at the borehole scale were applied to predict permeability and porosity images from velocity tomography data recorded between the two wells. The permeability images provided information on three flow units; in particular, a high-permeability zone characterized by interconnected vugs. This is consistent with the hydrological results of high water production being monitored in the interwell region.

Figure 1. A 3D view of an X-ray CT scan image of the diameter of core 41, showing an interconnected vug system typical in carbonate rock from the Ocala Limestone Formation, Palm Beach, South Florida. This core is from a limestone with wackestone texture taken from a depth of 1138 feet in the Ocala, an Upper Eocene formation. The high permeability of the sample is controlled by interconnected vugs, and a stochastic analysis of the CT image predicts two length scales: 2.2 and 17 mm in the z-direction, and 2.4 and 7.2 mm in the xy-plane.

Figure 2. (a) Calculated density from the X-ray CT data for a slice from core 41. Data plotted is dry density in g/cc. (b) A photograph of the end of core 41. This core has extensive cavities that are captured by the CT images.

Figure 3. (a) 2D density images of cores 7 and 41 show small separated and large interconnected vugs, respectively. Permeability of core 7, also from the Ocala Formation, is 7 millidarcies; permeability of core 41 is > 4000 millidarcies.

Figure 3. In (b) and (c), the black line is the waveform for a homogeneous saturated core, the green line is the waveform for a heterogeneous saturated core, and the red line is the waveform for a heterogeneous dry core. (b) The synthetic waveform for core 7 is almost identical to the waveform of a uniform, equivalent core, although reduced in amplitude. Core 7 has few cavities and is much more uniform than core 41. (c) The waveforms associated with core 41 reflect the heterogeneity of the carbonate sample.

Figure 4. Cross plots of 24 measured and calculated P-wave velocities of whole core samples versus permeability. The curves represent six flow units. The numbers in the plot are squirt-flow lengths in millimeters. Each curve represents a flow zone indicator (FZI) in terms of porosity and permeability. The curves show that P-wave velocity decreases as permeability increases. Also, as permeability increases, squirt-flow length increases as well, i.e., a large permeability correlates with large flow lengths. The plots suggest that differences between observed and calculated velocities are due to the presence of vuggy porosity in the cores. We expect that the increase in permeability with squirt-flow length reflects the presence of connected vugs.

Figure 5 Comparison of NMR core signatures with OM thin sections for cores 4, 6, 21, 32 and 49. The NMR plots contain the T2 relaxation distributions for both desaturated and fully saturated samples overlain on one plot. The NMR measurements were made for small plugs having different permeabilities and porosities than the whole cores. Core #4 Core #6 Core #21 Core #32 Core #49

Core #4 is a limestone of grainstone texture with intergranular pores and vugs. The saturated T2 distribution exhibits two pore size peaks at 40 ms and 1000 ms. The photomicrograph show localized vugs that are separated. The T2 distribution reflects the presence of the separate vugs (at 1000 ms) and the intergranualar pore size (40 ms). The plug permeability is 158 md, and the whole core permeability is 1235 md. A heterogeneous sample.

Core #6 is a limestone of grainstone texture with no vugs and with poorly interconnected moldic pores. The T2 exhibits a peak at 12ms, which corresponds to the matrix porosity of the grainstone sample. The permeability of this plug is close to zero, and the permeability of the whole core is 0.7 md. A homogenous sample.

Core #21 is a sandstone with an average grain size of mm. Intergranular pores (igp) with dolomite cement dominate the pore system. The T2 distribution peak at 12 ms reflects the matrix porosity of the sample. A low permeability, homogenous sample (average permeability of hte plug is 31 md and of the whole core is 86 md).

Core #32 is a limestone of poorly-preserved packstone texture. Moldic and intraparticle pores can be identified. The T2 distribution has a peak at about 400 ms, which corresponds to large pore size (vuggy porosity). The sample is heterogeneous. The plug permeability is 220 md, and the whole core permeability is 1805 md.

Core #49 is limestone of packstone texture. The pore system compromises common intraparticle and intergranular pores, with moderate amounts of intercrystalline pores. The T2 peak is at 80 ms, which corresponds to moderate pore sizes. The permeability of hte plug is 13 md, and the permeability of the whole core is 98 md. The sample is relatively homogeneous.

Figure 6 NMR measurements performed on 18 saturated and desaturated core samples provided the information to produce T2 relaxation cut-off times (T2c) for use in log calibration. Different relaxation rates are observed in the data associated with the different rock groups in the well, which provides the appropriate bound-volume index (BVI) for each core plug. Models based on flow zone indicator (FZI), NMR derived porosity, and the BVI parameter provide the relationship to calculate permeability at the core scale.

Figure 7. Four T2c, selected from cores and the permeability equation given in Figure 6, provide the calibration parameters to produce NMR-derived permeability in the middle track above. Here the far right plot shows the T2 distribution in the color scale and overlain red lines. The white log is the median T2 value, which is used with porosity to discriminate among relaxivity units. The thick red line is the variable T2 cut-off. For comparison, this figure shows the lithology, porosity and the Vp and Vs logs.

Figure 8. The Velocity Image, the sonic log for well PBF-10, and gamma ray logs for both wells are plotted in measured depth from ground level (GL) of well PBF-10. The data available for quality control includes sonic and density logs in well PBF-10 and gamma ray and induction logs in both wells. Gamma ray and induction logs show that the structure is almost one dimensional, with vertical but no lateral variations. A sonic log from PBF-13 shows considerable disagreement with that of PBF-10, so it was not used as a quality control aid. The velocity image shows good agreement with trends in the sonic and density log variations with depth. Vertical velocity changes are fairly well resolved and correlate with the sonic and density logs as well as formation changes. Since there are no receiver locations below 1105 feet in well PBF- 10, the velocities below this interval are constrained only by the travel time picks from source locations below 1100 feet in well PBF-13.

Figure 9. Location of crosswell seismic experiments at the western Hillsboro Aquifer Storage Recovery (ASR) site near Boca Raton, Florida. One profile was acquired between wells PBF10 and PBF13. At the surface, the well heads are approximately 333 feet apart.

Figure 10. The figure shows the wiggle traces superimposed over the velocity tomogram. The reflection image, velocity image, sonic log, and tomographic velocity are plotted in measured depth referenced from ground level for well PBF- 10 about 10 feet from the well (no velocity logs are available for well PBF-13). Actual reflection coverage below the total depth for each well is limited by well spacing as well as the deepest source and receiver locations in each well. The resolution of the reflection data for this profile is very good (to about 2 feet vertical resolution). The reflection images show good agreement with the acoustic and density log variations with depth and hence with the synthetic seismogram. Vertical velocity variations agree very well with the reflection events, with little or no lateral structural variations. Lateral reflection variations probably result from imperfect amplitude corrections applied to address large amplitude variations in the data due to differences in well casings between the wells. In addition, there was no access to receiver locations below 1110 feet due to an obstruction in the well. This limited access further reduced reflection coverage in the deeper part of the section and thus the amount of reflection data available for mapping.

Figure 11. Since there is a good correlation between P-wave velocity and permeability at the core scale, as shown in Figure 4, we correlate the Vp with the NMR-derived permeability and with the total porosity log. The computed relations are shown in Figure 11. The figure shows nonlinear relationships between the Vp and the permeability in the permeable Ocala carbonates ( ft) and in the Arcadia Formation at depth intervals of ft and ft. Figure 11 also shows linear relationships between Vp and the total porosity in both regions.

Figure 12. The comparison of the permeability log with the lithology shows a very low permeability in the sandstone, and a moderated permeability low in the chalky carbonate. The high permeability values correlate with the carbonate with interparticle porosity, which is consistent with the core data. The permeability and porosity equations are applied to the velocity pixels to produce the permeability and porosity images. Here we compare the lithology with the velocity, porosity and permeability images between ft. A permeable zone between ft in the interwell region of wells PBF10 and PBF13 is developed at well PBF10 and decreases toward well PBF13.

Ultrasonic responses based on CT models is a practical technique to determine the heterogeneous conditions of the rock fabric and the applicability of acoustics to describe the aquifer formation. The results of the analysis of the observed and calculated ultrasonic responses leads to correlations of P-wave velocity and permeability at the core scale. This suggests that the velocity can be related to permeability at the borehole and interwell scales. The excellent correlations between P-wave velocity and porosity and P-wave velocity and permeability at the borehole scale demonstrate that fluid flow effects can indeed be related to velocity tomography data. Thus, the velocity images at the interwell scale were converted to permeability and porosity distributions between wells PBF10 and PBF13. The permeability images delineate three flow units in the 330-foot interwell region. The upper two flow units are thin continuous connected beds, less than or equal to about 10 feet thick. The deeper flow unit is approximately 60 feet thick and more heterogeneous than the upper two flow units. The velocity, porosity and permeability images correlate with the gamma ray and velocity logs. Conclusion

Comparisons of the plug and whole core permeability measurements imply the presence of permeability heterogeneity at these two scales. This condition suggests that NMR whole core measurements will provide more representative permeability data than that from plugs. Thin section and core analyses show that the NMR well log-derived permeability represents the matrix permeability. Although NMR well log calibration based on plugs has apparently underestimated the true permeability of the vuggy formation, the relative permeability correlates with the lithology in the region between 1000 and 1200 feet. This study demonstrated that acoustic and CT image techniques, supported by core analyses and NMR measurements, can be used to characterize vuggy carbonate formations at the pore and borehole scales. The final results demonstrate that integration of well logs with tomography and reflection images is a practical approach for mapping flow units in the carbonate aquifer of the Ocala Limestone Formation in Palm Beach County, South Florida. In particular, the crosswell seismic data provided high-resolution images, beyond the resolution of surface seismic data, that are useful in characterizing the formations in the region of wells PBF10 and PBF13. Conclusion, con’t.

Acknowledgements This work was supported by Contract DE-AC26-99BC15203 from the U.S. Department of Energy, National Petroleum Technology Office. Assistance of P. Halder (DOE) is gratefully acknowledged.