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The AAPG/Datapages Combined Publications Database

AAPG Bulletin


AAPG Bulletin, V. 87, No. 2 (February 2003), P. 295-311.

Copyright ©2003. The American Association of Petroleum Geologists. All rights reserved.

Improved interpretation of wireline pressure data

Alton Brown1

1Consultant, 1603 Waterview Drive, Richardson, Texas, 75080; email: [email protected]


Alton Brown worked as a research geologist at ARCO's Research Center in Plano, Texas, from 1980 until ARCO's merger with BP Amoco. Since then, he has been an independent consultant. Research interests include petroleum migration, carbonate sedimentology and diagenesis, basin analysis, and gas geochemistry.


This work was completed at the ARCO Research Center in Plano, Texas. I thank ARCO and VASTAR for permission to release this study. ARCO and VASTAR have subsequently become part of BP Amoco, which is also acknowledged for its cooperation. AGIP and Petroecuador are gratefully acknowledged for releasing Villano field pressure data. Paul Willette, Lee Russell, and Jim Twyman reviewed earlier drafts of the manuscript. AAPG reviewers Jim Puckette and Alain Huc are also acknowledged. David Novak, Andy Harper, Paul Willette, and Herb Vickers helped with the information-release process. A. F. Veneruso kindly provided unpublished updates to his pressure-gauge response model. Reference to any tool or gauge model or manufacturer is not an endorsement or recommendation for that product.


Modern wireline pressure data can have resolution and reproducibility sufficient to detect small fluid-density changes and pressure barriers, yet these features are commonly overlooked on conventional pressure-depth plots. The large pressure variation caused by weight of subsurface fluids hides these subtle features. Excess pressure is the pressure left after subtracting the weight of a fluid from the total pressure. This concept is applied to wireline pressure data to remove effects of weight and emphasize subtle pressure differences caused by density variations and pressure barriers. Fluid-density changes of 0.02 g/cm3 or less can be resolved, and within-well pressure barriers in the order of 5 kPa (0.7 psi) can be detected. Using good-quality data, effects of reservoir capillary-displacement pressure can be detected by offset of the free-water level from the petroleum-water contact. This effect can be used to estimate reservoir wettability. Subsurface fluid-density measurements can also be used to evaluate oil or gas quality on a bed-by-bed scale in traps having variable oil or gas composition, to detect compartmentalization by small petroleum density differences, to verify quality of samples for PVT (pressure, volume, temperature) analysis, and estimate salinity or temperature of unsampled water zones.

Data quality limits barrier and fluid-contact resolution; thus, quality control is essential. Pressure measurement errors on the 3-kPa (0.5-psi) scale can be detected from behavior of the buildup pressure. Tests having the potential for small amounts of supercharge are identified from the overbalance and formation mobility. Examples illustrate identification of free-water levels and fluid contacts, fluid identification, supercharge identification, and water-zone compartmentalization.

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