This paper presents the initial results of a survey of the occurrence and characteristics of geopressured fluid resources in California using the publicly-available database involving more than 150,000 oil and gas wells drilled in the State. Of the 975 documented on-shore oil and gas pools studied, about 42% were identified as potentially geopressured. Geothermal gradients in California oil and gas fields lie within the normal range of 1°F to 2°F per 100 feet. Except for the Los Angeles Basin, there was no evidence of higher temperatures or temperature gradients in geopressured pools. The porosity of geopressured pools shows the same normal distribution as for normal pressured pools, with a mode in the range of 20 to 25%. The salinity distribution of both the geopressured and normal pressured pools appear to be bimodal, each with two peak ranges of 0 to 10,000 and 25,000 to 30,000 ppm.

The publicly available database on oil and gas fields in California provides a significant and consistent source of information which can be used to evaluate geopressure. A total of 410 pools have pressure gradients exceeding 0.45 psi/foot; these are considered to be potentially geopressured. At least 70 of these have pressures distinctly higher than predicted by the regional hydrostatic gradient, and 8 pools are super pressured.

The purposes of this paper are to review the stratigraphic and structural models which have been developed for The Geysers from surface mapping, propose a model which is the most compatible with drilling results and, based on the preferred model, show how stratigraphy and structure control the occurrence of steam.

This paper presents the results of a continuing study of geopressured resources in California. Three aspects of geopressured resources were examined in this study: the identification of geopressured zones in wells; quantification of the excess pressure from well logs; and the quantity of dissolved methane in California geopressured fluids.

A numerical simulation model of The Geysers geothermal field, California, has been developed using reservoir and production data provided by UNOCAL, Calpine, NCPA and CCPA. The model was originally developed by UNOCAL and was based primarily on data from the Unocal-NEC-Thermal (U-N-T) lease areas; the purpose of this study was to extend the model by incorporating data from other field operators and to use the re-calibrated model to forecast future production trends.

Geothermal power generation and mineral extraction from geothermal brines are affected by chemical processes within the reservoir. Until recently, numerical simulation technology for geothermal systems could not handle most chemical processes, except for tracking total salinity, one or two non-condensable gases, and non-reactive tracers. The Lawrence Berkeley National Laboratory (LBNL) has developed an enhanced version of their geothermal reservoir simulation software TOUGH2, developed with funding from the U.S. Department of Energy. This highly innovative software (TOUGHREACT) includes comprehensive chemical interactions between liquid, gaseous and solid phases that are coupled to the modeling of solute transport and subsurface multiphase fluid and heat flow.

The Department of Energy's EGS Strategic Plan anticipates that EGS experimentation in the United States will be underway by 2004 in areas within or adjaeent to commerciallydeveloped hydrothermal fields, and that an EGS demonstration plant will begin operating in 2008. Criteria for selecting sites for EGS experimentation focus on enhancing energy recovery at producing fields while advancing the EGS knowledge base incrementally towards a demonstration project. With input from field operators, basic characteristics and information on the type of EGS work that may be undertaken are presented for 15 producing fields and 2 unexploited fields. Six producing fields meet 90 - 100% of the site selection criteria and 9 meet 60 - 70%. The use of EGS techniques to supply an existing facility has the advantages of low cost, support from the geothermal industry and demonstration of applicability to a variety of conversion technologies. This approach seeks to reduce EGS risk and uncertainty, promoting the transition from research to commercial evelopment.

This paper summarizes the results of a recent study (the Facilities Improvement Report) performed with funding by the Public Interest Energy Research (PIER) program of the California Energy Commission (CEC). The Facilities Improvement Report describes potential improvements to 45 existing power plants in 7 currently producing geothermal fields in California. The improvements are of two general types: improvements in resource supply and improvements in surface facilities. To resolve inconsistencies in reported plant capacities, distinctions are made between original capacity, electromechanical capacity, 2005 capacity (which takes into account resource limitations), and actual annual average power. The total electro-mechanical capacity of the geothermal plants in California is about 2,650 MW-gross, and the 2005 capacity is about 1,850 MW-gross (1,600 MW-net).

Advances in binary-cycle power and submersible pump technologies over the past two decades have made electric power generation from geothermal fields in the moderate temperature range (100° to 180°C) convincingly commercial. For geothermal water in this temperature range, binary-cycle is more efficient for power conversion than flash-cycle and pumping of wells is more efficient than self flowing. The lower temperature limit of 100°C is imposed by the limits of binary-cycle technology and the upper limit of 180°C is imposed by the limits of pump technology commercially available today. This paper is a case study of optimization of net power generation from such a field at Raft River, in the State of Idaho, United States.

The similarities and differences ill reservoir engineering in the geothermal and petroleum industries are not familiar to many. This unfamiliarity frequently leads to aberrant perception of the risks and rewards of geothermal development in the minds of developers and financiers who are accustomed to the petroleum industry but are new to geothermal. This paper is a comparative survey of the state-of-the-art of reservoir engineering in the two industries.