| Abstract |
The Geysers geothermal field, located in Lake, Sonoma, and Mendocino Counties, California is the largest developed geothermal system in the world since 1973. Electric power generation started at The Geysers in 1960 with a 12 MW (gross) plant (PG&E’s Unit 1). Injection of plant effluent, known as condensate, began in April 1969, into well Sulphur Bank 1, with the startup of PG&E’s Unit 4. Condensate injection alone replaces ~ 22% of mass steam withdrawal from the reservoir. This net loss of mass is due to the fact that geothermal power plants at The Geysers typically lose between 70 to 80% of produced mass to evaporation in the cooling towers. The total installed capacity in the field peaked in 1989 at 2,043 MW. As more and more power plants were built during the 1970s and 1980s and cumulative net mass withdrawals increased with time, reservoir pressures declined, eventually resulting in steam shortfalls and declining generation levels. In response to this decline, field operators made modifications to augment injection and distribute water throughout the reservoir. Based on both internal studies by Operators and other Agencies (such as the California Energy Commission), it was determined that injection of water from outside sources was the most effective method of managing the long-term decline in the resource. There are three significant injection augmentation programs: 1) Capture and injection of excess rain water, especially from the Big Sulphur Creek starting the early 1980s, 2) Injection of treated effluent from Lake County into the Southeast Geysers, starting in late 1997, and 3) Injection of treated effluent from communities located in central Sonoma County starting in 2002. Between 1969 and 2008, injectate has been distributed into 137 wells across the field and has replaced 39.5% of the mass of steam produced. The mass replacement rate has increased to an annual rate of ~85% in 2008. As this program of augmented injection has brought mass injected into near-parity with mass produced, the rate of reservoir pressure decline has been significantly reduced. Still, optimizing the distribution of augmented injection throughout the field and making adjustments to plant and pipeline facilities is a complicated process, with many interdependencies. To aid in ongoing optimization of the field, an integrated model has been developed by the Northern California Power Agency (NCPA) that combines reservoir simulation with mathematical modeling of the wellbores, the pipelines, and the power plants. This integrated model, funded in part by the California Energy Commission, has proven very useful for evaluating the most cost-effective improvements to the combination of wells and surface facilities, and to study the benefit of increasing the volume of augmented injection. This study goal was to determine the areal distribution and to quantify the recovery of injection derived steam over time. A two component option within the numerical model allows for the modeling of water as either in-situ or injection derived. Numerical modeling results based on the two-component water option indicate that recovery of injection derived steam (IDS) started soon after injection began in 1969 and continues today. On average, ~ 61% of steam production was injection derived in 2008 and certain areas of the field are actually producing 100% IDS. Also, the rate of steam production for 2010 is 50 percent higher than predicted by previous modeling efforts without significant augmented injection indicating significant benefit from increased water injection. Numerical modeling results also indicate that areal distribution of IDS recovery has gradually increased as injection has become more widespread. Injection recovery is highest within three distinct areas that, in general, correspond to the three low-pressure areas known as the Old Geysers’ Area, the Central Area and the Southeast Geysers Area. Injection is quantified for these three areas of The Geysers. |