Accidental spills of condensate, cooling water or geothermal brine outside of the containment areas (e.g., along pipeline routes) would be handled as if it were storm runoff (i.e., directed to drainage ditches where it is expected to be absorbed by the porous soils.

Spill containment areas would include, but not be limited to, the following areas: Plant transformers; Turbine lube oil system; Liquid reduction skid and chemical storage area; Secondary abatement chemical area (if secondary abatement is needed); Cooling water chemical treatment area; Diesel engine fire pump area; Diesel fuel storage tank; and Well pad chemical injection system

Spill control provisions would consist of berming the areas subject to spills to contain 150 percent of the potential maximum spill volume and providing the bermed area with a sump for a temporary sump pump. Inside the sump would be a water drain-off valve that would normally be closed. Any uncontaminated rainwater could be released by opening this valve. Uncontaminated rainwater from spill containment areas inside the fenced plant area would flow to the plant water storage pond. Uncontaminated rainwater from the well pad chemical injection system spill containment would flow to the well pad sump. Any spills or potentially contaminated runoff occurring within the spill areas would either be removed by a licensed hazardous waste hauler, pumped into a tanker truck for offsite disposal at an appropriate location, or pumped to an injection well for disposal.

2.2.3.7 Well Abandonment and Wellfield Site Restoration

Should a production test well be drilled that is not suitable for conversion to an injection or observation well, and therefore proposed for abandonment, abandonment would be accomplished in accordance with the GRO Orders, stipulations of the BLM and USFS, and all other applicable permits or regulations. During a typical well abandonment the hole would be plugged back with cement. The well casing would be cut off below ground surface, capped with a welded plate, the cellar back-filled, and the site restored to USFS specifications.

Prior to closing the solids disposal sump at each well pad, the liquid contents of the sump would be removed and the dry sump contents would be sampled and analyzed to confirm that the material was nonhazardous. If the sump contents were determined to be hazardous, or otherwise determined to be unacceptable for burial in place, the sump contents would be removed and transported to an off-site disposal facility authorized to accept the waste. Subsequently, the sump would be backfilled and graded to contour.

The lined fluid sump would be emptied of any residual fluid and destroyed. The sump liner would be either removed entirely, or the liner would be cut to below ground surface, punctured to allow water to permeate through it, and backfilled with native soil. The entire pad would be regraded to approximate natural contour and scarified to promote revegetation.

Wellfield roads that are no longer needed would be closed or reclaimed as directed by the USFS. If a road is to be closed, it would be abandoned as directed by the USFS. Roads that are reclaimed would be scarified, culverts would be removed, water bars would be installed to control drainage, surfaces would be replanted with native tree species, and the road would be blocked with an earthen barrier or down and dead woody material.

2.2.3.8 Production and Injection Fluid Pipelines

The high and low pressure (HP and LP) steam and/or brine (for injection) cross-country piping from each well pad to the power plant would utilize common pipe support structures (see Figure 2.2.8). The pipe support structures would keep the pipeline off of the ground surface at a height of about 3 feet on level terrain. The height of the pipeline above the ground surface would vary up to about 6 feet, as necessary to span topographic highs and lows along the pipeline route. All pipelines and well pad equipment would be wrapped with 3 inches of insulation. Figure 2.2.9 shows a typical geothermal pipeline corridor layout. Thermal expansion would be provided for by a series of guided pipe supports, expansion loops and anchor pipe supports. For the most part, the expansion loops would be horizontal as illustrated on Figure 2.2.9. However, vertical expansion loops could be desirable at specific locations such as at the power plant pad (vertical, upward) or for particular road crossings (vertical, underground). The injection cross-country piping would utilize the same pipe support structures as the steam piping wherever practical.

The gathering and injection system pipeline corridor would be routed through existing cleared areas and along existing roads and logging trails, to the extent practical (see Figure 2.2.10). In areas where logging roads do not exist along the pipeline corridors, 25-foot wide maintenance roads would be located parallel to the pipelines (see Figure 2.2.3). Construction corridors, including the maintenance roads, would be confined to less than 120 feet in width. After construction, the corridor would be allowed to revegetate, where practical. Approximately 25 percent of the pipeline corridor area would be in continuing operational use as pipeline piers, footing and access roads. Figure 2.2.9 also illustrates the typical layout of the proposed cross-country pipeline corridors.

2.2.3.8.1 Production Pipeline Equipment

A typical production wellhead configuration is shown in Figure 2.2.11. Downstream of each production wellhead would be a motor-operated master control valve. This valve could be operated remotely by the power plant operator or locally at the wellhead. This valve would be a high performance control valve that could be used to continually regulate or trim production rates to the power plant. This valve would be capable of shutting-in the well under preprogrammed and emergency shut-in conditions. Upstream of the motor-operated master control valve would be a manually-operated valve that would control the flow of fluids to the wellhead silencer. A bleed line with an isolation valve would be piped from the wellhead to the pipeline and silencer. The wellhead silencers would be used during start-up in order to warm-up the well prior to diverting the geothermal fluid into the production pipeline. Liquid from the silencer would drain into the nearest sump. Typical production well control facilities are schematically shown in Figure 2.2.12.

Downstream of the master motor control valve for each well would be a high-pressure (HP) steam separator that would be located on a well pad and interconnected to several wells. Several high-pressure separators would be spaced within the wellfield with two-phase geothermal fluid feeder production pipelines constructed from the production wells to the HP separators. The geothermal fluid would be allowed to partially flash in the HP separators. Steam from the HP separators would be interconnected to a common main HP steam pipeline to the power plant. Liquid from the HP separators would be directed via feeder pipelines to a centrally located low-pressure (LP) steam separator where the remaining LP steam would be flashed from the geothermal fluid, separated from the heat-spent liquid and transmitted to the power plant via LP steam pipelines.

The spent geothermal liquid fraction from the LP separator would be routed to one or more injection wells. Several wells would be expected to be interconnected to a common HP separator. Downstream of the HP separator would be motor control valves that could be used to regulate production from the interconnected wells.

2.2.3.8.2 Injection Pipeline Equipment

Each injection well would be equipped with manually-operated wellhead controls and manually-operated stacked master control valves (see Figure 2.2.13). Upstream of these valves, hot geothermal fluid injection wells would be equipped with a regulating valve that would be the primary control valve that would regulate the amount of fluid being injected into each well (see Figure 2.2.14). Noncondensable gas injection could be utilized as a system back-up for the gas treatment program. If noncondensable gas would be injected, it would either be mixed with the return fluids from the power plant or mixed at the injection well. The noncondensable gas piping system would have separate isolation and regulation valves from the return fluid pipelines (see Section 2.2.4.5.5).

2.2.3.9 Freshwater Wells and Pipelines

Water for drilling/construction activity would either be trucked or piped from existing wells in the Arnica Sink currently used by CEGC and Modoc National Forest. There are two water wells, north well and south well, in the Arnica Sink area originally constructed for geothermal operations. The south well is owned by CEGC. This well would be the primary supply well for the project. The north well was also constructed by geothermal developers and was dedicated to the USFS for general uses. Both wells could be used during construction. If piping water to well sites is determined to be practical, temporary above-ground pipelines would be laid along existing roads or other appropriate routes from the source to the drill site. Example quantities of water use would be: (a) temperature gradient well operations generally require 3,000 to 5,000 gallons of water per day; (b) exploratory and production test wells would require generally 9,000 gallons of water per day and up to 40,000 gallons per day may be lost in circulation zones. Produced fluids from successful wells would be used to reduce the need for other drilling water sources.

A pipeline would also be constructed to transport groundwater to the power plant site. The pipeline would be buried beneath the frost zone and would generally follow a former logging road to the power plant site (see Figure 2.2.10). Water from the shallow groundwater wells would be used to initially charge the power plant cooling towers, but makeup water to replace evaporative cooling tower losses would come from geothermal production fluid steam condensate (see Section 2.2.4.5.2).

2.2.4 Power Plant

2.2.4.1 Power Plant Site

The proposed power plant would be located in Section 18, T43N, R4E (see Figure 2.2.4). Commercial operation of the power plant to generate electricity represents the second phase (operation) of the Proposed Action.

The power plant site and adjacent laydown area would encompass a total area of approximately 15 acres (i.e., about 580’ x 1,140’) and would include the power plant pad, an equipment laydown area, water storage ponds, contingency cut and fill areas, and a 50-foot wide fire break around the surface facilities (see Figure 2.2.15). The site would be generally rectangular and would be cleared of vegetation and graded to balance cut and fill requirements. However, the Proposed Action also assumes construction of well pad 52-18 adjacent to the power plant facilities. The location of this well pad is superimposed over the equipment laydown area to minimize the total surface disturbance required for the well pad and equipment laydown area construction.

Based on current knowledge of the geothermal resource conditions in the Project wellfield area, the power plant would be constructed using double-flash technology. The proposed power plant would be capable of generating 48 MW (gross) electrical power, with 45 MW (net) deliverable to the BPA inter-tie point near Tionesta, California.

The power plant would be engineered and constructed in accordance with utility standards. The Project would utilize commercially available geothermal technologies and equipment successfully utilized at other project sites. The projected annual capacity factor would be 90 percent or greater of the electrical power generation capacity of the power plant.

2.2.4.2 Process Flow Projections

Figure 2.2.16 is a schematic flow diagram showing the fluid flow paths from the production wells through the power plant and heat rejection (cooling) system to the injection wells. The accompanying tabulated material balance (see Table 2.2.2) identifies the projected fluid mass flows, temperatures and pressures throughout the power cycle based on the currently projected geothermal resource conditions (see Table 2.2.3).

2.2.4.3 Proposed Facilities

Table 2.2.4 lists the major power generation equipment/systems expected to be used for the proposed project and includes a description or general specification for that equipment/system. A plot plan of the proposed power plant site showing the major power plant structures and exterior equipment is provided as Figure 2.2.15. Figure 2.2.17 shows the general elevations of the building, cooling tower, and other prominent power plant facilities. The following subsections describe the general process and equipment proposed for this project. The locations of the facilities within the proposed power plant site, including the building, cooling tower, water storage pads, rock boxes, switch gear, and construction laydown area are shown on Figure 2.2.15.

2.2.4.4 Communications

A dedicated communications system would be installed at the existing Red Shale Butte communications site located at the summit of Red Shale Butte. The communications site includes the existing USFS communications center, a USGS communications pole and other radio towers. The site has adequate room to install a new Project relay without additional surface disturbance. The Project equipment would have radio frequencies that do not interfere with existing users. A Communications Plan describing the equipment and frequency would be prepared by CEGC and submitted to the USFS for review and approval prior to installation.