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The Raft River geothermal field is the site of an innovative Department of Energy Enhanced Geothermal System (EGS) project to determine the viability of using combined thermal and hydraulic stimulation techniques to improve energy production. Well RRG-9 is currently undergoing a stimulation program using injectate from the US Geothermal Raft River Power Plant and cold water from a cooling tower make-up water well. The stimulation began on 13 June 2013 with injection from the power plant at a temperature of about 39 °C and a pressure of 275 psig. Next, two positive displacement plunger type pumps were used to increase the injection pressure and flow rate for about one month. The highest rate achieved was 258 gpm at a pressure of 741 psig. During this time, fluid from the cooler water well was injected for about 2 weeks at various pressures. Then, the pumps were removed and plant injection resumed on 25 September. Plant injection will continue until the spring of 2014, when a high pressure hydraulic stimulation will be conducted. A series of seismic monitoring stations deployed around the well are providing data on seismic events occurring at the site. Over the past year, 51 microseismic events have been recorded, all less than Magnitude 1.
During injection, several diagnostic tests were conducted to gain a better understanding of the well and reservoir. A step-rate test was performed on 22 August to measure the in-situ stress and aid in modeling in-situ fractures. A tracer was injected into the well on 9 September. No tracer was detected in adjacent production wells after several months. A second borehole televiewer survey was conducted for comparison to pre-stimulation images. A third borehole televiewer survey is planned after the high pressure stimulation.
Injection test data is evaluated in real time. A modified Hall plot analysis indicates the effective permeability is increasing. The injectivity index supports the results of the modified Hall plot analysis. As the thermal stimulation has continued, the injectivity index has consistently followed an upward trend from 0.1 gpm/psi to 0.53 gpm/psi.
In August 2012, the City of Akutan completed an exploration program to further characterize the geothermal resource and to select drilling targets in the geothermal resource area on Akutan Island near Hot Springs Bay Valley. The exploration program included geologic mapping, a magnetotelluric (MT) survey, and a gravity survey. The program built on previous exploration, which included an MT survey, a geologic reconnaissance field study, soil and soil gas geochemical surveys, a satellite remote sensing study, a review of existing hot springs geochemistry data, drilling of two temperature gradient wells, and development of a conceptual model. The culmination of the 2012 work was to use 3D visualization of the data to advance the conceptual model and select deep drilling targets. Access requirements were taken into account in selection of the surface locations; underground targets will be reached using directional drilling.
The Raft River geothermal field, located in Cassia County in southwestern Idaho, is the site of a Department of Energy Enhanced Geothermal System project. U.S. Geothermal, Inc. currently produces about 11 MWe from Precambrian metamorphic rocks. These lie beneath ~5,000 ft of Quaternary and Tertiary volcaniclastic and volcanic deposits. Maximum temperatures range from 271o F to 300o F.
Well RRG-9 ST1, the well targeted for stimulation is located approximately 1 mile south of the main bore field. The open hole section of the well, from 5,551 to 5,900 ft MD, consists of Precambrian Elba Quartzite, the stimulation target, granite and minor diabase. Prior to setting the casing acoustic, gamma ray, and density logs were run. After completing the well, a step rate/step down test was conducted. The maximum injection rate achieved was 18 bpm at a wellhead pressure of 1,150 psig.
A borehole televiewer run in the open hole section showed evidence of more than eighty fractures. The majority of these fractures trend from N20⁰W to N20oE and dip from 40o to 60oW. Permeable fractures were encountered in the Elba Quartzite at 5,640-5,660 ft MD. Analysis of the injection test indicates that the minimum in-situ principal stress in this zone is 3,050-3,200 psi, corresponding to a fracture gradient of 0.59-0.62 psi/ft. A discrete fracture network model was developed using
measured and inferred fracture orientations, distributions and dimensions.
A three-phase stimulation program is proposed for RRG-9 ST-1. During the first two stages, water at 140oF, and later 40oF, will be injected to pre-condition and thermally fracture the reservoir. The third stage will consist of a high rate, large volume conventional hydraulic stimulation.
The Salton Sea Geothermal Field is one of the largest geothermal resources in the world. Recent changes in leasehold positions, changes in lake management due to Colorado River water transfers, a transition to renewable energy resources and the clean energy initiatives of California, have prompted renewed interest in development of the field for baseload power generation. The receding shoreline of the Salton Sea is now exposing areas previously inaccessible, and exposing large tracts of land for development. Since the last conceptual model and resource estimate for the Salton Sea Geothermal Field was published in 2002, significant additional data has become available, including publicly available seismic surveys over the resource area, experiences of developers and operators at the field, and recent research related to seismicity and tectonics of Southern California. In this study, we integrate these data sets in an updated conceptual model and a revised estimate of the power generation potential of the field. The result is a model that can serve as the basis for further exploration and development in the field. Our study increases the power generation potential of the field to 2950 MWe.
Drilling cost and risk is the greatest impediment to global geothermal development. In the early 1990s, the use of lower cost slim holes was introduced for geothermal exploration. Although the industry was slow to adopt this method, slim holes are now commonly drilled and tested to evaluate geothermal resource potential. With the advancement of novel drilling techniques and miniaturized instrumentation, microbore exploration wells can reduce drilling cost and risk in EGS and conventional geothermal development.
Of critical importance in the use of a surrogate slim hole or microbore to assess resource capability is the assumption that test results can be accurately scaled to larger, more expensive production bores to be completed after successful discovery of a resource. The accuracy of this scaling varies with test bore diameter, resource conditions and the degree of scale-up to larger bores. Geothermal exploration wells are typically evaluated by discharging the well to surface equipment at atmospheric pressure to measure flow rate, enthalpy, and fluid composition. Reservoir characteristics are further evaluated by conducting injection tests, step-rate production tests, and pressure recovery measurements. However, low temperature resources or small diameter bores are often incapable of continuous, unassisted flow. In such cases, flow to the surface can sometimes be induced, or temporarily maintained, by air- or nitrogen-lift, or pumping, but these methods add significantly to the cost and complexity of the test operation. In addition, atmospheric flow tests require relatively large liquid storage facilities (sumps or tanks) or a nearby injection well, and test duration may be limited due to steam and gas emission considerations, hazardous liquid composition, or water disposal restrictions.
Using innovative test methods, slim hole and microbore resource evaluation can be completed using a drill stem test. This method eliminates errors associated with surface flow tests, and requires substantially less infrastructure and reduce the time required for resource evaluation.
The Momotombo geothermal field has been in development since the 1960s, with most drilling completed in the 1970s, and was on line with its first 35 MWg geothermal flash power plant in September 1983. The field has had several operators in its operational history, with installed capacities of 35-77 MWg and generation from 8-69 MWe. Generation was 22.5 MWe at the time of the study.
Momotombo Power Company recently became the owner/operator of the concession of the Momotombo field, and a complete assessment of wellfield performance and well conditions was initiated to assess the feasibility of increasing generation to 42 MWg. This review included a numerical simulation of the field, which also requires a strong geologic conceptual model. Previous reservoir models focused on the producing field, but did not account for sources of pressure support to several wells from outside the core of the field area. A new conceptual model was developed, and a numerical simulation of the field was used to validate and adjust assumptions in the conceptual model, resulting in a very robust conceptual and numerical model.
The resulting, integrated model suggests the existence of an area of primary recharge and upwelling that is currently undeveloped and partially connected to the existing development, providing pressure and heat support to wells closest to that area. There appear to be significant developable reserves in this area, and additional exploration is recommended to determine the extent and possible secondary outflow areas.
Within the history matching process of the numerical model, two downhole well bore failures were identified. Candidates for well remediation have been identified to increase generation from existing wells to increase generation to 42 MWe. Areas for expansion were revealed to better utilize installed capacity, and a plan to increase generation through the 15-year contract life will be implemented.
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