A leading geothermal project developer acquired acreage in North America that was near numerous operating geothermal projects. Moreover, indications of an underlying geothermal system had been discovered during mineral exploration more than a decade ago, when shallow wells (200-ft to 300-ft deep) encountered temperatures >200 degF. However, there was no surface manifestation of geothermal activity, such as hot springs or fumaroles, in the acquired area—it was a blind prospect.
Over the next 5 years, the developer conducted an extensive exploration campaign that included in-depth reservoir evaluation, drilling for cores, and drilling several deep, full-size commercial wells. A 29-day production-injection test in the full-size wells demonstrated high flow capacities and a stable production temperature. Preliminary reservoir modeling supported the proposed development of a power plant with a capacity of 15–16 MW for a 20-year project. As a result, commercial drilling operations continued, and all necessary field requirements were completed for a projected plant startup by the end of the following year. During negotiations for a 20-year PPA, however, the buyer requested verification of the sustainable resource capacity by independent third-party experts. Based on an extensive global track record and proven excellence, GeothermEx services were selected for the data review.
From the suite of geotechnical data provided by the developer, the focus was on the following elements:
This review was used to estimate resource characteristics for a probabilistic analysis of sustainable power capacity, based on a volumetric heat-in-place approach. Of the various inputs required for the technique, reservoir temperature, thickness, and area are the most critical.
Estimating reservoir temperature
Following a study of the available geochemical analyses of reservoir fluid, geothermometric calculations yielded fluid temperatures in the range 264–269 degF, consistent with observed temperatures in the main production zone. As input to the probabilistic heat-in-place estimates, GeothermEx services estimated average reservoir temperatures to lie between 255 degF and 275 degF, with a most likely value of 265 degF. This range accounts for the potential contributions of deeper, hotter fluids as well as the slightly cooler, shallow zones noted during the long-term production-injection flow test.
Estimating reservoir thickness
Many of the static wellbore temperature surveys display a relatively high shallow geothermal gradient—approaching the maximum temperature in the first 300 ft of measured depth (MD)—followed by an isothermal profile to TD. In the deepest well, the isothermal zone extends across more than 2,200 ft before transitioning to a deeper, hotter zone that extends another 1,500 ft. Using these observations and empirically derived estimates of typical thickness for geothermal projects in similar geologic environments, the minimum, maximum, and most likely reservoir thicknesses were estimated.
Estimating reservoir area
First, the temperature distribution 6.5 ft below the surface was analyzed. Although very shallow and susceptible to dynamics in the local hydrogeology, these data provide a frame of reference for estimating the areal extent of the deeper reservoir. For example, the 70-degF and 75-degF contour lines on these data encompass approximately 6 mi2 and 3 mi2, respectively.
Temperature contours were also estimated at approximately 1,000-ft MD—which is more representative of the productive reservoir—using the inferred initial-state distribution of reservoir temperatures interpreted from static wellbore temperature surveys. The potential resource area represented by the 260-degF isotherm is approximately 2 mi2; it indicates the minimum resource area since hotter temperatures are observed in deeper parts of the reservoir. The inferred 230-degF isotherm encompasses nearly 6 mi2. Because of the lack of spatial coverage at this depth and inherent uncertainty in the inferred temperature distribution, GeothermEx services estimated the reservoir area to lie in the range of 2–4 mi2, with 3 mi2 the most likely value.
Confirming resource viability
With the key inputs reasonably bounded, the probabilistic heat-in-place calculations were carried out with the addition of a number of other parameters, whose assumed values were based on typical observed ranges. The analysis corroborated with a confidence level >90% that the required power output could be sustained from the reservoir. A study of available flow test data indicated that the wells could reasonably be expected to operate at the production and injection rates required for the proposed power plant.
The PPA terms under discussion required a power output in the first year equal to at least 95% of nominal capacity and subsequently declining by 0.5% annually for the 20-year duration of the agreement. GeothermEx services estimated that this decline would be equivalent to a temperature decrease of about 0.5 degF per year, assuming a constant flow rate of geothermal fluid. Based on other geothermal projects in similar geologic environments and comparable separation between production and injection wells, the projected 0.5% annual decline was deemed reasonable. With all concerns addressed, the PPA was signed and sealed to the mutual satisfaction of both parties.
Plant performance
Since the plant came online, its average output has significantly exceeded nominal capacity. The high permeability and shallow reservoir depth compensate for the relatively low production temperature, enabling economic and sustained development of the resource.
These results were supported by a new in-depth study conducted about 20 months later by GeothermEx services personnel. The latter study, encompassing nine production and five injection wells, was part of a due diligence review for another PPA related to a second plant in the field, which was due to come online soon.
Analysis of flow capacities and temperatures (based on demonstrated performance for the first plant and production tests in new wells for the second) confirmed that the reservoir could support more than the nominal output of the two plants. Calibrated resistance temperature detector (RTD) thermometers showed that the plant inlet temperature had declined less than the estimated 0.5 degF per year, while reservoir pressures also showed little or no change. Results of tracer testing indicated a hydraulic connection between the injection and production areas, which is beneficial from the perspective of supporting reservoir pressures. Moreover, based on the speed and magnitude of the tracer response, the risk of cooling due to injection is low. Finally, review of a reservoir simulation confirmed relatively modest temperature and pressure declines over the next 20 years, unlikely to have a significant impact on plant performance. Given the large amount of spare capacity available from existing wells, GeothermEx services estimated with 90% confidence level that the plants would maintain the required output for the duration of the agreement.
