Abstract:

Magma Energy (U.S.) Corp. (Magma) acquired a 13 sq mi three-dimensional, three-component reflection seismic survey over the Soda Lake geothermal field in June 2010. The Soda Lake field has been in production since the early 1980’s and gross generation is below name-plate-rating due to declining reservoir temperatures. Magma Energy (U.S.) Corp acquired the plant in October 2008 with the goal of increasing production to the plant’s name plate rating and identify additional resources. To achieve
this goal, Magma made a major effort of integrating existing well field and new geophysical data into a comprehensive 3D GIS interpretation. Integration of the existing well data, 3D seismic and precision gravity led to a new conceptual model and identified two exploration targets outside of the existing producing area that were overlooked for twenty years.

Abstract:

In 2010, a geothermal exploratory drilling program was conducted on Akutan Island, Alaska. The purpose of the drilling program was to obtain temperature gradient data to constrain resource capacity. The wells were designed to allow long-term monitoring and possible testing of the Akutan geothermal field. The 2010 drilling operations were carried out using wireline core equipment and were supported by helicopter. Two wells were drilled to respective depths of 253.9 meters and 457.2 meters. The first well (TG-2) was drilled directly above an outflow aquifer(s). A preliminary analysis of the TG-2 well showed that the well made 2-phase flow with a 190 liter per minute liquid phase via a 96 mm hole and from a depth of 177 to 178 m. The second well (TG-4) was drilled at the margins of the modeled outflow in order to conceptualize the size of the outflow resource. That well had very low permeability but displayed a high temperature gradient, with an extrapolated temperature of 164 deg C at 457 m. Some evidence that a deeper, hotter resource exists at or near the TG-4 site was found using mineralogical data. Preliminary analysis of data suggests that a pumped production well at the TG-2 site would be capable of a maximum production of 2.3 MW. Geochemical sampling of the fumarole gasses was carried out on the flank of the Akutan Volcano concurrent with the drilling. The data obtained from drilling will be combined with core and geochemical analysis in order to form a resource model of the field preliminary to
production drilling.

Abstract:

A study completed by the French geological survey, Bureau de Recherches Géologiques et Minières (BRGM), in 1984 suggested the existence of a large geothermal reservoir in the Wotten Waven and Laudat areas of the Roseau Valley (BRGM, 1984). Many surface manifestations are apparent, including hot and warm springs, solfatara, and fumaroles, which produce sodium-chloride water, and exhibit strong 18O isotopic shifts and geothermometer temperatures exceeding 230°C. The possible extent of the system over an area of approximately 8 km2 was delineated by complimentary resistivity and gravity surveys.

In 2012, the Geothermal Program Management Unit (GPMU) of the Commonwealth of Dominica successfully completed exploration drilling in the Roseau Valley Geothermal Field. Three slim holes were drilled to depths ranging from 1200 m to 1613 m. All of the wells completed in 2012 were productive, with the strongest exhibiting flow rates up to 29 kg/s at a wellhead pressure of 17.5 barg. Measured temperatures, as high as 246°C and in agreement with earlier BRGM exploration, are accompanied by neutral pH, low salinity fluids. ELC Electroconsult S.p.A (ELC) evaluated the results of the well tests and provided a preliminary volumetric reservoir assessment, using a Monte Carlo approach, estimating indicated and inferred potentials of 60 MW and 90 MW, with probabilities of 90% and 60%, respectively. Aside from providing technical assistance from 2009 to 2013, ELC also selected the well sites for WW-1, WW-2, and WW-3. Development of the Roseau Valley geothermal resource is continuing in 2014 with the drilling of full-size production and injection wells, and feasibility studies for the construction of a 10-15 MW power plant.

Abstract:

The Raft River geothermal system, located 160 km northwest of Salt Lake City, Utah is the site of a Department of Energy Enhanced Geothermal System (EGS) stimulation demonstration project. The target well RRG-9 ST-1, is roughly 1.6 km (1 mile) south of the power plant. This well has undergone a series of thermal and hydraulic stimulation treatments. The well passes through approximately 1,524 m MD (5,000 ft. MD) of laterally discontinuous Quaternary and Tertiary volcanoclastic and volcanic rocks that unconformably overlie the Precambrian basement. The Elba Quartzite formation located in the Precambrian basement is the target zone for the stimulation program. Fluid injected into the well exits through a fracture zone in the Elba Quartzite at 1,567 m TVD (5,140 ft. TVD). In June 2013 low-rate stimulation began at RRG-9 ST-1 using injection water from the geothermal plant. The average injection rate, temperature, and well head pressure of the low-rate stimulation was 163 Lpm (43 gpm), 34°C, and 1,931kPa (280 psig), respectively. This injection continued through late August of 2013 when wellhead pressures were intentionally increased to approximately 5,516 kPa (800 psig) at approximately 984 Lpm (260 gpm). From September 12 to September 24, 2013 cold well water was injected. The average surface injection temperature was approximately 12°C. On September 25, 2013 injection of the warmer plant water was resumed. This was continued through the rest of 2013 and into 2014. Between April 1, 2014 and April 4, 2014, a higher rate hydraulic stimulation was conducted. Colder water (~10°C) was injected at rates of 20 bpm to 30 bpm (3,178 Lpm to 4,770 Lpm) at wellhead pressures of 5,861 kPa (850 psig) over approximately 24 hours. Microseismic activity was recorded near the Tertiary-Precambrian contact. Subsequently, injection of water from the plant was resumed. As of mid-January, 2015, over 666 million liters (176 million gallons) have been injected into the well. The fate of this water is the subject of ongoing numerical analyses and continuous site monitoring.

Various analyses have been implemented to monitor and assess the ongoing stimulation program. Modified Hall plot analysis shows increasing conductivity and/or a decreasing skin factor around the wellbore. Since April, 2014, the injectivity index has increased significantly from 0.28 Lpm/kPa (0.5 gpm/psig) to 0.93 Lpm/kPa (1.7 gpm/psig).

Abstract:

Scientific test well 58-32 was drilled to a depth of 7,536 ft (2,297 m) to obtain direct measurements on rock type, temperature, permeability and stress within the Utah FORGE reservoir. Well 58-32 encountered the top of the granite at about 3200 ft. (975 m) and the top of the FORGE reservoir at 6500 ft. (1980 m) based on expected formation temperature. Drilling tool selection kept the rate of penetration reasonable through the hard rock formation. The well was cased with 7-inch casing to a depth of 7,374 ft. (2,247 m). Core samples were collected near the top of the expected reservoir and at total depth, prior to running the casing in the hole. Injection testing and fall-off
pressures provide data on the permeability of the crystalline rock. Additional data were obtained, including a suite of geophysical logs, pressure and temperature surveys, and microresistivity image logs. An injection test was conducted in the open hole section of the well. The temperature surveys indicate over 350°F (175°C) at the reservoir depth, as required for the FORGE initiative enhanced geothermal systems laboratory. The drilling and testing of 58-32 well was completed deeper than planned, ahead of schedule and under budget.

Abstract:

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 miniaturized instruments and other components, microbore exploration wells can reduce drilling cost and risk. Of critical importance in the use of a surrogate slim hole or microbore 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 bore diameter, resource conditions and the amount of scale up to larger sizes desired. 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 may be limited due to steam and gas emission considerations, hazardous liquid composition, or water disposal restrictions. Using innovative test methods, microbore resource evaluation can be completed using injection, drill stem tests, and in situ chemical analysis. These methods require substantially less infrastructure and reduce the time required for resource evaluation.