Drilling cost reduction is a major concern for geothermal operators and crucial to long-term geothermal development. Reducing drilling days and lowering per-foot costs are primary means to achieving this goal. Baker Hughes, Inc. (BHI) developed the Kymera hybrid bit with these goals in mind. The advantage of the Kymera bit technology versus standard tungsten carbide insert (TCI) bits is in the Kymera’s combination of roller-cone design and polycrystalline diamond compact (PDC) bit design. In trials at EnergySource’s Hudson Ranch II project, performance data from 12.25- in (311 mm) and 9.875- in (250.8 mm) Kymera bit runs are compared to TCI bit runs in offset wells. Performance is measured using a systematic approach comparing revolutions per minute (RPM) and rate of penetration (ROP) in both slide and rotating modes. Formation and depth are also factored into the performance data. The Kymera hybrid bit increased rates of penetration and total footage drilled per bit run, resulting in a significant reduction in cost per foot (CPF) versus standard roller-cone bits for a substantial cost savings.
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.
An injection stimulation test begun at the Raft River geothermal reservoir in June, 2013 has produced a wealth of data describing well and reservoir response via high-resolution temperature logging and distributed temperature sensing, seismic monitoring, periodic borehole televiewer logging, periodic stepped flow rate tests and tracer injections before and after stimulation efforts. The hydraulic response demonstrates continually increasing injectivity, reflected in varying flow rate response to nearly constant injection pressure, but features of the hydraulic response provide information about different characteristics of the reservoir. Changes in injectivity immediately following high-flow rate tests suggest that hydro shearing has altered the near-well permeability structure, while pressure response during those tests indicates that near-well permeability is relatively homogeneous and low but that the well is near, but not well connected to, a zone of higher transmissivity. Long-term changes in injectivity are believed to reflect propagation of the injection cooling front through low permeability zones. Two dimensional flow and heat transport simulations are used to demonstrate how the timescale of pressure response may relate to length scales of permeability distribution.
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).
In June 1991, a high-pressure/high-temperature well located in Hawaii kicked and unloaded at 3,476 ft (1,059 m). This well was estimated to have a possible bottomhole temperature of 650°F (343°C) and a reservoir pressure approaching 2,300 psi (15,858kPa). Immediate attempts to kill the well were unsuccessful, and the long process
of well control was started.
Besides the harsh geological and reservoir conditions encountered, the scarce availability of materials in a remote location and long distance transportation of necessary equipment figured heavily into the time delay of the final kill procedure of the well.
Regaining the control of the well in a remote, tropical environment was accomplished using state-of-the-art well control techniques. These techniques were applied through the operating company's careful coordination of service companies and personnel during a month period.
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.
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