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HS Orka has operated the Svartsengi Geothermal Power Plant since 1976, the Reykjanes geothermal system since 1982, and the 100 MW Reykjanes Power plant since 2006. Scaling problems have been observed in wells and in most parts of the surface equipment. This paper describes the various types of scaling encountered and the different fluid conditions where scaling is formed. The current methods of scaling mitigations will be provided and described how the plant operation can be made reliable, in spite of scaling problems.
HS Orka has been operating the Svartsengi Geothermal Power plant since 1976, the Reykjanes Geothermal System since 1982, and the 100 MW Reykjanes Power Plant since 2006. The fields produce brine in the temperature range from 235°C to approximately 300°C. The deep-well fluid contains total dissolved solids (TDS) of about 23.000 mg/kg for Svartsengi and 33.000 for Reykjanes. The reservoir fluid is of seawater origin. Scaling is strongly dependent on the downhole temperatures in the wells.
Studies on the water and scaling in Svartsengi have been performed, indicating effects of time, acidity, and temperature on scaling behavior.
Scaling in wells in Svartsengi
The types of scaling depend on the downhole temperature and chemistry. Calcite used to be the main scaling problem in Svartsengi. When flowing up the well, the fluid starts boiling when the pressure drops sufficiently. As the boiling starts, CO2 goes into the vapor phase while calcium carbonate remains in liquid phase. Then, calcite precipitates on the well surfaces. During the first 5 years of operation, the wells had to be worked over by a drilling rig at 6 to 8 months interval. The first few wells were completed with a 9 5/8” casing and 7” slotted liner. Wells from no. 7 onwards were widened with 13 3/8” casing and 9 5/8” slotted liner. This prolonged the workover interval to over a year up to two years. The need for workover diminished gradually as the geothermal reservoir degassed, see Figure.3.
The second deep geothermal well drilled in the Iceland Deep Drilling Project (IDDP) at Reykjanes was completed in the year 2017. The final depth of the IDDP-2 well reached 4650 m depth, with a bottom hole temperature of 427°C and a pressure around 340 bar. The well was injected with cold tap water for stimulation after being completed. Temperature measurements were performed during an intermediate heat up in the well where no cold water injection was performed. A carbon steel injection pipe was implemented to the bottom of the well to ensure cold water and improved stimulation into the deepest part of the well. Extensive corrosion damages were discovered on the lowest part of the injection string when retrieved. Multiple axial cracks were also observed on the joint ends in a 600-meter interval of the pipe, from 4650 up to 4000 m depth. Failure analysis of damaged parts of the injection pipe with visual inspection and microscopic examination revealed extensive uniform and pitting corrosion. The analyze indicate that the high temperature and relatively high oxygen content in the cold water used for injection and contact with corrosive reservoir fluid caused the severe corrosion. The analysis of the cracks and hardness measurements of the joints indicate that sulfide stress corrosion cracking is the most likely cause of failure due to combined effect of thermal stresses, corrosive environment and susceptible material.
The drilling of the second deep geothermal well drilled in the Iceland Deep Drilling Project (IDDP) at Reykjanes geothermal field was successfully completed in the beginning of year 2017. The previously drilled RN 15 production well, 2500 m deep, was used as the base for the IDDP-2 well. The final depth of the IDDP-2 well reached 4650 m depth, with a bottom hole temperature measured to be 427°C and a pressure around 340 bar. The bottom of the IDDP-2 well reached fluid at supercritical conditions and became the deepest geothermal well in Iceland. After completion of the well a 3,5” drill string was implemented into the very bottom of the well. The well was injected with cold tap water for stimulation within the injection drill string. The drill string was made of carbon steel (API 5DP PSL1 grade G-105). The flow rate of the cold water was 15 l/s inside the drill string and 45 l/s in annulus (space between injection drill string and well casings and liner). During the cold water injection period the pumping was stopped and the water in the well was able to heat up for several days during two separate heat up periods, in March and May 2017. Figure 1 shows measured temperature of the well during injection. Damages were discovered in the IDDP-2 casing at 2300 m depth. From Figure 1 it can be stated that reservoir fluid is flowing into the well at 2300 meter because there is a step in the temperature at this point. During the time from when the drill string was first inserted to the well there have been different flow rates for the cold water injection to the well to improve thermal stimulation. In certain periods there has also been no injection to allow periodic heating of the well as stated previously. Pressure measurements show overpressure in the bottom of the well compared to the assumed hydrostatic pressure in the reservoir during the heat up periods. This leads to downwards flows internally in the well towards the lowest reservoir zones and the lowest section of the drill string. This shows the possibility for reservoir fluids to be in contact with the outside of the drill string at least in certain periods. The temperature within the drill string was recorded during one heat up period; it reached 384°C at the bottom and 254°C at 4000 m after 5 days of heating up.1
Stefánsson, Ari (HS Orka) | Duerholt, Ralf (Baker Hughes, a GE company) | Schroder, Jon (Baker Hughes, a GE company) | Macpherson, John (Baker Hughes, a GE company) | Hohl, Carsten (Baker Hughes, a GE company) | Kruspe, Thomas (Baker Hughes, a GE company) | Eriksen, Tor-Jan (Baker Hughes, a GE company)
The typical rating for downhole measurement-while-drilling equipment for oil and gas drilling is between 150°C and 175°C. There are currently few available drilling systems rated for operation at temperatures above 200°C. This paper describes the development, testing and field deployment of a drilling system comprised of drill bits, positive displacement motors and drilling fluids capable of drilling at operating temperatures up to 300°C. It also describes the development and testing of a 300°C capable measurement-while-drilling platform.
The development of 300°C technologies for geothermal drilling also extends tool capabilities, longevity and reliability at lower oilfield temperatures. New technologies developed in this project include 300°C drill bits, metal-to-metal motors, and drilling fluid, and an advanced hybrid electronics and downhole cooling system for a measurement-while-drilling platform. The overall approach was to remove elastomers from the drilling system and to provide a robust "drilling-ready" downhole cooling system for electronics. The project included laboratory testing, field testing and full field deployment of the drilling system. The US Department of Energy Geothermal Technologies Office partially funded the project.
The use of a sub-optimal drilling system due to the limited availability of very high temperature technology can result in unnecessarily high overall wellbore construction costs. It can lead to short runs, downhole tool failures and poor drilling rates. The paper presents results from the testing and deployment of the 300°C drilling system. It describes successful laboratory testing of individual bottom-hole-assembly components, and full-scale integration tests on an in-house research rig. The paper also describes the successful deployment of the 300°C drilling system in the exploratory geothermal well IDDP-2 as part of the Iceland Deep Drilling Project. The well reached a measured depth of 4659m, by far the deepest in Iceland. The paper includes drilling performance data and the results of post-run analysis of bits and motors used in this well, which confirm the encouraging results obtained during laboratory tests. The paper also discusses testing and performance of the 300°C rated measurement-while-drilling components – hybrid electronics, power and telemetry - and the performance of the drilling tolerant cooling system.
This is the industry's first 300°C capable drilling system, comprising metal-to-metal motors, drill bits, drilling fluid and accompanying measurement-while-drilling system. These new technologies provide opportunities for drilling oil and gas wells in previously undrillable ultra-high temperature environments.