Turkey contains extensive geothermal capacity which has been exploited through large-scale drilling projects. Data from more than 300 wells revealed abrasion, vibration, thermal, and fluid-loss drilling difficulties. Offset-well analysis showed that vibration mitigation tools, cooling procedures, proper bottom hole assembly (BHA) selection, and specific stuck-pipe practices minimized geothermal drilling risks.
The Kingdom of Saudi Arabia (KSA) also has extensive geothermal potential and has looked to Turkey’s geothermal experiences for best drilling practices. In addition, Aramco has designed well-test procedures and equipment to handle high temperature fluids, high flowrates, and associated gases from geothermal wells. Based on these advances, KSA will implement a large-scale geothermal program in-country to address the Kingdom’s thermal and electrical requirements.
Turkey geothermal
Turkey ranks fourth in the world in installed geothermal capacity, and most of the licenses are in Western Anatolia (Table 1). Büyük Menderes Graben and Gediz Graben (valleys with distinct escarpments on each side caused by downward displacement from parallel normal faults) contain most of the reservoirs. The Kızıldere geothermal field in Menderes Graben contains top and mid reservoir sections of conglomerate, limestone, sandstone, and marl. Shales appear as intervals or in shaly limestones. Menderes metamorphic rock lies beneath these layers and is comprised of quartz-schist, marble, or quartzite with intervals of mica-schist and chlorite-schist resulting from interbedding. The basement İğdecik formation contains alternations of quartzite, micaschist, and marble.
Total installed geothermal generation (Table 1)
Germencik field, formed by metamorphics of the Menderes Massif, and Salavatlı-Alaşehir fields in Gediz Graben, has similar lithology to Kızıldere (Fig. 1). Geothermal wells in these fields require drilling through Menderes metamorphic rocks. These rocks are much harder than shale and limestone, with hardness like quartz.
The region has steeply dipping E-W striking normal faults and transversely oriented (N-NW to N-NE striking) oblique-slip faults. These faults intersect, overlap, or terminate, and geothermal wells require directional deviations to navigate through them.
In addition to these directional drilling issues, formation dips push the drillstring off planned trajectory. A study of four wells drilled in the same field using similar J-well trajectories with planned 1.5°/30 m dog leg severity (DLS) showed that the first well’s DLS peaked at 6°/30 m. The higher bend angle compensated for the formation dip. Using the slide and formation data obtained from this wildcat well, drilling improvements resulted in ≤ 2°/30 m DLS for the final two wells.
This heterogeneous interbedded geological setting, combined with a high geothermal gradient, produces shocks, vibrations, increased wear on stabilizer coatings, and thermal degradation of electronics while drilling. Additional drilling problems from natural fractures in the Menderes Massif rocks include high drilling-fluid losses which potentially lead to stuck pipe. Total reached depth depends in part on both reservoir depth and expected drilling losses.
Turkish geothermal wells typically drill with J-, S-, and vertical-well trajectories with only a few horizontal wells in inventory. Wells have 8-10 m surface displacement on-pad. The well designs typically include tapered strings with 20-in., 13 ⅜-in., 9 ⅝-in, and 7-in. OD casing inside 26-in, 17 ½-in., 12 ¼-in, and 8 ½-in. holes, respectively. The 17 ½-in. hole section is typically drilled vertically, with kick-off in the 12 ¼-in. hole section.
The 20-in casing sections go through alluvium rocks, the 13 ⅜-in. casing section starts when the sedimentary rock section transitions to metamorphic rock, and the 9 ⅝-in casing section starts upon encountering Menderes Metamorphic rocks. The 7-in. casing contains slotted liners for production and is set upon reaching target depth or if adequate losses are encountered to indicate good reservoir connectivity and flow.
Casing for geothermal service needs to be H2S-rated, with a 1.75 safety-factor for tensile and burst ratings and a 1.15 safety-factor for collapse rating. In Turkey, top and intermediate sections use K-55 steel while the production (wetted) casing uses L-80 for corrosion resistance. Water based mud (WBM) comprises the drilling fluid with formulations based on formation temperature, wellbore stability, and formation damage potential.
The drillstring BHA contains a positive displacement motor (PDM), measuring while drilling (MWD) tools, drilling jars, and stabilizers (Fig. 2). Two stabilizers are typically employed in the BHA, one on the lower part of the motor and one on the string above. Stabilizer diameters vary depending upon drilled section trajectories. Tricone insert bits are preferred over polycrystalline diamond bits based on the former’s steerability in metamorphic rocks.
Wear, shock stabilization
Turkey’s geothermal drilling experiences showed that highly abrasive Menderes metamorphic schist and gneiss reduce bit and stabilizer life (Fig. 3). In the Kızıldere region, lower-sleeve stabilizers were particularly prone to wear when drilling through these rocks. Quartzite and quartzschist produced more blade abrasion than marble, with the 12 ¼-in. section showing the highest wear.
After each bit trip, motor stabilizer changeouts were required to prevent suboptimal motor performance. String stabilizers had less wear and were used in multiple runs. These stabilizers contained abrasion-resistant tungsten carbide coatings.
Metamorphic rocks and interbedded stratigraphy produce high lateral and axial shock loads. Axial vibrations produce bit bounce, and lateral vibrations produce bit whirl (OGJ, Oct. 10, 2024, pp. 14-25). These vibrational modes combine to lower rate of penetration (ROP), increase drilling time, and require more bits and stabilizers. Fig. 4 shows vibration and shock data in the 8 ½-in. hole section of a geothermal well. The data show up to 200-g shock and 30-g rms (root mean square of 1-ms axial acceleration in 10 sec of data) vibrational axial loads through Menderes metamorphic rocks sections.
To counteract these forces, subsequent wells used a spring-loaded tool assembly to provide constant weight on bit (WOB), isolating the BHA string from the nonuniform motions of the drill string in either drilling motor or rotary BHA applications. The tool contains a 24-in. stroke length compared with a typical 6-in. stroke of a standard shock sub.
Comparison data between wells with and without this shock tool show that the tool decreased shock frequencies from above 4,000 cycles/sec to less than 500 cycles/sec. The tool improved ROP by 23% and decreased string vibration by 25%.
Drilling at high temperatures
Reservoir temperatures for Niğde and Alasehir geothermal fields are 295° C. and 287° C., respectively, representing the highest temperatures in Turkey. Historical geothermal drilling data in Turkey typically shows about 160° C. dynamic bottomhole temperature (BHT) while drilling, which increases to 180° C. after a bit trip. These temperatures are at the limits of typical MWD electronics, seals on jars, and motors. To address these problems, directional companies drilling in geothermal wells implement cooling procedures and use higher-temperature resistant equipment, including power sections rated to 175° C., seals rated to 205° C., and MWD sensors rated to 175° C.
Cooling procedure guidelines minimize thermal tool failure risk. These procedures go into effect when dynamic temperatures reach 90° C., because at this point static temperatures can reach 120° C. After this, temperatures are checked every 300 m. A 15-min circulation is established if the temperature increases drastically between two checkpoints or is above 120° C. If the temperature increases further, interval depth between checkpoints is shortened and circulation time is lengthened. Mud cooling towers have proven effective in certain instances where these procedures do not reduce temperatures to operable limits.
Stopping lost circulation in geothermal wells faces two major problems: high loss rates and high-temperature incompatibility of fluid-loss material (FLM). Sodium silicate pumped ahead of the cement slurry effectively prevented high-temperature loss. For temperatures below 121° C., crosslinked cement provided suitable fluid-loss control when LCM failed. For high-permeability fractured zones which did not respond to these treatments, lost circulation required an engineered spacer containing hydrophobically modified polysaccharides pumped before the cement slurry. These polysaccharides bridged across the fractures to reduce fluid losses.
Combining the above lessons from Turkey’s extensive geothermal well database, best practices have been implemented with respect to vibration mitigation tools, cooling procedures, and proper bit and directional equipment selection.
Saudi geothermal
KSA produces the majority of the six-member Gulf Cooperation Council’s (GCC) greenhouse gas emissions (GHG) about 65% in 2019. The country has implemented a large-scale geothermal energy program as part of its efforts to reduce GHG.
KSA contains three sources of geothermal energy: high-enthalpy volcanic intrusives (Harrats), high-enthalpy radiogenic granites, and medium enthalpy hot springs (Fig. 5). These are mainly wet geothermal systems, not requiring enhanced geothermal systems (EGS) to supply water (OGJ, June 6, 2022, pp. 40-44).
There are 10 main Harrats in the Arabian Sheild: Ithnayan, Khyabar, Rahat, Lunayyir, Al Sirat, Kuraama, Al Buqum, Shama, Al Birk, and Rahat. These Harrats cover preexisting drainage and paleochannels. Volcanic activity continues about 8 km below Harrat Lunayyir. Crustal thinning causes high enthalpy. These systems are suitable for power generation and are in the central part of the Arabian Shield, close to western and central Saudi domestic and industrial applications.
Radioactive minerals (uranium, thorium, and potassium) within granites also produce high-enthalpy systems with high heat-flow, mostly in north and northwestern parts of KSA. While most are wet, some of these granites are dry and may be suitable for EGS. These systems can produce power for domestic and industrial applications in central Saudi Arabia.
Hot springs fed by faults and fractures connected to hot subsurface anomalies exist in western and southwestern coastal parts of Saudi Arabia. Most hot springs produce 40-80° C., with Ain-Al Harrah hot spring representing one of the hottest spring-water sources at about 95° C. While too low in enthalpy for power generation, the heat from these springs can drive district cooling, desalination, and agriculture applications.
KSA plans to apply Turkey’s geothermal well design, drilling procedures, and lessons learned for its geothermal projects. Towards that end, Aramco developed geothermal well testing guidelines which require different considerations than oil and gas well testing.
Aramco geothermal well testing
Geothermal well testing requires higher flow rates and upgraded equipment relative to oil and gas testing. Test objectives include heat capacity and enthalpy measurements instead of gas-oil or water-oil ratios to assess the well’s potential to power an electrical plant or provide heat, depending on the application. Table 2 lists the main differences between geothermal and conventional oil and gas test parameters.
Well-testing parameters (Table 2)
While geothermal testing concentrates on water or steam production, considerations must be made for other non-condensable gases (NCG) such as H2S, CO2, and N2. These components affect the metallurgy required for completion and test equipment. Safely venting these gases requires standard oil and gas pressurized equipment upstream of the atmospheric geothermal equipment. Best practices require a minimum wind speed of 5 knots during the tests with surrounding gas sensors to monitor H2S releases exceeding 5 ppm.
Geothermal well test methods include tracer dilution, two-phase sharp-edge orifice, total-flow calorimeter, and vertical discharge with lip pressure. Aramco chose the latter for their geothermal project. Fig. 5 shows a process diagram for this test. Gate valves comprise the first surface barriers for the test, and these must be rated to 500° F. with 8- to 10-in. gates for geothermal service. Well-flow passes through a straight pipe downstream of the gate valves and constricts through a smaller lip pipe, or James Tube, to discharge into a separator at atmospheric pressure. Most of the steam is flashed at the separator while the water passes through a weir box for volumetric measurement. For additional safety, a digital weir level sensor, backed up by an electromagnetic flow meter, provides remote flow measurements to keep personnel away from well discharge.
Well-enthalpy calculations use empirical Equation 1 which incorporates the water flow rate and lip pressure at the end of the James Tube. Total well effluent, steam flow rates, and potential power are calculated by using the enthalpy, water rate, and results from a saturated steam table.
Digital data collection during geothermal well testing includes upstream and downstream pressure of the gate valve, upstream and downstream temperature of the gate valve, James Tube lip pressure, flow between silencer and weir box, and liquid level measurement at the weir box. Flow measurement is by an electromagnetic flow meter and weir box level by digital level radar. Manual data collection includes James Tube size, water density, salinity, pH, and sediments based on sampling.
Aramco geothermal testing requires a downhole electrical submersible pump (ESP), and ESP data include pump intake pressure, pump intake temperature, and pump discharge pressure. These data are integrated into well test software to calculate water flow rate at standard conditions, total enthalpy, total flow rate including water and steam, steam flow rate, steam fraction, and potential electrical power generation. A secure web-based platform provided remote real-time data access and visualization for personnel to quality-check and evaluate the data for project goals.
Alex Procyk | Upstream Editor
Alex Procyk is Upstream Editor at Oil & Gas Journal. He has also served as a principal technical professional at Halliburton and as a completion engineer at ConocoPhillips. He holds a BS in chemistry (1987) from Kent State University and a PhD in chemistry (1992) from Carnegie Mellon University. He is a member of the Society of Petroleum Engineers (SPE).
