High Temperature Geothermal Wells Research Articles

Computational Fluid Dynamics Study on Bottom-Hole Multiphase Flow Fields Formed by Polycrystalline Diamond Compact Drill Bits in Foam Drilling

High-temperature geothermal wells frequently employ foam drilling fluids and Polycrystalline Diamond Compact (PDC) drill bits. Understanding the bottom-hole flow field of PDC drill bits in foam drilling is essential for accurately analyzing their hydraulic structure design. Based on computational fluid dynamics (CFD) and multiphase flow theory, this paper establishes a numerical simulation technique for gas-liquid-solid multiphase flow in foam drilling with PDC drill bits, combined with a qualitative and quantitative hydraulic structure evaluation method. This method is applied to simulate the bottom-hole flow field of a six-blade PDC drill bit. The results show that the flow velocity of the air phase in foam drilling fluid is generally higher than that of the water phase. Some blades’ cutting teeth exhibit poor cleaning and cooling effects, with individual cutting teeth showing signs of erosion damage and cuttings cross-flow between channels. To address these issues, optimizing the nozzle spray angle and channel design is necessary to improve hydraulic energy distribution, enhance drilling efficiency, and extend drill bit life. This study provides new ideas and methods for developing geothermal drilling technology in the numerical simulation of a gas-liquid-solid three-phase flow field. Additionally, the combined qualitative and quantitative evaluation method offers new insights and approaches for research and practice in drilling engineering.

Real-time prediction of bottom-hole circulating temperature in geothermal wells using machine learning models

Drilling high-temperature geothermal wells presents technical and economic challenges. Real-time and precise estimation of bottom-hole circulating temperature (BHCT) during geothermal drilling is crucial for maximizing the working life of drill bits and temperature-limited bottom-hole assembly (BHA) components, thereby avoiding unplanned and unnecessary bit/BHA trips. This study introduces a novel machine learning (ML) model that accurately predicts BHCT in real time, enhancing proactive temperature management and mitigating thermally induced challenges during geothermal drilling operations.An integrated thermo-hydraulic model, validated using publicly available data from the Utah FORGE field, was used to generate a large dataset that simulates the transient BHCT under typical drilling conditions. This dataset was subsequently used to train and test the prediction capability of six ML models of the BHCT, including deep neural networks (DNN), support vector machines (SVR), random forests (RF), extreme gradient boosting regressor (XGBoost), ensemble (Stacked) algorithm, and long-short term memory (LSTM) networks. It was also used to generate an understanding of the non-linear relationship between the input features and the output variable (BHCT). Resultsdemonstrate the benefits of implementing the LSTM model for reliable prediction of the BHCT and capturing its full-scale transient behavior in geothermal wells. The LSTM model stands out for its excellent generalization capability, stability, and precision in real-time estimation of BHCT across various geothermal drilling conditions, including both stationary and dynamic scenarios. This is achieved without the high computational costs associated with complex numerical models, thus preventing temperature-related drilling problems. Among the other supervised ML models, the XGBoost model can still reliably simulate the BHCT with a mean absolute error (MAE) below 1 °C during geothermal drilling at constant drilling parameters, but will show overfitting when drilling parameters change.

Evaluating the maximum drilling length of horizontal geothermal wells utilizing temperature constraints

The geothermal industry faces a significant challenge in exploring and developing resources due to elevated temperatures in downhole environments. Successful drilling in high-temperature geothermal wells requires precise thermal management. This research assesses constraints on horizontal section length and temperature during geothermal horizontal well drilling, aiming to formulate effective wellbore temperature management guidelines.The study utilizes thermal resistance analysis to establish a tailored transient heat transfer model for high-temperature horizontal geothermal well drilling. Parameters such as circulation time, horizontal section length, flow rate, drilling fluid properties, formation thermal conductivity, and drill string thermal conductivity are thoroughly investigated. Treating input parameters as triangular distributions, Monte Carlo simulation techniques conduct sensitivity analysis. Tornado diagrams quantitatively determine key parameter impacts on bottom-hole temperature. The research introduces a procedural framework for geothermal well drilling, aiding engineers in swiftly identifying operational parameter combinations for effective wellbore temperature management. This workflow provides practical guidance for geothermal resource development, ensuring drilling safety in diverse conditions.

Innovative drilling fluid containing sand grafted with a cationic surfactant capable of drilling high pressure and high temperature geothermal and petroleum wells

Maintaining the rheology and filtration properties of a drilling fluid plays a vital role during a drilling operation. With the current challenges of high pressure and high temperature environments, there is an urgent need to design thermally stable water-based mud systems (WBM) which are environmentally clean and economically cheap.High pressure and high temperature (HPHT) environments affect drilling fluid systems leading to degradation of additives hence reducing the efficiency of the drilling fluid. Nanotechnology has been widely used to answer questions about additive degradation, and many studies are currently being conducted on how to use nanotechnology to design smart drilling fluids. However, nanotechnology comes at a high cost, resulting in an increase in the overall drilling operation costs and the project as a all. Therefore, the effectiveness of sand particles as a replacement of commercial nanoparticles is investigated in this study as an additive for designing effective-performance water-based drilling fluids. Effective-performance drilling fluids are environmentally friendly, stable at high temperatures, and help to avoid well damage during drilling operations.The research compared sand particles, which are widely available and inexpensive to silica nanoparticles at 0.5 wt% concentration. The samples were tested at different aging temperatures. Rheological properties were measured at room temperature up to 232 °C. The performance of sand and silica nanoparticles was studied by comparing each of the nanoparticle muds with the reference mud sample, taking filtration and rheological properties as the benchmark parameters. Experimental data showed that sand particles enhanced almost all the rheological and filtration properties of the WBM compared to the reference mud. When compared to silica nanoparticles, the results showed neither statistically significant variance in plastic viscosity and yield point among the samples, with muds containing sand particles performing similarly or better. Formulation S2 (35–70 μm) demonstrated the ability to improve the rheology of WBM. At 204 °C and 232 °C, Formulation S2 (35–70 μm) filtrate loss decreased by 16.35% and 29.52%, respectively, compared to 5.66% and 11.32% by mud containing nano silica. The same mud sample decreased the mud cake thickness at the same temperatures conditions by 54.74% and 45.45%, respectively, as opposed to 36.84% and 11.81%. The new innovative mud system can be used to drill in HPHT conditions.

Assessment of Cementitious Composites for High-Temperature Geothermal Wells.

High-temperature (HT) geothermal wells can provide green power 24 hours a day, 7 days a week. Under harsh environmental and operational conditions, the long-term durability requirements of such wells require special cementitious composites for well construction. This paper reports a comprehensive assessment of geothermal cement composites in cyclic pressure function laboratory tests and field exposures in an HT geothermal well (300-350 °C), as well as a numerical model to complement the experimental results. Performances of calcium-aluminate cement (CAC)-based composites and calcium-free cement were compared against the reference ordinary Portland cement (OPC)/silica blend. The stability and degradation of the tested materials were characterized by crystalline composition, thermo-gravimetric and elemental analyses, morphological studies, water-fillable porosity, and mechanical property measurements. All CAC-based formulations outperformed the reference blend both in the function and exposure tests. The reference OPC/silica lost its mechanical properties during the 9-month well exposure through extensive HT carbonation, while the properties of the CAC-based blends improved over that period. The Modified Cam-Clay (MCC) plasticity parameters of several HT cement formulations were extracted from triaxial and Brazilian tests and verified against the experimental results of function cyclic tests. These parameters can be used in well integrity models to predict the field-scale behavior of the cement sheath under geothermal well conditions.

Feasibility Analysis of Drilling with Liquid Nitrogen in High Temperature Geothermal Wells

The main costs of developing geothermal processes are concentrated in the project of drilling, accounting for more than 70% of the total budget. Inspired by thermal stimulation technology，a new concept of drilling with liquid nitrogen was presented in this paper. The main objective of this paper is to investigate the effect of rapid cooling on bit-rock interaction and the feasibility of drilling with liquid nitrogen. Through the hardness test experiment results, it showed that the thermal stress caused by rapid cooling can reduce the resistance of indenter invades the rock. Then the micro-bit drilling experiment results indicated that liquid nitrogen can eliminate the thermal damage and enhance the wear resistance, which is the main factor affected the life and footage per bit in geothermal drilling. The negative effect is that liquid nitrogen increase the rock failure resistance slightly and need about 8% more mechanical specific energy compared with drilling with air, but the increase about 8% in mechanical specific energy is affordable to drilling engineers. All these results showed that drilling with liquid nitrogen is beneficial to improve the life and footage per bit, reduce non-production time and reduce drilling costs, it is a promising technology in geothermal engineering.

Experimental Investigation of Geopolymers for Application in High-Temperature and Geothermal Well Cementing

Summary With recurrent calls for a reduction in carbon emissions, geothermal (GT) energy has received increasing attention in recent years as a prominent source of clean energy. With current drilling technology, GT wells are being constructed in extremely challenging temperature environments, which could reach more than 600°F (315°C) in situ. However, GT well-cementing technology has not changed much over the past few decades, with ordinary Portland cement (OPC) still being the primary choice of cementing material. OPC has several drawbacks, including brittle behavior, shrinkage upon setting, poor bond strength to formation and casing, susceptibility to an acid gas attack, temperature-induced strength retrogression, and low tolerance toward drilling fluid contamination. These factors could lead to a poor cementing job, thus compromising well integrity and not ensuring proper zonal isolation for the life of the GT well. Thus, there is a need to develop an alternative material that is compatible with the GT environment and able to provide long-term zonal isolation. With a low carbon footprint, self-healing ability, and low shrinkage sensitivity, geopolymers or alkali-activated materials could be a suitable option to augment or even replace OPC. Some of the previous studies on geopolymers have shown that they could be a potential candidate for oil and gas well cementing and civil engineering applications, with some being stable at very high temperatures [up to 1,470°F (800°C)]. Geopolymers are formed by mixing an aluminosilicate source such as fly ash (FA) with an alkali-activating solution, such as sodium or potassium hydroxide or silicate. The aim of the study reported here is to demonstrate the applicability of geopolymers for GT well cementing. An experimental investigation was carried out to understand the behavior of geopolymer formulations made from FA, metakaolin (MK), and blast furnace slag in a high-temperature environment. The material properties such as porosity, viscosity, thickening/pump time, compressive strength, tensile strength, and bond strength were tested in the laboratory. It was found that geopolymer can be formulated to have the desired rheological properties with adequate pump time and resistance to drilling fluid contamination. In addition, the formulations can exceed the required compressive and tensile strength for GT cementing operations, while obtaining excellent bond strength values. These findings indicate that geopolymers are well-suited to provide long-term zonal isolation in high-temperature GT wells.

Modeling of two-phase flow of high temperature geothermal production wells in the Yangbajing geothermal field, Tibet

Two-phase flow (flow of water in both liquid and gas phase, containing a non-condensable gas such as CO2) in the wellbore is one of the most important processes in the production performance and wellbore scaling evaluations of high temperature geothermal wells. This paper first describes the discharge tests in the Yangbajing geothermal field, Tibet. Next, a simple model for governing the two-phase flow in the presence of CO2 in the wellbore is constructed and a robust calculation method is presented. The model is applied to three production wells in the Yangbajing geothermal field. The results show that the velocity difference between the gas and liquid phase should be included in the model. Ignoring this difference (i.e., homogeneous model) would result in a significant deviation between measurements and calculations. A drift flux model (DFM) describes the velocity difference, where the specifics of the particular model can have significant effects on the results for the pressure and temperature profiles in the wellbore. Three commonly used DFMs are compared to estimate their performance. The calculated wellhead pressure and temperature are in the range of 2,3 bar and 125°C–135°C for all three wells at a production rate of about 20 kg/s. The estimated wellhead gas mass fraction is between 3% and 8%. Considering CO2 content, three different scenarios were evaluated, although the effect on the pressure and temperature profiles were limited. However, CO2 content has a much more significant effect on the flash depth, which is an important parameter for the estimation of calcite scaling.

Personalized design and field experiment of polycrystalline diamond compact bits for high-temperature geothermal wells

Considering the existing geothermal drilling conditions in Kenya (200 °C, low penetration rate, and short service life), we propose new polycrystalline diamond compact (PDC) bits. The new PDC bit oblong holes, increase the drill hole radial coverage, can enlarge hole direct injection cooling cleaning the area of cutting tooth, reduce thermal wear failure of PDC cutters. Combined with the formation characteristics of the Olkaria block in a Kenyan well, the personalized design of PDC bits was realized by considering the following three aspects: high temperature–resistant PDC cutter optimization, bit cutting structure realization, and bit hydraulic structure realization. Furthermore, a φ 215.9-mm flat and long waterstoma PDC bit was developed and a field experiment was conducted. Experimental results show that the drilling speed of the PDC bit with flat waterstoma increased by 35.8%–144.3% and the footage increased by 173.4%–361.5% compared with the same bit in adjacent wells. This indicates that the PDC bit with flat waterstoma can adapt to Kenya's high temperature conditions (200 °C), efficiently cool the cutters, and prolong the service life of bits, accelerating the exploration and development of high-temperature geothermal wells. Furthermore, reducing geothermal drilling costs has positive implications.

Hydrothermal-activity stage classification and power-generation potential evaluation of geothermal wells based on a natural analog study on epithermal deposits, in Japan

In this study, we prepare guidelines for hydrothermal-activity stage classification and evaluate the power-generation potential of geothermal wells based on a natural analog study on the hydrogeological and thermal structures and hydrothermal-alteration minerals in a low-sulfidation epithermal deposit. As such, many high-temperature geothermal wells in Japan were classified into four hydrothermal-activity stages (early, middle, late-1, and late-2) based on the developed guidelines. In conclusion, the late-1-stage well is evaluated to supply fluids for power generation with the least economic and environmental risks. In contrast, the geothermal wells in other active stages indicate some of the concerns.

Experimental and Numerical Study on a Two-stage Coring Method for Stress Measurement: Application to Deep and High-Temperature Geothermal Wells

We discuss the possibility of recording the state of in-situ stress in the shape of a rock core that is sampled using a modified core drilling method. This concept is based on a phenomenon that a cylindrical rock-core expands radially into a slightly elliptical shape along its transverse cross-section when the rock sample is relieved of its in-situ anisotropic stress by drilling. The magnitudes and orientation of in-situ stresses can, in principle, be estimated from the circumferential variation of core expansion. However, it is not possible to evaluate the expansion from a core collected in a conventional way, with a single drilling bit, since it will be in its expanded state when extracted and lacks information about its required pre-expansion dimensions. To overcome this problem, we propose an innovative way of core drilling referred to as Dual-bit Coring. This approach results in a single core that has two signature transverse cross-sections: the first has an elliptical shape resulting from core expansion and the second records the initial circular shape prior expansion. Then, the amount of expansion can be estimated based on the differences between the shapes of those cross-sections. We propose practical drilling tool for carrying out Dual-bits Coring. The tool works mechanically and does not require any electric devices sensitive to high temperatures so that it is expected to function even in deep and high temperature rocks at geothermal fields, such as those encountered in supercritical geothermal systems.

Self-re-adhering alkali-activated cement composite and its ability to mitigate corrosion of carbon steel in 300 °C hydrothermal environment

Cement-steel interface is a weak point of cement sheath integrity under the environments of high-temperature geothermal wells. This paper presents carbon steel (CS) adherence behaviors of 300 °C-autoclaved alkali-activated Calcium-Aluminate-Cement (CAC)/fly ash F (FAF) (Thermal Shock Resistant Cement, TSRC), granulated blast furnace slag (GBFS)/SiO2, and Ordinary Portland Cement (OPC)/SiO2 blends. The composites’ ability to preserve the bond under the conditions of thermal shock (TS) and strong acid attack (pH 0.6 H2SO4/brine at 90 °C) as well as their ability to recover the damaged bond and provide steel corrosion protection after additional short-time 5-day curing at 300 °C were evaluated. GBFS/SiO2 sheath underwent catastrophic failure in the first TS cycle; OPC/SiO2 lost 78 % and TSRC 51 % of the bond strength in 6 cycles. Only TSRC-CS bond survived 30 days of strong acid exposure; OPC/SiO2 bond failed after 18 days and GBFS/SiO2 after 20 days. Addition of micro-glass fibers (MGF) to TSRC further improved its bond strength and CS corrosion protection. Samples of TSRC-CS cured for 30 days at 300 °C before the bond damage recovered 49 % of the damaged bond strength after additional short-time curing. The CS protected by the re-adhered TSRC showed low corrosion rate of 0.13 mm/year (TSRC-MGF), 0.2 mm/year (TSRC) vs. 0.64 mm/year for OPC/SiO2 protected CS.

Unit Quaternion Description Method for Detecting High-Temperature Geothermal Well Drilling Conditions

When the typically utilized method for detecting the drilling conditions of high-temperature geothermal wells is applied, the detection takes a long time, the detection results are inconsistent with the actual conditions, and there are problems such as low detection efficiency and large detection deviation. Therefore, a method for detecting the drilling conditions of high-temperature geothermal wells described by a unit quaternion is proposed. Based on quaternion theory, the quaternion model of the position and attitude is constructed to obtain the drilling attitude. According to the analysis results and the basic principle of kernel principal component analysis, a model is built to realize the detection of high-temperature geothermal well drilling conditions. The experimental results show that in many iterations, the time required is stable and lower than that of other comparison methods, and the detection errors are all lower than 10%. The proposed method has high detection efficiency and low detection errors.

Rectorite drilling fluid: high-temperature resistance for geothermal applications

This study aims to resolve some existing limitations of geothermal drilling and exploration of high-temperature drilling fluid systems, such as complex formulation, inconvenient preparation, inappropriate selection of additives, unstable high-temperature performance, and high costs, through theoretical, experimental, and microstructural analysis. The slurry-making ability of several relevant clay minerals were theoretically analyzed based on their slurry-making performance and rheological behavior under various high-temperature environments (i.e., 180, 200, and 220 °C). Rectorite was selected as the appropriate slurry-making clay mineral and was modified organically using a single colloidal material (LP). In addition, suitable high-temperature additives were selected to improve the performance of the drilling fluid system by reducing filtration loss and preventing borehole collapse during geothermal drilling. The proposed drilling fluid system exhibited a simple system structure, excellent rheological performance under high temperatures, reduced filtration loss, and inhibitory and anti-pollution characteristics. The microstructure of rectorite was analyzed using x-ray diffraction, infrared spectrometry, and environmental scanning electron microscopy. It was verified that the microstructural mechanisms improved the temperature resistance of the drilling fluid system, thus helping to solve the critical problems in high-temperature geothermal well drilling and other production processes.

Design and Safety Considerations for Coiled Tubing Operations in Geothermal Wells

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper OTC 30408, “Design and Safety Considerations To Perform Coiled Tubing Operations in Large-Diameter, High-Temperature Geothermal Wells,” by Ishaan Singh, SPE, Danny Aryo Wijoseno, SPE, and Kellen Wolf, Schlumberger, et al., prepared for the 2020 Offshore Technology Conference Asia, originally scheduled to be held in Kuala Lumpur, 17–19 August. The paper has not been peer reviewed. Copyright 2020 Offshore Technology Conference. Reproduced by permission. The productive section in a high-pressure, high-temperature (HP/HT) geothermal Field A in the Philippines features shallow and deep reservoirs separated by a low-permeability formation. However, recent years have seen a reduction in production levels. To activate and enhance well production, coiled tubing (CT) nitrogen-lift operations were required. CT simulations were combined with simulations from the geothermal reservoir to overcome modeling limitations. The outcome helped the design of a new cooling-loop system and allowed optimization of the nitrogen-lift technique. As a result, two large-diameter geothermal wells were lifted safely with 2-in. CT. Introduction This study describes design and safety considerations in performing CT operations in high-temperature, large- diameter geothermal wells. The customized high-temperature-grade seal material was chosen to withstand high bottomhole temperatures (BHT) (600°F), and a heat exchanger riser system was designed and tested on the job to handle high-surface-temperature steam (350–400°F), thus mitigating potential well-control incidents. Challenges of Seal Damage Caused by High Surface Temperatures in Live Well Intervention The CT interventions in quenched HP/HT geothermal wells reduce the risk of surface equipment failure. The seal material readily available in the market is rated to 250°F, but, if quenching is not possible, the high-temperature steam (approximately 350–400°F) may flow into the pressure-control equipment, leading to seal damage and CT contingencies. At high temperatures (400°F), these seals are unusable. It becomes essential to use a surface heat exchange riser (HER) system to prevent this issue. Design and Execution of HER Systems in Field A To avoid any well contingency and to keep pressure-control equipment safe, HER systems can be used. Some basic designs for HERs are described in the complete paper. For this study, a customized 4.06-in. HER cooling system (Design 1, shown in Fig. 1) was designed to accommodate 2-in. CT pipe. Design 1 was chosen from an evaluation of three design candidates outlined in the complete paper. The wellhead stack featured seal elements rated to high temperatures (400°F). To prevent high- temperature steam from entering the wellhead stack, the blowout preventer, and other surface- equipment elements, an efficient HER system was designed wherein, while the CT is still in the well performing CT operations, the cold water can be pumped into the CT-stack annulus from the top flow cross through the cooling riser to the bottom flow cross and back to the return tank. The temperature of the cooling loop was continuously monitored to ensure that it was well below 212°F (the boiling point of water).

Technology Focus: Coiled Tubing (June 2021)

Last year, this feature opened, almost inevitably, with comments on the effects the COVID-19 pandemic might have on our industry. Unfortunately, a year later, we probably have all experienced the effects, both personal and work-related. One of these effects is that there has been re-evaluation of what’s important. To understand what is important takes some reflection and evaluation of the past. In previous features, the focus has been on what is new or reimagined. Therefore, I thought that, in selecting papers for this year’s feature, it would be useful to select ones that look at coiled tubing operations performed and that have been evaluated in one way or another. From Bolivia comes a paper that reviews some 25 well interventions performed. Most of these operations are of a type that will be familiar to the reader. Also, some of the challenges that were faced in performing these coiled tubing operations will be familiar. These operations used a range of established types of coiled tubing operations and blended the techniques to meet particular operating conditions, especially location and logistics challenges. All conclusions and best practices that resulted, however, may not be familiar to all readers. During the past few years, many coiled tubing papers have focused on the use of coiled tubing in multizone fracturing operations, especially plug milling. An area of coiled tubing use in fracturing operations that has had less of an audience recently has been the use of coiled tubing in annular fracturing operations. This activity is still routinely being performed, particularly in Canada. The question has long existed about how the pipe is being eroded. In the related paper in this feature, the authors explain how they have tried to answer that question and have shared some of their review insights. In the past decade, coiled tubing size, weight, and grade all have continued to increase. Looking back at this trend and thinking about its effect on pressure control equipment led the developers in the third of this year’s papers to work on solutions for shear rams. This is particularly relevant after having just passed the 11th anniversary of the tragic Macondo disaster. Again, this year, I ask everyone to stay well. Recommended additional reading at OnePetro: www.onepetro.org. OTC 30408 Design and Safety Considerations To Perform Coiled Tubing Operations in Large-Diameter, High-Temperature Geothermal Wells by Ishaan Singh, Schlumberger, et al. SPE 204446 Implementing Business Analytics Software To Optimize Coiled Tubing Operations: A Digital Approach to Operations Efficiency by Xaymaca Bautista Alarcon, Royal Oaks Energy Services, et al. SPE 203272 The Reinvention of a Well-Established Coiled Tubing Intervention Work Flow Creates New Perspectives for Acidizing Openhole Horizontal Tight Carbonate Water Injectors by Sameer Punnapala, ADNOC, et al.

Performance Prediction of a Turbodrill Based on the Properties of the Drilling Fluid

High-temperature geothermal well resource exploration faces high-temperature and high-pressure environments at the bottom of the hole. The all-metal turbodrill has the advantages of high-temperature resistance and corrosion resistance and has good application prospects. Multistage hydraulic components, consisting of stators and rotors, are the key to the turbodrill. The purpose of this paper is to provide a basis for designing turbodrill blades with high-density drilling fluid under high-temperature conditions. Based on the basic equation of pseudo-fluid two-phase flow and the modified Bernoulli equation, a mathematical model for the coupling of two-phase viscous fluid flow with the turbodrill blade is established. A single-stage blade performance prediction model is proposed and extended to multi-stage blades. A Computational Fluid Dynamics (CFD) model of a 100-stage turbodrill blade channel is established, and the multi-stage blade simulation results for different fluid properties are given. The analysis confirms the influence of fluid viscosity and fluid density on the output performance of the turbodrill. The research results show that compared with the condition of clear water, the high-viscosity and high-density conditions (viscosity 16 mPa∙s, density 1.4 g/cm3) will increase the braking torque of the turbodrill by 24.2%, the peak power by 19.8%, and the pressure drop by 52.1%. The results will be beneficial to the modification of the geometry model of the blade and guide the on-site application of the turbodrill to improve drilling efficiency.

Monitoring of a reverse cement job in a high-temperature geothermal environment

Cementing operations in wellbores, especially for long casings, are often challenging and prone to deficiencies when not properly planned and executed. While exploring for and exploiting of geothermal resources at temperatures above the critical point of water was attempted in different drilling projects in recent years, the well design, and especially the procedure to run and cement long production casings became a key challenge for drilling engineers. For the first time, a reverse cementing job for a 2.97 km long production casing in a high-temperature geothermal well could be monitored and analyzed using a combination of permanently installed distributed fiber optic and electronic sensors as well as conventional well logging equipment. Data from the permanently installed sensors were used to monitor and evaluate the cementation process as well as the onset of the cement hydration. Based on the data, the understanding of downhole fluid dynamics during cementation could be improved. Our analysis suggests that the cement was diluted during cement placement and partly lost into the formation. These findings can help to better prepare for future drilling ventures under similar downhole conditions.

Thermo-mechanical tensile testing of geothermal casing materials

Ultra-high temperature geothermal wells (>450 °C) have a large potential for increased energy yield as compared to conventional high-temperature geothermal wells (200-300 °C), but several research challenges must be resolved before robust operation in this temperature range can be achieved. In this study, yield- and tensile strength data for several relevant carbon steels and corrosion resistant alloys are generated as a step on the way to enable design of collapse- and tensile capacity for geothermal casings exposed to temperatures up to 500-550 °C. The experiments extend the data set listed in NZS 2403:2015 by providing data for higher temperatures and different material classes. It is found that the carbon steels follow the same near linear decay in strength as the NZS 2403:2015 curves up to 350 °C, and then display a significant drop in tensile strength at higher temperatures, particularly for the lower strength steels. The alloys with high nickel content work harden significantly more than the carbon steels at high temperatures and they tend to retain their strength at temperatures above 350 °C. The tested titanium alloy shows high yield strength and low work-hardening at 500 °C and in contrast to the tested nickel alloys, do not display dynamic strain ageing.

An Axial and Torsional Percussion Hammer with Considerable Potential to Increase the Drilling Speed of High-Temperature Geothermal Wells

Geothermal energy is a kind of green and sustainable energy and an essential alternative energy in the future. Improving the drilling speed of geothermal wells is helpful for the efficient exploitation of geothermal resources. Axial & Torsional Percussion Hammer (ATPH) was proposed in this paper for drilling enhancement. ATPH can convert the kinetic energy of the drilling fluid to percussion load, and improve the rock-breaking efficiency of the bit. Because of its mechanical seal design, it can operate efficiently at temperatures over 200 °C, which proves that it can be used in geothermal wells. The large eddy simulation (LES) method is chosen to calculate the percussion load characteristics of the ATPH oscillator, including its main frequency and amplitude. In the field drilling experiments of two high-temperature wells, ATPH showed better ROP enhancement ability and longer working life than PDM. In the well interval drilled by ATPH, the maximum temperature at the well bottom reached 202.54 °C.