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1
Zhang, Liang, Songhe Geng, Jun Kang, Jiahao Chao, Linchao Yang, and Fangping Yan. "Experimental Study on the Heat Exchange Mechanism in a Simulated Self-Circulation Wellbore." Energies 13, no. 11 (June 6, 2020): 2918. http://dx.doi.org/10.3390/en13112918.
Повний текст джерелаАнотація:
Self-circulation wellbore is a new technique for geothermal development in hot dry rocks (HDR), which uses a U-shape channel composed of tubing and casing as the heat exchanger. In this study, a self-circulation wellbore in HDR on a laboratory scale was built, and a serial of experiments were conducted to investigate the heat exchange law and the influencing factors on the heat mining rate of the wellbore. A similarity analysis was also made to estimate the heat-mining capacity of the wellbore on a field scale. The experimental results show that the large thermal conductivity and heat capacity of granite with high temperature can contribute to a large heat-mining rate. A high injection rate can cause a high convective heat transfer coefficient in wellbore, while a balance is needed between the heat mining rate and the outlet temperature. An inner tubing with low thermal conductivity can significantly reduce the heat loss to the casing annulus. The similarity analysis indicates that a heat mining rate of 1.25 MW can be reached when using a 2000 m long horizontal well section in a 150 °C HDR reservoir with a circulation rate of 602.8 m3/day. This result is well corresponding to the published data.
2
Sharma, P., A. Q. Al Saedi, and C. S. Kabir. "Geothermal energy extraction with wellbore heat exchanger: Analytical model and parameter evaluation to optimize heat recovery." Renewable Energy 166 (April 2020): 1–8. http://dx.doi.org/10.1016/j.renene.2020.11.116.
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3
Cheng, Sharon W. Y., Jundika C. Kurnia, Agus P. Sasmito, and Luluan A. Lubis. "The Effect of Triangular Protrusions on Geothermal Wellbore Heat Exchanger from Retrofitted Abandoned Oil Wells." Energy Procedia 158 (February 2019): 6061–66. http://dx.doi.org/10.1016/j.egypro.2019.01.511.
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Alimonti, C., and E. Soldo. "Study of geothermal power generation from a very deep oil well with a wellbore heat exchanger." Renewable Energy 86 (February 2016): 292–301. http://dx.doi.org/10.1016/j.renene.2015.08.031.
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5
Gizzi, Martina, Glenda Taddia, and Stefano Lo Russo. "Reuse of Decommissioned Hydrocarbon Wells in Italian Oilfields by Means of a Closed-Loop Geothermal System." Applied Sciences 11, no. 5 (March 9, 2021): 2411. http://dx.doi.org/10.3390/app11052411.
Повний текст джерелаАнотація:
Geological and geophysical exploration campaigns have ascertained the coexistence of low to medium-temperature geothermal energy resources in the deepest regions of Italian sedimentary basins. As such, energy production based on the exploitation of available geothermal resources associated with disused deep oil and gas wells in Italian oilfields could represent a considerable source of renewable energy. This study used information available on Italian hydrocarbon wells and on-field temperatures to apply a simplified closed-loop coaxial Wellbore Heat Exchanger (WBHE) model to three different hydrocarbon wells located in different Italian oilfields (Villafortuna-Trecate, Val d’Agri field, Gela fields). From this study, the authors have highlighted the differences in the quantity of potentially extracted thermal energy from different analysed wells. Considering the maximum extracted working fluid temperature of 100 °C and imagining a cascading exploitation mode of the heat accumulated, for Villafortuna 1 WBHE was it possible to hypothesise a multi-variant and comprehensive use of the resource. This could be done using existing infrastructure, available technologies, and current knowledge.
6
Immanuel, L. G., G. S. F. U. Almas, and T. M. Dimas. "Preliminary design study of wellbore heat exchanger in binary optimization for low – medium enthalpy to utilize non-self discharge wells in Indonesia." IOP Conference Series: Earth and Environmental Science 254 (April 29, 2019): 012016. http://dx.doi.org/10.1088/1755-1315/254/1/012016.
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7
Carpenter, Chris. "Flow Simulator Optimizes Geothermal Heat Extraction From End-of-Life Wells." Journal of Petroleum Technology 75, no. 01 (January 1, 2023): 67–69. http://dx.doi.org/10.2118/0123-0067-jpt.
Повний текст джерелаАнотація:
_ This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 208928, “Optimizing Geothermal Heat Extraction From End-of-Life Oil and Gas Wells Using a Transient Multiphase Flow Simulator,” by David Sask, SPE, David Sask Technology; Peter Graham, Algar Geothermal; and Carlos Nascimento, SPE, Schlumberger. The paper has not been peer reviewed. _ The complete paper presents results from evaluation of the rate of thermal energy that can be extracted under various completion scenarios using a transient flow simulator. This evaluation was conducted on closed-loop systems wherein the fluids are contained within the wellbore and surface facilities and do not involve any formation fluids. The use of a multiphase flow simulator for this study provides a road map for understanding thermal energy potential and important variables when considering extraction of geothermal energy from existing oil and gas wells. Introduction In Western Canada, there are, at the time of writing, more than 130,000 inactive and suspended wells. This includes more than 3,000 orphan wells but excludes an additional 115,000 abandoned wells. For some of these wells, end-of-life liability can be turned into an asset. This paper presents an overview of one system for extracting geothermal energy from a single well configuration using a closed-loop mode of operation. Equipment and Processes The technology described in the paper calls for inserting an insulated inner tubing inside the existing production casing immediately above the sealed base of the well. Cooler water is injected down the annulus of the coaxial configuration. As the water descends, it collects heat from zones where the adjacent rock is hotter. At the base of the well, the heated water is then redirected to surface from the open base of the insulated inner tubing. At surface, the heat is recovered, and the resulting cooled water is reinjected into the well to complete the circuit. This closed-loop process has little pump demand because there is no hydraulic head. This technology was developed in the late 1990s but did not gain much traction because of the excessive cost of drilling, inadequate and expensive insulated tubing, and poor heat and temperature recoveries. The technology has developed enhancements to overcome the latter limitation. One key enhancement is to operate the well in two different modes. The first mode operates as a storage mode during periods when no heat demand exists. Water is pumped into the annulus of the well and returned to surface within the insulated inner tube. Once the heated water reaches the surface, it is reinjected directly into the same well without any heat being recovered at surface. As the returning hot water descends, it transfers heat to the adjacent cement and rock, which creates a heat jacket in the upper sections of the well. When heat demand returns, the second mode, referred to as extraction mode, commences. The only change is that the ascending heated water is redirected to a heat exchanger, which extracts only heat sufficient to meet demand; then, the partially heated water is returned to the well to collect additional heat.
8
Yang, Mou, Yingfeng Meng, Gao Li, Yongjie Li, Ying Chen, Xiangyang Zhao, and Hongtao Li. "Estimation of Wellbore and Formation Temperatures during the Drilling Process under Lost Circulation Conditions." Mathematical Problems in Engineering 2013 (2013): 1–11. http://dx.doi.org/10.1155/2013/579091.
Повний текст джерелаАнотація:
Significant change of wellbore and surrounding formation temperatures during the whole drilling process for oil and gas resources often leads by annulus fluid fluxes into formation and may pose a threat to operational security of drilling and completion process. Based on energy exchange mechanisms of wellbore and formation systems during circulation and shut-in stages under lost circulation conditions, a set of partial differential equations were developed to account for the transient heat exchange process between wellbore and formation. A finite difference method was used to solve the transient heat transfer models, which enables the wellbore and formation temperature profiles to be accurately predicted. Moreover, heat exchange generated by heat convection due to circulation losses to the rock surrounding a well was also considered in the mathematical model. The results indicated that the lost circulation zone and the casing programme had significant effects on the temperature distributions of wellbore and formation. The disturbance distance of formation temperature was influenced by circulation and shut-in stages. A comparative perfection theoretical basis for temperature distribution of wellbore-formation system in a deep well drilling was developed in presence of lost circulation.
9
Alimonti, C., E. Soldo, D. Bocchetti, and D. Berardi. "The wellbore heat exchangers: A technical review." Renewable Energy 123 (August 2018): 353–81. http://dx.doi.org/10.1016/j.renene.2018.02.055.
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Zheng, Miaozi, Renjie Yang, Jianmin Zhang, Yongkai Liu, Songlin Gao, and Menglan Duan. "An Interface Parametric Evaluation on Wellbore Integrity during Natural Gas Hydrate Production." Journal of Marine Science and Engineering 10, no. 10 (October 18, 2022): 1524. http://dx.doi.org/10.3390/jmse10101524.
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Based on the whole life cycle process of the economic exploitation of natural gas hydrate, this paper proposes the basic problem of stabilizing the wellbore for the basic conditions that must be met to ensure the integrity of the wellbore for exploitation: revealing the complex mechanism of fluid–solid–heat coupling in the process of the physical exchange of equilibrium among gas, water, and multiphase sand flows in the wellbore, hydrate reservoir, and wellbore, defining the interface conditions to ensure wellbore stability during the entire life cycle of hydrate production and proposing a scientific evaluation system of interface parameters for wellbore integrity.
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Shushakov, Oleg, Oleg Bocharov, Radu Coman, and Holger Thern. "HEAT EXCHANGE IMPACT ON NMR LOGGING WHILE DRILLING." Interexpo GEO-Siberia 2, no. 3 (2019): 38–46. http://dx.doi.org/10.33764/2618-981x-2019-2-3-38-46.
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The effect of temperature on nuclear magnetic resonance (NMR) logging while drilling (LWD) has been studied. Heat conduction and permeability effects in the near wellbore invasion zone have been taken into account. Analytical solutions and numerical calculations have been exemplified and verified with the use of NMR LWD field data.
12
Tang, Hewei, Boyue Xu, A. Rashid Hasan, Zhuang Sun, and John Killough. "Modeling wellbore heat exchangers: Fully numerical to fully analytical solutions." Renewable Energy 133 (April 2019): 1124–35. http://dx.doi.org/10.1016/j.renene.2018.10.094.
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13
Tang, Yang, Haoyu Xiong, Yin He, Shunxiao Huang, and Yuan Wang. "Spray Cooling Schemes and Temperature Field Analysis of Ultra-High-Temperature Production Wells in Underground Coal Gasification." Processes 10, no. 6 (June 8, 2022): 1149. http://dx.doi.org/10.3390/pr10061149.
Повний текст джерелаАнотація:
In underground coal gasification (UCG), it is essential for UCG production to accurately control the temperature of the gas produced at the wellhead of the production well and correctly calculate the variation law of the temperature field in the whole wellbore. UCG wellbore structures use three wellbore sprayed water cooling schemes. These schemes consider the heat exchange mechanism between the wellbore and the formation, the division of the production wellbore into the spray chamber section and the non-spray section, and the established temperature field model of the whole wellbore. The research shows that, due to the large temperature gradient formed in the wellbore heat transfer route under the spray tubing water injection cooling scheme, the temperature of the produced gas drops the most. The annular water injection cooling scheme can protect the cement sheath to a certain extent and is easier to implement; therefore, it is more suitable to use this scheme to cool the production well. It is feasible to control the temperature of the production wellhead by controlling the temperature of the spray chamber. The greater the daily output of produced gas or the thermal conductivity of the tubing, the smaller the temperature change between the bottom hole and the wellhead, and the more the spray water temperature rises.
14
Banks, Jonathan, Spencer Poulette, Jens Grimmer, Florian Bauer, and Eva Schill. "Geochemical Changes Associated with High-Temperature Heat Storage at Intermediate Depth: Thermodynamic Equilibrium Models for the DeepStor Site in the Upper Rhine Graben, Germany." Energies 14, no. 19 (September 24, 2021): 6089. http://dx.doi.org/10.3390/en14196089.
Повний текст джерелаАнотація:
The campus of the Karlsruhe Institute of Technology (KIT) contains several waste heat streams. In an effort to reduce greenhouse gas emissions by optimizing thermal power consumption on the campus, researchers at the KIT are proposing a ‘DeepStor’ project, which will sequester waste heat from these streams in an underground reservoir during the summer months, when the heat is not required. The stored heat will then be reproduced in the winter, when the campus’s thermal power demand is much higher. This paper contains a preliminary geochemical risk assessment for the operation of this subsurface, seasonal geothermal energy storage system. We used equilibrium thermodynamics to determine the potential phases and extent of mineral scale formation in the plant’s surface infrastructure, and to identify possible precipitation, dissolution, and ion exchange reactions that may lead to formation damage in the reservoir. The reservoir in question is the Meletta Beds of the Upper Rhein Graben’s Froidefontaine Formation. We modeled scale- and formation damage-causing reactions during six months of injecting 140 °C fluid into the reservoir during the summer thermal storage season and six months of injecting 80 °C fluid during the winter thermal consumption season. Overall, we ran the models for 5 years. Anhydrite and calcite are expected mineral scales during the thermal storage season (summer). Quartz is the predicted scale-forming mineral during the thermal consumption period (winter). Within ~20 m of the wellbores, magnesium and iron are leached from biotite; calcium and magnesium are leached from dolomite; and sodium, aluminum, and silica are leached from albite. These reactions lead to a net increase in both porosity and permeability in the wellbore adjacent region. At a distance of ~20–75 m from the wellbores, the leached ions recombine with the reservoir rocks to form a variety of clays, i.e., saponite, minnesotaite, and daphnite. These alteration products lead to a net loss in porosity and permeability in this zone. After each thermal storage and production cycle, the reservoir shows a net retention of heat, suggesting that the operation of the proposed DeepStor project could successfully store heat, if the geochemical risks described in this paper can managed.
15
Jing, Jun, Hongbin Shan, Xiaohua Zhu, Yixiang Huangpu, and Yang Tian. "Wellbore Temperature and Pressure Calculation of Offshore Gas Well Based on Gas–Liquid Separated Flow Model." Processes 10, no. 10 (October 10, 2022): 2043. http://dx.doi.org/10.3390/pr10102043.
Повний текст джерелаАнотація:
Compared with land wells, the production environment and reservoir depth of offshore oil and gas wells are more complex and shallower. Further, HPHT production fluid there will produce strong temperature and pressure disturbance that affects the wellbore, which easily generates wellbore safety problems, such as wellhead growth and leakage caused by the incompatible deformation of casing and cement sheath. Therefore, obtaining an accurate wellbore temperature and pressure field is the key to implementing a wellbore safety assessment. Based on the gas–liquid two-phase separated method, this paper established an improved calculation model of wellbore temperature and pressure field for offshore HPHT wells. This model also takes into account the heat transfer environment characteristics of “formation-seawater-air” and the influence of well structure. Compared with the measured data of the case well, the error of temperature and pressure calculation results of the improved model are only 0.87% and 2.46%. Further, its calculation accuracy is greatly improved compared to that of the traditional gas–liquid homogeneous flow calculation model. Based on this model, the influencing factors of wellbore temperature and pressure in offshore gas wells are analyzed. The results show that forced convection heat exchange between seawater–air and wellbore is stronger than that between wellbore and formation. Reducing the gas–liquid ratio of the product can effectively reduce wellbore temperature and increase wellbore pressure. The gas production has a significant impact on the wellbore temperature. When the gas production rises from 10 × 104⋅m3/d to 60 × 104⋅m3/d, the wellhead temperature rises from 63 °C to 99 °C. However, due to the mutual influence of friction pressure drop and hydrostatic pressure drop, wellbore pressure increases first and then decreases with the increase in gas production. The improved model can provide a more accurate estimate of the time to reach the rated wellhead temperature. Meanwhile, this model displays accurate theoretical support for the rational formulation of the production plan after the well opening, so as to avoid excessive restrictions on the initial production rate.
16
Nalla, Gopi, G. Michael Shook, Gregory L. Mines, and K. Kit Bloomfield. "Parametric sensitivity study of operating and design variables in wellbore heat exchangers." Geothermics 34, no. 3 (June 2005): 330–46. http://dx.doi.org/10.1016/j.geothermics.2005.02.001.
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Ding, Liangliang, Jiyang Rao, and Chengyu Xia. "Transient prediction of annular pressure between packers in high-pressure low-permeability wells during high-rate, staged acid jobs." Oil & Gas Science and Technology – Revue d’IFP Energies nouvelles 75 (2020): 49. http://dx.doi.org/10.2516/ogst/2020046.
Повний текст джерелаАнотація:
For high-pressure low-permeability wells, wellbore temperature drops drastically in high-rate and multistage acid fracturing process. Under the combined action of the swelling of tubing string and the contraction of annular fluid between packers, annular pressure between packers undergoes violent transient change in staged acid jobs, thereby deteriorating loading on the tubing string and packers. Based on the principle of energy conservation and wellbore heat conduction, the transient prediction of two-dimensional (2D) wellbore temperature field under pumping injection condition was established by considering the effects of heat generated by friction and convection heat exchange. Moreover, the effects of wellbore temperature/pressure changes on the annular volume between packers were analyzed. Furthermore, in combination with the transient prediction model of wellbore temperature, PVT state equation of annular fluid, the calculation model of tubing string radial deformation and the transient seepage equation of the formation, the transient prediction model of annular pressure between packers in high-pressure low-permeability wells was established. Finally, by taking a high-pressure low-permeability well as an example, annular pressure between packers was calculated and the forces on the packers and tubing string were analyzed. According to the prediction results, the tubing string, which was regarded to be safe using conventional design method, exhibited an extremely high risk of failure after taking into account the decrease in annular pressure between packers. Therefore, the decrease in annular pressure should be fully considered in the design of tubing string for high-pressure low-permeability wells in multistage acid fracturing process. In combination with sensitivity analysis results, it can be concluded that formation permeability, injection rate and formation pressure all affected the change in annular pressure between packers.
18
Zhao, Zhen, Guangxiong Qin, Huijuan Chen, Linchao Yang, Songhe Geng, Ronghua Wen, and Liang Zhang. "Numerical Simulation and Economic Evaluation of Wellbore Self-Circulation for Heat Extraction Using Cluster Horizontal Wells." Energies 15, no. 9 (April 30, 2022): 3296. http://dx.doi.org/10.3390/en15093296.
Повний текст джерелаАнотація:
The heat extraction capacity of the self-circulation wellbore is usually small because of the limited heat exchange area. In the paper, the cluster horizontal well group technology was proposed to enhance the heat extraction capacity and decrease the unit cost. Based on the mathematical model of heat transfer, a numerical simulation model of wellbore self-circulation for heat extraction using cluster horizontal wells was established to study the influence of main factors on heat extraction capacity. The economic analysis of heat extraction and power generation was carried out according to the model of the levelized cost of energy. The results show that the enhancement of heat extraction capacity is limited after the injection rate exceeds 432 m3/d (1.59 MW/well). The inflection point of the injection rate can be determined as the design basis for injection-production parameters. When the thermal conductivity of formation increases from 2 to 3.5 W/(m·K), the heat extraction rate will increase 1.45 times, indicating that the sandstone reservoirs with good thermal conductivity can be preferred as the heat extraction site. It is recommended that the well spacing of cluster wells is larger than 50 m to avoid the phenomenon of thermal short circuit between wells, and the thermal conductivity of the tubing should be less than 0.035 W/(m·K) to reduce the heat loss of heat-carrying fluid in the tubing. Compared with a single well, a cluster horizontal well group can reduce the unit cost of heat extraction and power generation by 24.3% and 25.5%, respectively. The economy can also be improved by optimizing heat-carrying fluids and retrofitting existing wells.
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Zhang, Yingqi, Lehua Pan, Karsten Pruess, and Stefan Finsterle. "A time-convolution approach for modeling heat exchange between a wellbore and surrounding formation." Geothermics 40, no. 4 (December 2011): 261–66. http://dx.doi.org/10.1016/j.geothermics.2011.08.003.
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LI, Jiashu, Chuanshan DAI, and Haiyan LEI. "The influence of thermal boundary conditions of wellbore on the heat extraction performance of deep borehole heat exchangers." Geothermics 100 (March 2022): 102325. http://dx.doi.org/10.1016/j.geothermics.2021.102325.
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21
Hasan, A. Rashid, C. Shah Kabir, and Dongqing Lin. "Analytic Wellbore Temperature Model for Transient Gas-Well Testing." SPE Reservoir Evaluation & Engineering 8, no. 03 (June 1, 2005): 240–47. http://dx.doi.org/10.2118/84288-pa.
Повний текст джерелаАнотація:
Summary Questions arise whether bottomhole pressures (BHPs), derived from their wellhead counterpart (WHP), lend themselves to transient analysis. That is because considerable heat exchange may affect the wellbore-density profile, thereby making the WHP translation a nontrivial exercise. In other words, gas density is dependent on both spatial locations in the wellbore and time during transient testing. Fully coupled wellbore/reservoir simulators are available to tackle this situation. However, they are not readily adaptable for their numeric formulations. This paper presents analytic expressions, derived from first principles, for computing time-dependent fluid temperature at any point in the wellbore during both drawdown and buildup testing. The simplicity of the analytic expressions for Tf (z, t) is profound in that one can compute flowing or shut-in BHPs on a spreadsheet. Two tests were considered to verify the new analytic formulae. In one case, measurements were available at both sandface and surface, and partial wellhead information was available in the other case. We explored a parametric study to assess whether a given wellbore/reservoir system will lend itself to wellhead measurements for valid transient analysis. Reservoir flow capacity (kh) turned out to be the most influential variable. Introduction Gas-well testing is sometimes conducted by measuring pressures at the wellhead. Both cost and circumstance (high pressure/high temperature, or HP/HT)often necessitate WHP monitoring or running the risk of having no tests at all. Methods for computing BHP from wellhead pressures for steady flow in gas wells are well established in the literature. For dry-gas wells, the widely used method of Cullender and Smith is most accurate, as confirmed by subsequent studies. For wet gas, either a two-phase model, such as the one offered by Govier and Fogarasi, or the modified Cullender-Smith approach appears satisfactory. However, these methods apply to steady-state gas flow and implicitly presuppose that the wellbore is in thermal equilibrium with the formation. These assumptions may be tested during a transient test. That is because unsteady-state wellbore heat transfer occurs even after the cessation of the wellbore-fluid-storage period. Steady-state fluid flow ordinarily implies the absence of wellbore effects from the viewpoint of transient testing. Consequently, one needs to develop working equations by conserving mass, momentum, and energy in the wellbore to capture physical phenomena. Earlier, we presented a forward model and showed its capability to reproduce BHP, WHP, and wellhead temperature (WHT) given reservoir and wellbore parameters. However, translation of WHP to BHP was not demonstrated clearly. The intent of this work is to present a framework for rigorous computation of BHP from WHP. To achieve this objective, we developed analytic expressions for depth- and time-dependent fluid temperature during both flow and shut-in tests. These temperature relations, in turn, allow computation of gas density and, therefore, pressure at any point in the wellbore.
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Xu, Tianfu, Zixu Hu, Bo Feng, Guanhong Feng, Fengyu Li, and Zhenjiao Jiang. "Numerical evaluation of building heating potential from a co-axial closed-loop geothermal system using wellbore–reservoir coupling numerical model." Energy Exploration & Exploitation 38, no. 3 (November 25, 2019): 733–54. http://dx.doi.org/10.1177/0144598719889799.
Повний текст джерелаАнотація:
Geothermal energy is one of the most potential renewable energy resources. How to efficiently extract and utilize geothermal energy has been a worldwide hot topic. Co-axial closed-loop geothermal system is a novel method using a continuously closed wellbore without water exchange with. It is more suitable for reservoirs with medium or low temperature and permeability because many problems could be avoided such as lack of in situ groundwater or low infectivity of the reservoir. Many companies and research institutes have applied closed-loop geothermal system in building heating engineering and some fine results have been gained. However, in practical engineering construction, the area of a closed-loop geothermal system heating system is a very important parameter. It directly determines the cost accounting and initial design of the project. Accurate and reliable estimation of heating capacity becomes very important. In this study, a wellbore–reservoir coupling model is established, which is calibrated using measured data from a short-term field trial operation. We have carried out mixed convective–conductive fluid-flow modeling using a wellbore flow model for TOUGH2 called T2Well to investigate the heat extraction performance of closed-loop geothermal system. The system evolution and the effect of flow rate and injection temperature on heat production performance are discussed. The result shows that the intermittent production cycles are more beneficial for heat extraction and system maintenance, and the temperature recovery between two heating seasons is enough to maintain system heating. And we can calculate that a geothermal well can ensure heating of buildings of 10,000–20,000 m2 and the heating area of intermittent operation is 4000 m2 more than continuous operation. Besides, the sensitivity analysis of parameters is also carried out.
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Sun, Fengrui, Yuedong Yao, Guozhen Li, and Xiangfang Li. "Numerical Simulation of Supercritical-Water Flow in Concentric-Dual-Tubing Wells." SPE Journal 23, no. 06 (August 25, 2018): 2188–201. http://dx.doi.org/10.2118/191363-pa.
Повний текст джерелаАнотація:
Summary Much work has been performed on the modeling of saturated/superheated-steam flow in wellbores. At present, the study on supercritical-water (SCW) flow in wellbores, especially concentric-dual-tubing wells (CDTWs), is very limited. In this paper, work was performed on modeling of SCW flow in CDTWs. First, a comprehensive mathematical model comprising a pipe-flow model, supercritical-fluid model, and heat-transfer model is established. In the model, the heat exchange between the integral joint tubing (IJT) and annuli is taken into consideration. Numerical solutions of SCW flow in CDTWs were obtained with a straightforward numerical method. Then, sensitivity analysis was conducted. The following results were found: SCW in annuli (with a higher temperature) releases thermal energy to SCW in the IJT, which causes increase of temperature in IJT. As a result, SCW density in the IJT has a decrease. The density gradient near the wellhead increases with increasing of injection rate. When the injection temperature in the IJT is larger than that in annuli, SCW density increases with well depth near the wellhead.
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Li, Xin, Jie Zhang, Cuinan Li, Ben Li, Haoyang Zhao, Rongxin Li, and Qi Qi. "Variation characteristics of coal-rock mechanical properties under varying temperature conditions for Shanxi Linfen coalbed methane well in China." Journal of Petroleum Exploration and Production Technology 11, no. 7 (May 30, 2021): 2905–15. http://dx.doi.org/10.1007/s13202-021-01186-2.
Повний текст джерелаАнотація:
AbstractIn the actual exploitation process of coalbed methane (CBM), as the fluid in the wellbore continues to circulate, the surrounding rock of the CBM well will continuously exchange heat with the fluid in the wellbore, resulting in continuous changes in the temperature of the surrounding rock itself. Linfen, Shanxi is the main exploitation area for CBM in China. This paper aims further to improve the exploitation efficiency of CBM in this area and conducts experimental research on the change characteristics of coal-rock mechanical properties under varying temperature conditions. The experimental results show that under constant pressure conditions, the higher the temperature, the lower the stress value when the coal-rock breaks. In the process of reaching peak strength, the higher the temperature, the higher the proportion of coal-rock plastic deformation in its entire deformation stage. The compressive strength, elastic modulus, and main crack length of coal-rock will decrease with temperature. The Poisson's ratio and primary fracture angle will increase with the increase of experimental temperature.
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Li, Hong, Kun Ji, Ye Tao, and Chun’an Tang. "Modelling a Novel Scheme of Mining Geothermal Energy from Hot Dry Rocks." Applied Sciences 12, no. 21 (November 6, 2022): 11257. http://dx.doi.org/10.3390/app122111257.
Повний текст джерелаАнотація:
On the basis of a conceptual model for an Excavation based Enhanced Geothermal System (EGS-E), which proposed to extract heat from Hot Dry Rock at depth through dominantly adopting shaft, roadways, and caved rock failure techniques but not depending on either wellbore drilling or fracturing stimulation, a novel extensive version of heat extraction is proposed in this paper. Considering its mechanical stability issues, the new scheme contains two fields apart away: the ones are near-field by piping flow to touch the tunnel wall; the others are far-field through filling and driving fluid within the voids of collapsed rock. The former is represented as a tunnel unit being installed hollow linear, which can extract and produce heat precisely according to structural design and accurate operative prediction. The latter is represented as interconnective fissures being induced by stope excavation due to gravitational weight and unloading of a deep-buried squeeze. The EGS-E uses a two-stage heat exchange system of “fluid-rock” and “fluid-fluid.” Then, a 3D transient thermal-hydraulic model is established to demonstrate the heat extraction performance. The temperature field and accumulated heat energy are investigated. The modeling work provides a tentative workflow to simulate an EGS-E system and, most probably for the first time, demonstrated that the deep underground Hot Dry Rock heat mining turns out to be preliminarily studied in a quantitative way.
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Xu, Tianfu, Huixing Zhu, Guanhong Feng, Yilong Yuan, and Hailong Tian. "On Fluid and Thermal Dynamics in a Heterogeneous CO2 Plume Geothermal Reservoir." Geofluids 2017 (2017): 1–12. http://dx.doi.org/10.1155/2017/9692517.
Повний текст джерелаАнотація:
CO2 is now considered as a novel heat transmission fluid to extract geothermal energy. It can achieve both the energy exploitation and CO2 geological sequestration. The migration pathway and the process of fluid flow within the reservoirs affect significantly a CO2 plume geothermal (CPG) system. In this study, we built three-dimensional wellbore-reservoir coupled models using geological and geothermal conditions of Qingshankou Formation in Songliao Basin, China. The performance of the CPG system is evaluated in terms of the temperature, CO2 plume distribution, flow rate of production fluid, heat extraction rate, and storage of CO2. For obtaining a deeper understanding of CO2-geothermal system under realistic conditions, heterogeneity of reservoir’s hydrological properties (in terms of permeability and porosity) is taken into account. Due to the fortissimo mobility of CO2, as long as a highly permeable zone exists between the two wells, it is more likely to flow through the highly permeable zone to reach the production well, even though the flow path is longer. The preferential flow shortens circulation time and reduces heat-exchange area, probably leading to early thermal breakthrough, which makes the production fluid temperature decrease rapidly. The analyses of flow dynamics of CO2-water fluid and heat may be useful for future design of a CO2-based geothermal development system.
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Renaud, Theo, Patrick G. Verdin, and Gioia Falcone. "Conjugated Numerical Approach for Modelling DBHE in High Geothermal Gradient Environments." Energies 13, no. 22 (November 21, 2020): 6107. http://dx.doi.org/10.3390/en13226107.
Повний текст джерелаАнотація:
Geothermal is a renewable energy source that can be untapped through various subsurface technologies. Closed geothermal well solutions, such as deep geothermal heat exchangers (DBHEs), consist of circulating a working fluid to recover the available heat, with less dependency on the local geological settings than conventional geothermal systems. This paper emphasizes a double numerical method to strengthen the assessment of DBHE performances. A computational fluid dynamics (CFD) commercial software and the 1D coupled wellbore-reservoir geothermal simulator T2Well have been used to investigate the heat transfer and fluid flow in a vertical DBHE in high geothermal gradient environments. The use of constant water properties to investigate the energy produced from DBHEs can lead to underestimating the overall heat transfer at high temperature and low mass flow rate. 2D axisymmetric CFD modelling improves the understanding of the return flow at the bottom of the DBHE, readjusting and better estimating the pressures losses commonly obtained with 1D modelling. This paper highlights the existence of convective cells located at the bottom of the DBHE internal tubing, with no significant effects due to the increase of injected water flow. Both codes are shown to constrain the numerical limitations to access the true potential of geothermal heat extraction from DBHEs in high geothermal gradient environments and demonstrate that they can be used for geothermal energy engineering applications.
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Ren, Keda, and Chengzheng Cai. "Numerical Investigation into the Distributions of Temperature and Stress around Wellbore during the Injection of Cryogenic Liquid Nitrogen into Hot Dry Rock Reservoir." Mathematical Problems in Engineering 2021 (June 19, 2021): 1–13. http://dx.doi.org/10.1155/2021/9913321.
Повний текст джерелаАнотація:
Cryogenic liquid nitrogen fracturing is expected to provide an effective stimulation method for hot dry rock reservoirs to increase heat production. This paper establishes a three-dimensional model to calculate the distributions of temperature and stress of the reservoir rock when liquid nitrogen is injected into the wellbore. The sensitivity of different parameters and water fracturing to the stress state is studied. The results indicate that when liquid nitrogen is injected into the bottom of well, a huge heat exchange occurs on the rock surface, which generates great thermal stress on the fluid-solid interface, and the value of thermal stress exceeds the tensile strength of rock. For the effect of parameters, the primitive temperature of the rock has a significant impact on the value of maximum principal stress. The pressure drop and ambient pressure affect the thermal stress slightly. At the same time, a series of experiments are conducted to validate the effect of thermal stress induced by liquid nitrogen injection on the rock fracture. As the temperature rises, the shale samples are broken more severely at the action of thermal stress. Thus, the study of liquid nitrogen fracturing provides a scientific and effective method for geothermal exploitation.
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Detienne, J.-L., Max Creusot, Nicolas Kessler, Bernard Sahuquet, and J.-L. Bergerot. "Thermally Induced Fractures: A Field-Proven Analytical Model." SPE Reservoir Evaluation & Engineering 1, no. 01 (February 1, 1998): 30–35. http://dx.doi.org/10.2118/30777-pa.
Повний текст джерелаАнотація:
Summary Thermally induced fracturing (TIF) during water injection is a well-established phenomenon. TIF modeling implies solving equations simultaneously that conventional petroleum engineering applications deal with separately. Combining these equations leads to very complex computer programs. This has led to the need for a simple model, which we present in this paper. Coupling analytical expressions representing each of these phenomena, rather than the basic physical equations, has led to a computer program that can be run on a modern desk-top computer. This program has successfully matched the daily wellhead pressure and injection rate during a period of 3 to 5 years for injection wells in complex sandstone/dolomite reservoirs. The model can be used for injection-well monitoring as well as in a predictive mode when planning new water-injection projects. The algorithm is sufficiently simple to be implemented in a conventional reservoir simulator. Introduction The concept of a constant productivity index, extrapolated below bubble point by use of Vogel's curve, is one of the fundamental tools of petroleum engineering. One of its most interesting features is that it depends on reservoir and reservoir properties alone. It is independent of downstream wellbore equipment and surface facilities. One would like to be able to use a similar concept for water injection wells, but, unfortunately, calculating an injectivity index, turns out to be much more complex. Water available for injection is often much colder than the reservoir, and numerous temperature-induced phenomena often having opposite effects occur within the first few days or weeks of injection. From the beginning of injection, the bottomhole flowing temperature decreases and finally reaches a stabilized value depending on surface and reservoir temperature, injection rate, depth, and well completion. During that time, matrix flows will have a reducing effect on injectivity. This is because, in such conditions, the bottom-hole viscosity can often increase two- to four-fold. Also, when water displaces oil, there is a relative-permeability effect tied to the growth of the zone from which oil has been displaced. At the same time, mechanical effects will tend to decrease injectivity inversely. The reservoir stress near the well is reduced when the reservoir is cooled, and fracturing will occur if the reservoir stress falls below bottomhole flowing pressure. This phenomena is called TIF.1–6 It leads to a continuous increase in injectivity when fracture develops. In fact, the final reduced stress is the result of a thermal reducing effect (thermoelasticity) and a fluid-pressure increasing effect (poroelasticity) at the injector. In general, however, the latter is much smaller. As we have shown, the injectivity index cannot be calculated without taking into account the wellbore pressure and temperature performance. Injectivity therefore depends on the situation both upstream (wellbore equipment and surface facilities) and downstream (reservoir properties). Modeling water injectivity therefore leads to very large computer programs in which the complexities of both reservoir models and fracturing simulators are intermingled. The pioneering work of Hagoort7 and Perkins and Gonzalez8 on thermo-poroelasticity were followed by more refined models, such as that published by Dikken and Niko.9 More recently, Settari10,11 and Clifford12 presented three-dimensional (3D) fracturing calculations. This paper presents a model that uses simple analytical formulas representing all these intermingled physical processes that influence the injectivity index. The model has been programmed on a PC and used to match the performance of wells injecting into a complex sandstone/dolomite reservoir in the Gulf of Guinea. Well behavior is modeled as a sequence of timesteps. The basic assumption is that steady-state equilibrium is reached at the end of each timestep. This is a good approximation for long-term well behavior. We do not aim to simulate short-term phenomena such as those encountered during well tests; in our model, reservoir pressure transients are ignored, as are the mechanics of fracture propagation. Our model starts at the wellhead, with a given injection rate and wellhead temperature. The model calculates a wellhead pressure, which can be compared to measurements. The least known parameters are adjusted within their plausible range of values until a satisfactory match is obtained. The algorithm also has been programmed so that when wellhead pressure and temperature are given as data, the model calculates the injection rate. This calculation mode is of particular interest when planning waterfloods. Part 1: The Model Wellbore Temperature Profile. The first task is to calculate bottomhole flowing temperature, ?wf, from surface temperature, injection rate, and wellbore equipment. A linear geothermal gradient is assumed. Bottomhole flowing temperature is calculated from wellhead temperature by dividing the tubing into 25 segments. We use the transient heat-exchange solution13 between each segment and the surrounding earth to calculate the quantity of heat that reaches the water in the tubing. This solution assumes that the well rate is constant. To cope with rate-varying behavior, an effective injection time has been defined with the cumulative injection Wi and the current injection rate i : As long as injection rate does not decrease too abruptly, this simple algorithm gives satisfactory results. The reason that such a simple algorithm works is that most of the heat exchange between an injection well and the surrounding earth takes place at depth, where the well geometry is simplest: a tubing and one casing. On the contrary, such a simple calculation is impossible on a production well because, in this case, the biggest temperature contrast and therefore most of the heat exchange are close to the surface where well geometry and its surroundings are most variable. This algorithm does not give realistic results when the injection rate is reduced abruptly (for instance, when the well is shut in). A smoothing function has therefore been introduced to limit the change in ?wf during any one timestep. Calculation Assuming Radial Injection. We use the term radial injection when flow is radially outwards from the well; the alternative, when the reservoir is fractured by the water injection process, is called fractured injection.
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Zhang, Yi, Jiexiang Wang, Peng Jia, Xiao Liu, Xuxu Zhang, Chang Liu, and Xiangwei Bai. "Viscosity Loss and Hydraulic Pressure Drop on Multilayer Separate Polymer Injection in Concentric Dual-Tubing." Energies 13, no. 7 (April 2, 2020): 1637. http://dx.doi.org/10.3390/en13071637.
Повний текст джерелаАнотація:
Multilayer separate polymer injection in concentric dual-tubing is a special method for enhancing oil recovery in later development stage of the multilayer formation. During the injection process, heat exchange occurs among the inner tubing, tubing annulus and formation, making the thermal transfer process more complicated than traditional one. This work focuses on the polymer flowing characteristics during the multilayer separate polymer flooding injection process in the wellbore. A temperature–viscosity numerical model is derived to investigate the influencing factors on polymer dual-tubing injection process. Then, an estimate-correct method is introduced to derive the numerical solutions. Several influences have been discussed, including the axial temperature distribution, viscosity distribution, pressure drop, and flow pattern of polymer. Results show that under low injecting rates, below 5 m3/d, formation temperature will greatly decrease the polymer viscosity. When the injecting rates above 20 m3/d, the polymer just decreases 1–3 mPa·s at the bottom of well, which is really small. Additionally, the temperature distribution, the coefficient of friction under different injecting rates have been discussed. Generally, this method provides a new way to analyze thermal conductivity during the polymer injection process which is meaningful for polymer flooding in the oilfield application.
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Shen, Lan, Huijing Tan, You Ye, and Wei He. "Using Fumed Silica to Develop Thermal Insulation Cement for Medium–Low Temperature Geothermal Wells." Materials 15, no. 14 (July 21, 2022): 5087. http://dx.doi.org/10.3390/ma15145087.
Повний текст джерелаАнотація:
During geothermal energy development, the bottom high-temperature fluid continuously exchanges heat with the upper low-temperature wellbore and the stratum during its rising process. Thermal insulation cement (TIC) can increase the outlet temperature, thus effectively reducing the heat loss of the geothermal fluid and improving energy efficiency. In this study, vitrified microbubbles (VMB) were screened out by conducting an orthogonal test of compressive strength (CS) and thermal conductivity (TC) on three inorganic thermal insulation materials (VMB, expanded perlite (EP), and fly-ash cenosphere (FAC)). Fumed silica (FS) was introduced into the cement with VMBs, as its significant decreasing effect on the TC. Moreover, a cement reinforcing agent (RA) and calcium hydroxide [CH] were added to further improve the CS of TIC at 90 °C. The fresh properties, CS, TC, hydration products, pore-size distribution, and the microstructure of the cement were investigated. As a result, a TIC with a TC of 0.1905 W/(m·K) and CS of 5.85 MPa was developed. The main conclusions are as follows: (1) Increasing the mass fraction of the thermal insulation material (TIM) is an effective method to reduce TC. (2) The CH content was reduced, but the C–S–H gel increased as FS content increased due to the pozzolanic reaction of the FS. (3) As the C–S–H gel is the main product of both the hydration and pozzolanic reactions, the matrix of the cement containing 60% FS and VMBs was mainly composed of gel. (4) The 10% RA improved the cement fluidity and increased the CS of TIC from 3.5 MPa to 5.85 MPa by promoting hydration.
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Alimonti, C., D. Berardi, D. Bocchetti, and E. Soldo. "Coupling of energy conversion systems and wellbore heat exchanger in a depleted oil well." Geothermal Energy 4, no. 1 (September 19, 2016). http://dx.doi.org/10.1186/s40517-016-0053-9.
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Doran, Hannah R., Theo Renaud, Gioia Falcone, Lehua Pan, and Patrick G. Verdin. "Modelling an unconventional closed-loop deep borehole heat exchanger (DBHE): sensitivity analysis on the Newberry volcanic setting." Geothermal Energy 9, no. 1 (February 15, 2021). http://dx.doi.org/10.1186/s40517-021-00185-0.
Повний текст джерелаАнотація:
AbstractAlternative (unconventional) deep geothermal designs are needed to provide a secure and efficient geothermal energy supply. An in-depth sensitivity analysis was investigated considering a deep borehole closed-loop heat exchanger (DBHE) to overcome the current limitations of deep EGS. A T2Well/EOS1 model previously calibrated on an experimental DBHE in Hawaii was adapted to the current NWG 55-29 well at the Newberry volcano site in Central Oregon. A sensitivity analysis was carried out, including parameters such as the working fluid mass flow rate, the casing and cement thermal properties, and the wellbore radii dimensions. The results conclude the highest energy flow rate to be 1.5 MW, after an annulus radii increase and an imposed mass flow rate of 5 kg/s. At 3 kg/s, the DBHE yielded an energy flow rate a factor of 3.5 lower than the NWG 55-29 conventional design. Despite this loss, the sensitivity analysis allows an assessment of the key thermodynamics within the wellbore and provides a valuable insight into how heat is lost/gained throughout the system. This analysis was performed under the assumption of subcritical conditions, and could aid the development of unconventional designs within future EGS work like the Newberry Deep Drilling Project (NDDP). Requirements for further software development are briefly discussed, which would facilitate the modelling of unconventional geothermal wells in supercritical systems to support EGS projects that could extend to deeper depths.
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Zhang, Liang, Linchao Yang, Songhe Geng, and Shaoran Ren. "Comparative Experiment of Wellbore Self-Circulation Heat Mining Capacity with Different Heat-Carrying Fluids." Lithosphere 2021, Special 5 (August 27, 2021). http://dx.doi.org/10.2113/2021/2953458.
Повний текст джерелаАнотація:
Abstract Based on the principle of wellbore self-circulation heat mining, the evaluation experiments of local wellbore self-circulation heat exchange laws and influencing factors were carried out. Water, SCCO2, R134a, and heat transfer oil were screened as the heat-carrying fluids. The heat exchange laws and heat mining capacity of these four heat carrying fluids were analyzed and compared, and their heat mining rates at the field scale were estimated using the similarity criterion method according to the experimental results. The results show that R134a and heat transfer oil can obtain the largest outlet temperature and the largest heat loss ratio, while the water can achieve a higher heat mining rate and a larger convective heat transfer coefficient than the other three fluids. The heat mining capacity of CO2 is significantly affected by the injection pressure. It is necessary to optimize the injection pressure larger than critical point to achieve the best heat mining performance. When the water is selected as the heat-carrying fluid, the heat mining rate can reach more than 1 MW if a horizontal wellbore with a length of 2000 m is applied for wellbore self-circulation at the field scale.
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Lei, Hongwu. "Performance Comparison of H2O and CO2 as the Working Fluid in Coupled Wellbore/Reservoir Systems for Geothermal Heat Extraction." Frontiers in Earth Science 10 (February 18, 2022). http://dx.doi.org/10.3389/feart.2022.819778.
Повний текст джерелаАнотація:
CO2 is considered as a novel heat-transmission fluid for extracting geothermal energy from enhanced geothermal systems (EGS), attributed to its high compressibility, expansivity and low viscosity in comparison to water. In order to compare the performance of CO2 and H2O as the working fluid in EGS, a classical five-spot model based on the geologic and geothermal conditions at the Songliao Basin, China, was constructed. Results obtained from the coupled wellbore/reservoir model revealed that the net heat extraction and flow rate are greater for CO2 than for H2O at a fixed operation pressure difference between the injection and production wellheads. However, the wellhead temperature is far lower for CO2 than for H2O due to the strong Joule–Thomson effect of CO2 in the wellbore. Moreover, a stronger pressure change in the wellbore is observed by using CO2, attributed to the gravity and high flow velocity of CO2; this pressure change induces a drop in the frictional pressure. For CO2, the enthalpy change in the wellbore is mainly contributed by the gravitational potential, while for H2O, it is contributed by the gravitational potential and lateral heat exchange. The heat extraction performance depends on the operation pressure difference and injection temperature for H2O-based EGS, while it depends on the wellhead pressures of both the injection and production wells as well as the injection temperature for CO2-based EGS. A high operation pressure is favorable for improving the heat extraction performance (especially the production temperature) for CO2. With the temperature drop limitation at the downhole of the production well, the heat extraction performance is better by using H2O than that by using CO2 as the working fluid. However, the low-power consumption for maintaining fluid circulation demonstrates the application potential of CO2-based EGS.
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"Parametric sensitivity study of operating and design variables in wellbore heat exchangers." Fuel and Energy Abstracts 47, no. 2 (March 2006): 104–5. http://dx.doi.org/10.1016/s0140-6701(06)80699-5.
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de Pater, C. J. (Hans), and Josef R. Shaoul. "Stimulation for geothermal wells in the Netherlands." Netherlands Journal of Geosciences 98 (2019). http://dx.doi.org/10.1017/njg.2019.8.
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Abstract Hydraulic fracturing is a long-established method of stimulating a well to improve the inflow or outflow potential. Hydraulic fracturing is the most successful stimulation method used by the oil and gas industry, and is also used for water injection and production wells around the world, even for drinking-water wells. Hydraulic fracturing creates a crack in the earth that is then filled with a highly conductive material (proppant). This fracture has a large inflow area compared to an unstimulated wellbore and provides a high-permeability path for the fluid to flow in or out of the reservoir. Hydraulic fracturing has a long history of being used in hot dry rock (HDR) geothermal applications since the 1980s (Murphy & Fehler, 1986). In those often very tight reservoirs, the aim is to create fracture networks that generate the reservoir flow capacity. In high-permeability formations, fracturing can potentially double the productivity of a well. In low-permeability formations, well performance can be increased by a factor of 5–10 in most cases. In this paper, we focus on two different scenarios of geothermal stimulation. The first is for permeable, porous formations where the heat exchange happens through the perfect contact between the fluid and the porous reservoir. Stimulation may then be necessary to create a small fracture if the pressure drop near the well is too large due to insufficient reservoir permeability. The other scenario is a formation at great depth, where the formation permeability is so extremely small that very long propped fractures would be needed to obtain sufficient flow or even where the porous system does not provide sufficient heat exchange but the heat exchange has to be facilitated by an artificial or stimulated fracture network: a so-called Enhanced Geothermal System. For porous, permeable formations we will present examples of fracture treatments that can increase the flow rate so that the economics of the project is improved. In some formations, stimulation is then a contingency in case of poorer than expected reservoir quality. A worst-case well with a large skin value of 20 can perform with stimulation like a base-case unstimulated well. In other formations, stimulation will be integral to well design in order to optimise the project performance. For those cases the Coefficient of Performance can be improved from 7 to 25 with the aid of stimulation. In Ultra-Deep Geothermal (UDG) recovery, the targets are reservoirs below 4000 m, because industrial heat demand requires a minimum temperature of 120°C up to 250°C. For an economic business case, the rate over a period of 15 to 25 years should be from 150 to 450 m3 h−1, depending on the boundary conditions. Shallower reservoirs in the Netherlands often show very high permeability, but at great depth the target layers could have very low permeability (Veldkamp et al., 2018). Several stimulation methods can be used, of which hydraulic fracture stimulation with water (proppantless) is the primary candidate. Other stimulation methods are propped fracturing in sandstone, acid fracturing in carbonates and thermal stimulation. For a geological play that is attractive for UDG in the Netherlands, the most likely stimulation method is with water fracturing, because propped fracturing would require a huge amount of proppant that is very costly. Based on analogues and conceptual designs, the expected flow rate is estimated under selected boundary conditions.