Relevant bibliographies by topics / Drilling Fluid Temperature

Contents

  1. Journal articles
  2. Dissertations / Theses
  3. Book chapters
  4. Conference papers
  5. Reports

Academic literature on the topic 'Drilling Fluid Temperature'

Author: Grafiati
Published: 4 June 2021
Last updated: 19 February 2022

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Journal articles on the topic "Drilling Fluid Temperature"

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Yue, Qian Sheng, Qing Zhi Yang, Shu Jie Liu, Bao Sheng He, and You Lin Hu. "Rheological Properties of Water Based Drilling Fluid in Deep Water Drilling Conditions." Applied Mechanics and Materials 318 (May 2013): 507–12. http://dx.doi.org/10.4028/www.scientific.net/amm.318.507.

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The rheological property of the drilling fluid was one of the focus problems in deep-water drilling, which was widely concerned. In the article, the viscosity-temperature properties of commonly used water soluble polymeric solution, polymeric brine solution, bentonite slurry, polyacrylamide-potassium chloride drilling fluid with different densities and water-base drilling fluid systems commonly used for China offshore well drillings were studied. 4°C-to-20°C viscosity ratio and 4°C-to-20°C YP ratio were used to judge the thickening level of drilling fluids due to low temperature. The experimental results show that on the condition of without considering the influence of pressure on the rheological property of water-base drilling fluid, its viscosity and yield point raised obviously with the decrease of temperature, but the increase level is proximately the same, its 4°C-to-20°C apparent viscosity ratio is basically within the 1.50. Analysis indicates that the viscosity of water-base drilling fluid depends on the viscosity of dispersed media. The performance of water medium determines the viscosity-temperature property of the water-based drilling fluid. It is proposed that in deep water drillings, if a water-base drilling fluid is used, it is not necessary to emphasize the influence of deep water and low temperature on the flowability. On the condition of guaranteeing wellbore stability and borehole cleaning, it is more suitable for using the water-base drilling fluid with low viscosity and low gel strength for deep water well drillings.
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Talalay, Pavel, Zhengyi Hu, Huiwen Xu, Dahui Yu, Lili Han, Junjie Han, and Lili Wang. "Environmental considerations of low-temperature drilling fluids." Annals of Glaciology 55, no. 65 (2014): 31–40. http://dx.doi.org/10.3189/2014aog65a226.

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AbstractThe introduction of low-temperature fluid into boreholes drilled in ice sheets helps to remove drilling cuttings and to prevent borehole closure through visco-plastic deformation. Only special fluids, or mixtures of fluids, can satisfy the very strict criteria for deep drilling in cold ice. The effects of drilling fluid on the natural environment are analyzed from the following points of view: (1) occupational safety and health; (2) ozone depletion and global warming; (3) chemical pollution; and (4) biological pollution. Traditional low-temperature drilling fluids (kerosene-based fluids with density additives, ethanol and n-butyl acetate) cannot be qualified as intelligent choices from the safety, environmental and technological standpoints. This paper introduces a new type of low-temperature drilling fluid composed of synthetic ESTISOLTM esters, which are non-hazardous substances. ESTISOLTM 140 mixtures with ESTISOLTM 165 or ESTISOLTM F2887 have an acceptable density and viscosity at low temperature. To avoid the potential for biological contamination of the subglacial environment, the borehole drilling fluid should be treated carefully on the surface.
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Ahmed, Alaa, Amin Sharifi Haddad, Roozbeh Rafati, Ahmed Bashir, Ahmed M. AlSabagh, and Amany A. Aboulrous. "Developing a Thermally Stable Ester-Based Drilling Fluid for Offshore Drilling Operations by Using Aluminum Oxide Nanorods." Sustainability 13, no. 6 (March 19, 2021): 3399. http://dx.doi.org/10.3390/su13063399.

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Esters were found to be promising alternatives to oil, as a constituent of drilling fluids, due to their biodegradability and bioaccumulation attributes. In this study, we used ethyl octanoate ester (EO) as a low molecular weight synthetic oil for formulating an ester-based drilling fluid (EBDF). Aluminum oxide nanorods (nanoparticles) were introduced as a Pickering emulsion stabilizer. Like the commercial emulsifiers, they showed that they stabilized the invert emulsion drilling fluid in our study. The rheological and filtration properties of the EBDF were tested at normal pressure and three temperatures: low temperature deepwater (LT) conditions of 2.6 °C, normal pressure and normal temperature (NPNT) conditions of 26.8 °C, and elevated temperature conditions of 70 °C. To enhance the stability and filtration properties of the drilling fluid, aluminum oxide nanoparticles (NPs) were used. An optimum concentration of 1 wt% was found to provide superior rheological performance and higher stability than samples without NPs at NPNT, LT, and elevated temperature conditions. Steadier gel rheology was exhibited at elevated temperature conditions, and a slow rate of an increasing trend occurred at the lower temperatures, with increasing NP concentrations up to 1.5 wt%. Filtration loss tests presented a reduction of fluid loss with increasing the NP concentration. The results demonstrate that a reduction of up to 45% was achieved with the addition of 1 wt% NP. These results show that nano-enhancement of ethyl octanoate drilling fluids would suffice to provide a wider range of operational temperatures for deepwater drilling operations by providing better thermal stability at elevated temperatures and maintaining stability at lower temperatures.
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Dong, Pu, Ren, Zhai, Gao, and Xie. "Thermoresponsive Bentonite for Water-Based Drilling Fluids." Materials 12, no. 13 (June 30, 2019): 2115. http://dx.doi.org/10.3390/ma12132115.

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As an important industrial material, bentonite has been widely applied in water-based drilling fluids to create mud cakes to protect boreholes. However, the common mud cake is porous, and it is difficult to reduce the filtration of a drilling fluid at high temperature. Therefore, this paper endowed bentonite with a thermo response via the insertion of N-isopropylacrylamide (NIPAM) monomers. The interaction between NIPAM monomers and bentonite was investigated via Fourier infrared spectroscopy (FTIR), isothermal adsorption, and X-ray diffraction (XRD) at various temperatures. The results demonstrate that chemical adsorption is involved in the adsorption process of NIPAM monomers on bentonite, and the adsorption of NIPAM monomers accords with the D–R model. With increasing temperature, more adsorption water was squeezed out of the composite when the temperature of the composite exceeded 70 °C. Based on the composite of NIPAM and bentonite, a mud cake was prepared using low-viscosity polyanionic cellulose (Lv-PAC) and initiator potassium peroxydisulfate (KPS). The change in the plugging of the mud cake was investigated via environmental scanning electron microscopy (ESEM), contact angle testing, filtration experiments, and linear expansion of the shale at various temperatures. In the plugging of the mud cake, a self-recovery behavior was observed with increasing temperature, and resistance was observed at 110 °C. The rheology of the drilling fluid was stable in the alterative temperature zone (70–110 °C). Based on the high resistance of the basic drilling fluid, a high-density drilling fluid (ρ = 2.0 g/cm3) was prepared with weighting materials with the objective of drilling high-temperature formations. By using a high-density drilling fluid, the hydration expansion of shale was reduced by half at 110 °C in comparison with common bentonite drilling fluid. In addition, the rheology of the high-density drilling fluid tended to be stable, and a self-recovery behavior was observed.
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Barrak, Ibrahim, Gábor Braunitzer, József Piffkó, and Emil Segatto. "Heat Generation and Temperature Control during Bone Drilling for Orthodontic Mini-Implants: An In Vitro Study." Applied Sciences 11, no. 16 (August 21, 2021): 7689. http://dx.doi.org/10.3390/app11167689.

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Background: The purpose of our in vitro study was to evaluate the impact of different irrigation fluid temperatures in combination with different drilling speeds on intraosseous temperature changes during mini-implant site preparation. Methods: Porcine ribs were used as bone specimens. Grouping determinants were as follows: irrigation fluid temperature (10 and 20 °C) and drilling speed (200, 600, 900, and 1200 RPM). The axial load was controlled at 2.0 kg. Temperature measurements were conducted using K-type thermocouples. Results: Extreme increments were observed only in the unirrigated groups. Irrigation invariably made a significant difference within groups defined by the same drilling speed. The comparison of the different temperature irrigation fluids (10 and 20 °C) in combination with the same drilling speed (200, 600, 900, or 1200 rpm) resulted in a statistically significant difference between the two different temperatures, whereas the use of irrigation fluid at a controlled room temperature of 20 °C showed significantly higher temperature changes. Conclusions: Based on the results of the study, we conclude that irrigation while preparing a pilot hole for a self-tapping orthodontic miniscrew is of utmost importance, even at low drilling speeds. The temperature of the cooling fluid does influence local temperature elevation to a significant extent.
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Liu, Jingping, Zhiwen Dai, Ke Xu, Yuping Yang, Kaihe Lv, Xianbin Huang, and Jinsheng Sun. "Water-Based Drilling Fluid Containing Bentonite/Poly(Sodium 4-Styrenesulfonate) Composite for Ultrahigh-Temperature Ultradeep Drilling and Its Field Performance." SPE Journal 25, no. 03 (January 10, 2020): 1193–203. http://dx.doi.org/10.2118/199362-pa.

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Summary The rapidly increasing global oil/gas demand and gradual depletion of shallow reservoirs require the development of deep oil/gas reservoirs and geothermal reservoirs. However, deep drilling suffers from drilling-fluid failures under ultrahigh temperature, which cause serious accidents such as wellbore collapse, stuck pipe, and even blowouts. In this study, we revealed the role of polymeric additives in improving the ultrahigh-temperature tolerance of bentonite-based drilling fluids, aiming to provide practical and efficient solutions to the failure of drilling fluids in severe conditions. By adding poly(sodium 4-styrenesulfonate) (PSS) to the original drilling fluid containing bentonite, significant fluid loss—as a consequence of bentonite-particle flocculation causing drilling-fluid shear-stress reduction and high-permeability mud—is successfully suppressed even at temperature as high as 200°C. This drilling fluid containing PSS was applied in the drilling of high-temperature deep wells in Xinjiang province, China, and exhibited high effectiveness in controlling accidents including overflow and leakage. NOTE: A supplementary file is available in the Supporting Information section.
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Xu, Shiguang, Junjie Ba, Xianfeng Chen, Ting Zheng, Yaochi Yang, and Liang Guo. "Predicting Strata Temperature Distribution from Drilling Fluid Temperature." International Journal of Heat and Technology 34, no. 2 (June 30, 2016): 345–50. http://dx.doi.org/10.18280/ijht.340227.

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Lan, Pixiang, Kyriaki Polychronopoulou, Larry L. Iaccino, Xiaoying Bao, and Andreas A. Polycarpou. "Elevated-Temperature and -Pressure Tribology of Drilling Fluids Used in Oil and Gas Extended-Reach-Drilling Applications." SPE Journal 23, no. 06 (August 29, 2018): 2339–50. http://dx.doi.org/10.2118/191380-pa.

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Summary Extended-reach-drilling (ERD) wells are expensive and challenging; however, in special situations, compared with conventional drilling, ERD wells are more environmentally friendly and cost-effective. Application of drilling fluids with good lubrication for ERD is one of the most important methods to facilitate longer total depth (TD) of the wells. To better simulate the elevated-temperature environment in the borehole, this study proposes a method to perform tribological studies of drilling fluids at temperatures higher than 100°C by conducting experiments in a high-chamber-pressure environment, which can suppress the evaporation of the drilling fluid at high temperatures. Two lubricant additives were studied, and the results showed that, for the drilling fluid at elevated temperatures, a prototype additive (Additive A) reduced the coefficient of friction (COF) significantly by 44.8%, whereas a commercial additive (Additive B) caused only a slight reduction of the COF by 4%. After the tribological experiments, the wear mechanisms of the additives and abrasive particles were investigated with scanning electron microscopy (SEM) and X-ray photoelectron spectroscopy (XPS).
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Gao, Yonghai, Baojiang Sun, Boyue Xu, Xingru Wu, Ye Chen, Xinxin Zhao, and Litao Chen. "A Wellbore/Formation-Coupled Heat-Transfer Model in Deepwater Drilling and Its Application in the Prediction of Hydrate-Reservoir Dissociation." SPE Journal 22, no. 03 (October 20, 2016): 756–66. http://dx.doi.org/10.2118/184398-pa.

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Summary On the basis of the wellbore and reservoir heat-transfer process during deepwater drilling, a heat-transfer model between wellbore and formation is built up for two different conditions: without riser and with riser. Wellbore and formation temperature distributions under different drilling-fluid-injection temperatures, flow rates, circulating times, and drilling depths are simulated by use of this model. Taking the hydrate-phase equilibrium into consideration, a possible region of hydrate-formation dissociation is analyzed, and effective methods are proposed to control the hydrate dissociation. The results indicate that, during shallow formation drilling, the increase of drilling-fluid flow rate will cause the wellbore temperature to rise, but below the hydrate-dissociation temperature in the whole process; during deep-formation drilling, drilling fluid is heated, and the heat is transferred from the deeper formation to the shallower formation through fluid circulation. Thus, the hydrate-reservoir temperature increases gradually along the wellbore radial direction. Hydrates will dissociate after the hydrate equilibrium temperature is reached; this may cause wellbore collapse or methane leak from the reservoir and result in disaster. To control hydrate dissociation during deepwater drilling, attention should be paid to the period of deep-formation drilling. Sensitivity studies indicate that the risk of hydrate dissociation rises as the drilling-fluid-injection temperature, flow rate, and circulating time increase.
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Almahdawi, Dr Faleh H. M., Dr Mohammed N. Husain Al Hasani, and Haider Salem Jasim. "Tragacanth Gum As Local Alternatives To Improve Viscosity And Filtration Control." Journal of Petroleum Research and Studies 8, no. 4 (May 1, 2021): 1–15. http://dx.doi.org/10.52716/jprs.v8i4.259.

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Today oil industry faces a lot of problems and lost money during drilling and completion operation, so that the studies and researches must including the ways and solutions that lead to decrease the costs. In this research we tried to find local alternative material instead of foreign drilling fluid materials that is used in drilling fluids and will help to save a lot of money by decrease oil well drilling cost because of the high cost of drilling fluid materials which represent now about 30 % of total cost for drilling oil well. The local alternatives is Ore polymers ( plant origin) called : TRAGACANTH GUM. In this study we investigated the local material and tested it under API Specification for Drilling Fluids Materials. Also tested sample of mud after add local material (TRAGACANTH GUM.) for weighted concentrations (0.5, 1.5, 2, 2.5 and 3 gm.) to show physical and rheological properties. The third part of this study tested sample of mud after add local material (TRAGACANTH GUM.) under different temperatures values and up to 70°C (this temperature is near for some formations temperature in Iraqi oil fields ) to show temperature effect on this material. A comparison between the local alternative and similar foreign materials for same sample was done to show physical and rheological properties. The results approved that, the local alternatives can used as filtration control materials for water based drilling fluid. Also the local alternatives increased viscosity as minimal for water based drilling fluids, So it can be used as part alternative for Bentonite to increase viscosity by increasing Yield point and decreasing solids concentration in drilling fluids so it have positive effect to save Rig equipment’s and Pay-zone.
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Dissertations / Theses on the topic "Drilling Fluid Temperature"

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Apak, Esat Can. "A Study On Heat Transfer Iside The Wellbore During Drilling Operations." Master's thesis, METU, 2007. http://etd.lib.metu.edu.tr/upload/12608048/index.pdf.

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Analysis of the drilling fluid temperature in a circulating well is the main objective of this study. Initially, an analytical temperature distribution model, which utilizes basic energy conservation principle, is presented for this purpose. A computer program is written in order to easily implement this model to different cases. Variables that have significant effect on temperature profile are observed. Since the verification of the analytical model is not probable for many cases, a computer program (ANSYS) that uses finite element method is employed to simulate different well conditions. Three different wells were modeled by using rectangular FLOTRAN CFD element that has four nodes. Maximum drilling fluid temperature data corresponding to significant variables is collectedfrom these models. This data is then used to develop an empirical correlation in order to determine maximum drilling fluid temperature. The proposed empirical correlation can estimate the temperature distribution within the wellbore with an average error of less than 16%, and maximum drilling fluid temperature with an average error of less than 7 %.
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Ibeh, Chijioke Stanley. "Investigation on the effects of ultra-high pressure and temperature on the rheological properties of oil-based drilling fluids." [College Station, Tex. : Texas A&M University, 2007. http://hdl.handle.net/1969.1/ETD-TAMU-2569.

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Paula, Junior Rubens Ribeiro de. "Modelagem de controle de poço com fluidos de perfuração não aquosos e estudos de casos." [s.n.], 2008. http://repositorio.unicamp.br/jspui/handle/REPOSIP/263123.

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Orientador: Paulo Roberto Ribeiro
Dissertação (mestrado) - Universidade Estadual de Campinas. Faculdade de Engenharia Mecanica e Instituto de Geociencias
Made available in DSpace on 2018-08-12T18:02:11Z (GMT). No. of bitstreams: 1 PaulaJunior_RubensRibeirode_M.pdf: 2205711 bytes, checksum: 8d99ae4553a735e11f7c7662c3878d30 (MD5) Previous issue date: 2008
Resumo: O trabalho apresenta uma revisão da literatura sobre poços HPHT, abordando o desafio na construção dos mesmos, com ênfase no aspecto de segurança de poço. Do ponto de vista de desenvolvimento, o trabalho envolveu a implementação de um modelo de controle de poços com fluidos de perfuração não aquosos em software existente (Unikick), que incorpora correlações empíricas derivadas de resultados experimentais com n-parafina e diesel. A importância dessa implementação deve-se ao fato de que a previsão do comportamento das pressões, vazões e volumes desenvolvidos em um poço durante a detecção e circulação de um kick de gás, é muito útil para o engenheiro de perfuração que poderá tomar decisões sobre a maneira mais segura de lidar com estas situações. Alguns estudos de casos foram realizados através de comparação dos resultados obtidos pelo Unikick e outros simuladores disponíveis e análise de sensibilidade de parâmetros. Nessa análise, foram simuladas circulações de kicks em terra e marítimos em várias lâminas d'água, com trajetórias verticais e horizontais e observados os comportamentos de parâmetros importantes durante o controle do poço, como a pressão no choke, pit gain e vazão de gás na superfície.
Abstract: The first part of the work provides a review of the literature on HPHT wells, addressing the challenge in the construction of these wells, emphasizing the safety aspects. From the point of view of development, the work involved an implementation of a well control model for nonaqueous drilling fluids using existing software (Unikick), that incorporates empirical correlations derived from experimental results with n-paraffin and diesel. The importance of this implementation is due to the fact that the estimation of the behavior of pressures, flow rates and volumes developed inside a well during gas kick detection and circulation out of the well is very useful for the drilling engineer to take decisions about the safest way to handle these situations. Some case studies were performed through the comparison of simulated results from Unikick and other simulators available and a sensitivity analysis. In this analysis, some kick circulations were simulated in onshore and offshore wells with various water depths, vertical and horizontal trajectories, when important parameters of well control were observed, such as choke pressure pit gain and gas flow rate at surface.
Mestrado
Explotação
Mestre em Engenharia Mecânica
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Thepchatri, Kritatee 1984. "Thermoporoelastic Effects of Drilling Fluid Temperature on Rock Drillability at Bit/Formation Interface." Thesis, 2012. http://hdl.handle.net/1969.1/148164.

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A drilling operation leads to thermal disturbances in the near-wellbore stress, which is an important cause of many undesired incidents in well drilling. A major cause of this thermal disturbance is the temperature difference between the drilling fluid and the downhole formation. It is critical for drilling engineers to understand this thermal impact to optimize their drilling plans. This thesis develops a numerical model using partially coupled thermoporoelasticity to study the effects of the temperature difference between the drilling fluid and formation in a drilling operation. This study focuses on the thermal impacts at the bit/formation interface. The model applies the finite-difference method for the pore pressure and temperature solutions, and the finite-element method for the deformation and stress solutions. However, the model also provides the thermoporoelastic effects at the wellbore wall, which involves wellbore fractures and wellbore instability. The simulation results show pronounced effects of the drilling fluid temperature on near-wellbore stresses. At the bottomhole area, a cool drilling fluid reduces the radial and tangential effective stresses in formation, whereas the vertical effective stress increases. The outcome is a possible enhancement in the drilling rate of the drill bit. At the wellbore wall, the cool drilling fluid reduces the vertical and tangential effective stresses but raises the radial effective stress. The result is a lower wellbore fracture gradient; however, it benefits formation stability and prevents wellbore collapse. Conversely, the simulation gives opposite induced stress results to the cooling cases when the drilling fluid is hotter than the formation.
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Rehman, Abdul. "New Environmentally Friendly Dispersants for High Temperature Invert-Emulsion Drilling Fluids Weighted by Manganese Tetraoxide." Thesis, 2011. http://hdl.handle.net/1969.1/ETD-TAMU-2011-12-10570.

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This thesis provides a detailed evaluation of different environmentally friendly dispersants in invert-emulsion drilling fluids that can be used to drill wells under difficult conditions such as HPHT. The drilling fluid is weighted by manganese tetraoxide (Mn3O4) particles, which have a specific gravity of 4.8 and a mean particle diameter of ca1 micrometers. Manganese tetraoxide has different wetting properties and surface chemistry than other weighting agents. Hence, there is a need to find dispersants for manganese tetraoxide that give reduced sag, reduced rheology, and low fluid-loss at HPHT conditions. This is particularly important for deep wells with narrow operating windows between pore-pressure and fracture pressure gradients. The stricter global environmental regulations mandated the dispersants to be environmentally friendly, e.g. within OCNS group D or E. First, oil compatibility tests and particle settling time experiments were conducted on 31 dispersants. From the experiments, we identified 3 oil-compatible dispersants that gave the longest settling time in base oil and belonged to OCNS group D. We investigated the effectiveness of selected chemicals in dispersing manganese tetraoxide at HPHT conditions. 1.95 and 2.4 S.G. drilling fluid samples were first prepared and tested without any contaminant and then in the presence of rev dust and cement as contaminants. Drilling fluid samples were statically aged at 400 degrees F and 500 psi for 16 hours. Sag and rheological measurements were taken before and after aging to determine the effect of HPHT conditions on fluid properties. Then, HPHT dynamic filtration tests were done at 500 psi differential pressure and 300 degrees F to determine HPHT dynamic fluid-loss. We have found that one of the dispersants (nonionic) gives low rheology and reduced sag before and after static aging. It also gives the lowest fluid-loss of the selected dispersants. For 2.4 S.G. fluid without contaminants, 10-minute gel strength was reduced from 50 to 32 lb/100 ft^2, plastic viscosity from 37 to 25 cp, sag from 0.249 to 0.135 lbm/gal, and fluid-loss was reduced from 44.4 to 39.6 cm^3 with the addition of dispersant. This dispersant prevents agglomeration of particles, thereby reducing fluid rheology, sag, and fluid-loss.
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Zigmond, Brandon. "Experimental Analysis of Water Based Drilling Fluid Aging Processes at High Temperature and High Pressure Conditions." Thesis, 2012. http://hdl.handle.net/1969.1/ETD-TAMU-2012-08-11629.

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In efforts to render the safest, fastest, and most cost efficient drilling program for a high temperature and high pressure (HT/HP) well the maximization of drilling operational efficiencies is key. Designing an adequate, HT/HP well specific, drilling fluid is of most importance and a technological challenge that can greatly affect the outcome of the overall operational efficiency. It is necessary to have a sound fundamental understanding of the behavior that water-based muds (WBM) exhibit when exposed to HT/HP conditions. Therefore, in order to adequately design and treat a WBM for a HT/HP well specific drilling program, it is essential that the mud be evaluated at HT/HP conditions. Currently, industry standard techniques used to evaluate WBM characteristics involve aging the fluid sample to a predetermined temperature, based on the anticipated bottom hole temperature (BHT), either statically or dynamically, for a predetermined length, then cooling and mixing the fluid and measuring its rheological properties at a significantly lower temperature. This, along with the fact that the fluid is not subjected to the anticipated bottom hole pressure (BHP) during or after the aging process, brings to question if the properties recorded are those that are truly experienced down-hole. Furthermore, these testing methods do not allow the user to effectively monitor the changes during the aging process. The research in this thesis is focused on evaluating a high performance WBM and the current test procedures used to evaluate their validity. Experimental static and dynamic aging tests were developed for comparative analysis as well to offer a more accurate and precise method to evaluate the effects experienced by WBM when subjected to HT/HP conditions. The experimental tests developed enable the user to monitor and evaluate, in real-time, the rheological changes that occur during the aging of a WBM while being subjected to true BHT and BHP. Detailed standard and experimental aging tests were conducted and suggest that the standard industry tests offer false rheological results with respect to true BHT and BHP. Furthermore, the experimental aging tests show that high pressure has a significant effect on the rheological properties of the WBM at elevated temperatures.
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Ravi, Ashwin. "Experimental Assessment of Water Based Drilling Fluids in High Pressure and High Temperature Conditions." Thesis, 2011. http://hdl.handle.net/1969.1/ETD-TAMU-2011-08-9925.

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Proper selection of drilling fluids plays a major role in determining the efficient completion of any drilling operation. With the increasing number of ultra-deep offshore wells being drilled and ever stringent environmental and safety regulations coming into effect, it becomes necessary to examine and understand the behavior of water based drilling fluids - which are cheaper and less polluting than their oil based counterpart - under extreme temperature and pressure conditions. In most of the existing literature, the testing procedure is simple - increase the temperature of the fluid in steps and record rheological properties at each step. A major drawback of this testing procedure is that it does not represent the continuous temperature change that occurs in a drilling fluid as it is circulated through the well bore. To have a better understanding of fluid behavior under such temperature variation, a continuous test procedure was devised in which the temperature of the drilling fluid was continuously increased to a pre-determined maximum value while monitoring one rheological parameter. The results of such tests may then be used to plan fluid treatment schedules. The experiments were conducted on a Chandler 7600 XHPHT viscometer and they seem to indicate specific temperature ranges above which the properties of the drilling fluid deteriorate. Different fluid compositions and drilling fluids in use in the field were tested and the results are discussed in detail.
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Book chapters on the topic "Drilling Fluid Temperature"

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Petersen, S., P. M. Herzig, and M. D. Hannington. "Fluid inclusion studies as a guide to the temperature regime within the TAG hydrothermal mound, 26°N, Mid–Atlantic Ridge." In Proceedings of the Ocean Drilling Program. Ocean Drilling Program, 1998. http://dx.doi.org/10.2973/odp.proc.sr.158.210.1998.

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Tivey, M. K., R. A. Mills, and D. A. H. Teagle. "Temperature and salinity of fluid inclusions in anhydrite as indicators of seawater entrainment and heating in the TAG active mound." In Proceedings of the Ocean Drilling Program. Ocean Drilling Program, 1998. http://dx.doi.org/10.2973/odp.proc.sr.158.211.1998.

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Maeda, J., H. R. Naslund, Y. D. Jang, E. Kikawa, T. Tajima, and W. H. Blackburn. "High-temperature fluid migration within oceanic Layer 3 gabbros, Hole 735B, Southwest Indian Ridge: implications for the magmatic-hydrothermal transition at slow-spreading mid-ocean ridges." In Proceedings of the Ocean Drilling Program. Ocean Drilling Program, 2002. http://dx.doi.org/10.2973/odp.proc.sr.176.004.2002.

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Adua Awejori, Gabriel, and Mileva Radonjic. "Review of Geochemical and Geo-Mechanical Impact of Clay-Fluid Interactions Relevant to Hydraulic Fracturing." In Hydraulic Fracturing [Working Title]. IntechOpen, 2021. http://dx.doi.org/10.5772/intechopen.98881.

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Shale rocks are an integral part of petroleum systems. Though, originally viewed primarily as source and seal rocks, introduction of horizontal drilling and hydraulic fracturing technologies have essentially redefined the role of shale rocks in unconventional reservoirs. In the geological setting, the deposition, formation and transformation of sedimentary rocks are characterised by interactions between their clay components and formation fluids at subsurface elevated temperatures and pressures. The main driving forces in evolution of any sedimentary rock formation are geochemistry (chemistry of solids and fluids) and geomechanics (earth stresses). During oil and gas production, clay minerals are exposed to engineered fluids, which initiate further reactions with significant implications. Application of hydraulic fracturing in shale formations also means exposure and reaction between shale clay minerals and hydraulic fracturing fluids. This chapter presents an overview of currently available published literature on interactions between formation clay minerals and fluids in the subsurface. The overview is particularly focused on the geochemical and geomechanical impacts of interactions between formation clays and hydraulic fracturing fluids, with the goal to identify knowledge gaps and new research questions on the subject.
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Conference papers on the topic "Drilling Fluid Temperature"

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Thaemlitz, Carl, Arvind Patel, George Coffin, and Lee Conn. "A New Environmentally Safe High-Temperature, Water-Base Drilling Fluid System." In SPE/IADC Drilling Conference. Society of Petroleum Engineers, 1997. http://dx.doi.org/10.2118/37606-ms.

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Mas, M., T. Tapin, R. Marquez, Z. Negrin, C. Diaz, and L. Bejarano. "A New High-Temperature Oil-Based Drilling Fluid." In Latin American and Caribbean Petroleum Engineering Conference. Society of Petroleum Engineers, 1999. http://dx.doi.org/10.2118/53941-ms.

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Block, J. "Alumina Gel Drilling Fluid for High-Temperature Use." In SPE Oilfield and Geothermal Chemistry Symposium. Society of Petroleum Engineers, 1985. http://dx.doi.org/10.2118/13557-ms.

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Ghazali, Nurul Aimi, Shigemi Naganawa, Yoshihiro Masuda, Wan Asma Ibrahim, and Noor Fitrah Abu Bakar. "Eco-Friendly Drilling Fluid Deflocculant for Drilling High Temperature Well: A Review." In ASME 2018 37th International Conference on Ocean, Offshore and Arctic Engineering. American Society of Mechanical Engineers, 2018. http://dx.doi.org/10.1115/omae2018-78149.

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Conventional clay-based drilling fluids often experienced difficulties in controlling the rheological properties, gelation, and filtration due to flocculation of clay at the temperature higher than 121°C. Deflocculant or thinner, one of the drilling fluid additives, serves a significant role in preventing the association of clay particles particularly in high temperature environments such as high-pressure and high-temperature (HPHT) deep-water drilling. Lignosulfonate has been commonly used in the industry as deflocculant for clay-based drilling fluids since the late 1950s as a replacement for Quebracho tannin. Degradation at the elevated temperature limits the usage of anionic polymer and lignosulfonate. In improving the stability of deflocculant at high temperature, lignosulfonate is admixed or reacted with chromium and iron compound to obtain ferro-chrome lignosulfonate whose temperature limit is approximately 190°C. While recent ferro-chrome lignosulfonate contains less chrome than in the past, development of more environmentally friendly and higher thermally stable deflocculant is still needed. In HPHT environment which requires high-density drilling fluid, a higher thermally-stable deflocculant is also valuable for barite sagging that becomes problematic at a temperature higher than 200°C. Several findings in the past development of adhesives show that addition of tannin improves the thermal stability of lignosulfonate. Tannin is a polyphenolic compound that is natural, non-toxic and biodegradable and can be found in various part of a vascular plant other than Quebracho. Lignosulfonate, on the other hand, is a byproduct of the paper pulping process. Tannin and lignosulfonate are cross-linked to obtain tannin–lignosulfonate for use as a high-temperature drilling fluid deflocculant. Tannin and lignin are the most abundant compounds extracted from biomass. The wide availability of tannin and lignosulfonate is an advantage from a manufacturing cost viewpoint. In this paper, an overview of drilling fluids, classification of drilling fluid, high temperature reservoir environment, and mechanisms of dispersion and deflocculation are presented. Further discussion on the potential development of eco-friendly tannin–lignosulfonate based drilling fluid system for the high temperature well development also presented.
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Jiang, Qihui, Guancheng Jiang, Chunlei Wang, Qi Zhu, Lili Yang, Le Wang, Xianmin Zhang, and Chong Liu. "A New High-Temperature Shear-Tolerant Supramolecular Viscoelastic Fracturing Fluid." In IADC/SPE Asia Pacific Drilling Technology Conference. Society of Petroleum Engineers, 2016. http://dx.doi.org/10.2118/180595-ms.

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Galindo, Kay A., Jay Paul Deville, Bernard Jean-Luc Espagne, David Pasquier, Isabelle Henaut, and Sara Rovinetti. "Fluorous-Based Drilling Fluid for Ultra-High Temperature Wells." In SPE Annual Technical Conference and Exhibition. Society of Petroleum Engineers, 2013. http://dx.doi.org/10.2118/166126-ms.

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Wenlong, Zheng, Wu Xiaoming, Huang Yuming, Xu Jie, and Wang Wenshi. "Research and Application of High-Temperature Drilling Fluid for Scientific Core Drilling Project." In Abu Dhabi International Petroleum Exhibition & Conference. Society of Petroleum Engineers, 2017. http://dx.doi.org/10.2118/188906-ms.

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Lyons, K. David, Simone Honeygan, and Thomas Mroz. "NETL Extreme Drilling Laboratory Studies High Pressure High Temperature Drilling Phenomena." In ASME 2007 26th International Conference on Offshore Mechanics and Arctic Engineering. ASMEDC, 2007. http://dx.doi.org/10.1115/omae2007-29478.

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The U.S. Department of Energy’s National Energy Technology Laboratory (NETL) established an Extreme Drilling Lab to engineer effective and efficient drilling technologies viable at depths greater than 20,000 feet. This paper details the challenges of ultra-deep drilling, documents reports of decreased drilling rates as a result of increasing fluid pressure and temperature, and describes NETL’s Research and Development activities. NETL is invested in laboratory-scale physical simulation. Their physical simulator will have capability of circulating drilling fluids at 30,000 psi and 480 °F around a single drill cutter. This simulator will not yet be operational by the planned conference dates; therefore, the results will be limited to identification of leading hypotheses of drilling phenomena and NETL’s test plans to validate or refute such theories. Of particular interest to the Extreme Drilling Lab’s studies are the combinatorial effects of drilling fluid pressure, drilling fluid properties, rock properties, pore pressure, and drilling parameters, such as cutter rotational speed, weight on bit, and hydraulics associated with drilling fluid introduction to the rock-cutter interface. A detailed discussion of how each variable is controlled in a laboratory setting will be part of the conference paper and presentation.
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Cesaroni, Renzo, and Umberto Repetti. "Solved Problems of High-Density and High-Temperature Drilling Fluid in an Environmentally Sensitive Area." In SPE/IADC Drilling Conference. Society of Petroleum Engineers, 1993. http://dx.doi.org/10.2118/25701-ms.

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Chodankar, Abhijeet D., and Cheng-Xian Lin. "Borehole Temperature Modelling in High Temperature Drilling Environment Based on Heat Transfer Laws." In ASME 2019 International Mechanical Engineering Congress and Exposition. American Society of Mechanical Engineers, 2019. http://dx.doi.org/10.1115/imece2019-10085.

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Abstract High temperature drilling environment has a drastic effect on drilling fluids, wellbore stability, and drilling system components. It has been observed that drilling fluids displace conventional halide based fluids in High Pressure and High Temperature (HPHT) wells leading to corrosion and environmental hazards, while wellbore strengthens further as a result of an increase in fracture initiation pressure in high temperature environment. However, it seriously damages the downhole tools like sensors, elastomer dynamic seals, lithium batteries, electronic component and boards leading to increases in cost and non-productive time. The main objective of this paper is to present an analytical borehole temperature model based on classical heat transfer laws in a high temperature drilling environment. The borehole is modelled using two approaches: composite wall and concentric cylinders. The composite wall and concentric cylinder approaches consist layers of geological formations, drilling fluids outside the drill string, drill string, and drilling fluid inside the drill string. Temperature, heat transfer coefficient, and heat transfer variations along the borehole layers are determined using the derived analytical solutions and tested for different drilling fluid types, air drilling environment, and different drill string materials. The results of composite wall and concentric cylinder models are obtained by using the input field temperatures data in the geological formation and inner annulus of drill pipe to determine the borehole temperature profile in HPHT wells. Therefore, a thorough borehole heat transfer analysis will help in wellbore stability, drilling fluid selection, corrosion control, and optimal placement and material selection of drilling components in HPHT drilling environments.
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Reports on the topic "Drilling Fluid Temperature"

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Guidati, Gianfranco, and Domenico Giardini. Joint synthesis “Geothermal Energy” of the NRP “Energy”. Swiss National Science Foundation (SNSF), February 2020. http://dx.doi.org/10.46446/publication_nrp70_nrp71.2020.4.en.

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Near-to-surface geothermal energy with heat pumps is state of the art and is already widespread in Switzerland. In the future energy system, medium-deep to deep geothermal energy (1 to 6 kilometres) will, in addition, play an important role. To the forefront is the supply of heat for buildings and industrial processes. This form of geothermal energy utilisation requires a highly permeable underground area that allows a fluid – usually water – to absorb the naturally existing rock heat and then transport it to the surface. Sedimentary rocks are usually permeable by nature, whereas for granites and gneisses permeability must be artificially induced by injecting water. The heat gained in this way increases in line with the drilling depth: at a depth of 1 kilometre, the underground temperature is approximately 40°C, while at a depth of 3 kilometres it is around 100°C. To drive a steam turbine for the production of electricity, temperatures of over 100°C are required. As this requires greater depths of 3 to 6 kilometres, the risk of seismicity induced by the drilling also increases. Underground zones are also suitable for storing heat and gases, such as hydrogen or methane, and for the definitive storage of CO2. For this purpose, such zones need to fulfil similar requirements to those applicable to heat generation. In addition, however, a dense top layer is required above the reservoir so that the gas cannot escape. The joint project “Hydropower and geo-energy” of the NRP “Energy” focused on the question of where suitable ground layers can be found in Switzerland that optimally meet the requirements for the various uses. A second research priority concerned measures to reduce seismicity induced by deep drilling and the resulting damage to buildings. Models and simulations were also developed which contribute to a better understanding of the underground processes involved in the development and use of geothermal resources. In summary, the research results show that there are good conditions in Switzerland for the use of medium-deep geothermal energy (1 to 3 kilometres) – both for the building stock and for industrial processes. There are also grounds for optimism concerning the seasonal storage of heat and gases. In contrast, the potential for the definitive storage of CO2 in relevant quantities is rather limited. With respect to electricity production using deep geothermal energy (> 3 kilometres), the extent to which there is potential to exploit the underground economically is still not absolutely certain. In this regard, industrially operated demonstration plants are urgently needed in order to boost acceptance among the population and investors.
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