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Journal articles on the topic 'Drilling Fluid Temperature'
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1
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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Ismail, Abdul Razak, Wan Rosli Wan Sulaiman, Mohd Zaidi Jaafar, Issham Ismail, and Elisabet Sabu Hera. "Nanoparticles Performance as Fluid Loss Additives in Water Based Drilling Fluids." Materials Science Forum 864 (August 2016): 189–93. http://dx.doi.org/10.4028/www.scientific.net/msf.864.189.
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Nanoparticles are used to study the rheological characteristics of drilling fluids. Nanoparticles have high surface to volume ratio, therefore only small quantity is required to blend in the drilling fluid. This research evaluates the performance of nanosilica and multi walled carbon nanotubes (MWCNT) as fluid loss additives in water based drilling fluid with various nanoparticles concentration and temperature. The results show that plastic viscosity, yield point and gel strength of drilling fluid increases as the concentration of nanoparticles increased. Drilling fluid with nanosilica gives the highest filtrate loss of 12 ml and mudcake thickness of 10 inch at 1 g concentration at 300°F. However, drilling fluid with MWCNT shows a decreasing trend in fluid loss and mudcake thickness. The results also show that xanthan gum containing 1 g of MWCNT gives 4.9 ml fluid loss and mudcake thickness of 4 inch at 200°F. After aging, plastic viscosity, yield point and gel strength of mud containing nanoparticles decrease significantly especially for 1 g of nanosilica and 0.01 g MWCNT. Fluid loss and mudcake thickness increased when the mud is exposed to temperature above 250°F. The results showed that xanthan gum with MWCNT gives a better rheological performance.
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Almahdawi, Dr Faleh H. M., Dr Mohammad N. Hussain, and Haider Salim Jasim. "Plum Tree Gums as Local Alternatives for Foreign Drilling Fluid Materials." Journal of Petroleum Research and Studies 7, no. 3 (May 7, 2021): 51–65. http://dx.doi.org/10.52716/jprs.v7i3.158.
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A few years ago oil well drilling cost increased due to using modern technique such as equipment and materials that are used by specialist companies so studies and researches were required to decrease these costs. In this study we tried to find local alternatives for foreign drilling fluid materials that are aimed to decrease oil well drilling cost although the cost of drilling fluid materials reach to 30 % of total materials cost of drilling oil well.
In the first part of this study seven local materials and it's tested under API Specification 13A for Drilling Fluids Materials were investigated. Plum Tree Gum was succeeded in this test among several other materials as drilling fluid materials. The second part of this study was a comparison between these local alternative and similar foreign materials for same sample to show physical and rheological properties. The third part of this study was tested this local alternative under different values temperature to show effect the temperature on physical and rheological properties of this local alternative. The results approved that; Plum Tree Gum, local alternative, can use as filtration control materials for water based drilling fluid. Also this local alternative 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 has positive effect on Rig equipment’s and Pay-zone. Plum Tree Gum is Ore polymers (plant origin)
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Song, Xun Cheng, Xiao Long Xu, Sha Sha Hu, and Zhi Chuan Guan. "Full Transient Features of Heat Transfer and Sensitivities on Deep Water Wells." Advanced Materials Research 524-527 (May 2012): 1423–28. http://dx.doi.org/10.4028/www.scientific.net/amr.524-527.1423.
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Wellbore temperature is significant to well program and safety drilling for deep water drilling operations. On the basis of transient heat transfer mechanisms involved in deep water drilling among wellbore and formation and sea water, wellbore temperature profile, especially near sea bed and sensitivities to drilling fluid circulating duration, inlet temperature, water depth, water temperature, riser insulation and drilling fluid specific heat capacity have been analyzed via this model. Analysis show that deep-water wellbore temperature is much lower than a land well, the temperatures above sea bed normally ranges 10-30°C, and decreases with increased circulating duration; temperature at both outlet and bottom hole decreases drastically with increased water depth, and heat generation must be considered into estimating wellbore temperature profile especially one at bottom hole.
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Mohamed, Abdelmjeed, Salem Basfar, Salaheldin Elkatatny, and Abdulaziz Al-Majed. "Prevention of Barite Sag in Oil-Based Drilling Fluids Using a Mixture of Barite and Ilmenite as Weighting Material." Sustainability 11, no. 20 (October 12, 2019): 5617. http://dx.doi.org/10.3390/su11205617.
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Drilling high-pressure high-temperature (HPHT) wells requires a special fluid formulation that is capable of controlling the high pressure and is stable under the high downhole temperature. Barite-weighted fluids are common for such purpose because of the good properties of barite, its low cost, and its availability. However, solids settlement is a major problem encountered with this type of fluids, especially at elevated downhole temperatures. This phenomenon is known as barite sag, and it is encountered in vertical and directional wells under static or dynamic conditions leading to serious well control issues. This study aims to evaluate the use of barite-ilmenite mixture as a weighting agent to prevent solids sag in oil-based muds at elevated temperatures. Sag test was conducted under static conditions (vertical and inclined) at 350 °F and under dynamic conditions at 120 °F to determine the optimum ilmenite concentration. Afterward, a complete evaluation of the drilling fluid was performed by monitoring density, electrical stability, rheological and viscoelastic properties, and filtration performance to study the impact of adding ilmenite on drilling fluid performance. The results of this study showed that adding ilmenite reduces sag tendency, and only 40 wt.% ilmenite (from the total weighting material) was adequate to eliminate barite sag under both static and dynamic conditions with a sag factor of around 0.51. Adding ilmenite enhanced the rheological and viscoelastic properties and the suspension of solid particles in the drilling fluid, which confirmed sag test results. Adding ilmenite slightly increased the density of the drilling fluid, with a slight decrease in the electrical stability within the acceptable range of field applications. Moreover, a minor improvement in the filtration performance of the drilling fluid and filter cake sealing properties was observed with the combined weighting agent. The findings of this study provide a practical solution to the barite sag issue in oil-based fluids using a combination of barite and ilmenite powder as a weighting agent to drill HPHT oil and gas wells safely and efficiently with such type of fluids.
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Ma, Cha, Long Li, and Yu Ping Yang. "Study on Horizontal Wells and ERW Drilling Technology of Carrying Cuttings." Applied Mechanics and Materials 204-208 (October 2012): 397–400. http://dx.doi.org/10.4028/www.scientific.net/amm.204-208.397.
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Hole cleaning was very difficult in horizontal wells and extended reach wells (ERW), which was the technical bottleneck in raising the progress and success rate of petroleum exploration and production at present. A new type of treating agent for drilling fluid (CNRJ), designed for horizontal wells and extended-reach wells, was synthesized. CNRJ was added to drilling fluids, and the rheological properties, temperature-resisting property and suspension performance of drilling fluid system were analysed. The results indicate that CNRJ has good compatibility with drilling fluid system, and the dynamic plastic ratio of drilling fluid system can be adjusted from 0.20 to 1.12. In addition, the drilling fluid system has good static suspension ability for cuttings, good heat resistance and pollution resistance.
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Jiang, Xiao Ling, Zong Ming Lei, and Kai Wei. "Application of R/S Rheometer in Low Temperature Drilling Fluid Rheology Determination." Advanced Materials Research 490-495 (March 2012): 3114–18. http://dx.doi.org/10.4028/www.scientific.net/amr.490-495.3114.
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With six-speed rotary viscometer measuring the rheology of drilling fluid at low temperature, during the high-speed process, the drilling fluid temperature is not constant at low temperature, which leads to the inaccuracy in rheological measurement. When R/S rheometer is used cooperating with constant low-temperature box , the temperature remains stable during the process of determining the drilling fluid rheology under low temperature. The R/S rheometer and the six-speed rotational viscometer are both coaxial rotational viscometers, but they work in different ways and the two cylindrical clearance between them are different.How to make two viscometer determination result can maintain consistent?The experimental results show that, The use of R/S rheometer, with the shear rate for 900s-1 shear stress values instead of six speed rotary viscometer shear rate for 1022s-1 shear stress values.Then use two-point formula to calculate rheological parameters.The R/S rheometer rheological parameter variation with temperature has a good linear relationship,Can better reflect the rheological properties of drilling fluids with low temperature changerule
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Basfar, Salem, Abdelmjeed Mohamed, Salaheldin Elkatatny, and Abdulaziz Al-Majed. "A Combined Barite–Ilmenite Weighting Material to Prevent Barite Sag in Water-Based Drilling Fluid." Materials 12, no. 12 (June 17, 2019): 1945. http://dx.doi.org/10.3390/ma12121945.
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Barite sag is a serious problem encountered while drilling high-pressure/high-temperature (HPHT) wells. It occurs when barite particles separate from the base fluid leading to variations in drilling fluid density that may cause a serious well control issue. However, it occurs in vertical and inclined wells under both static and dynamic conditions. This study introduces a combined barite–ilmenite weighting material to prevent the barite sag problem in water-based drilling fluid. Different drilling fluid samples were prepared by adding different percentages of ilmenite (25, 50, and 75 wt.% from the total weight of the weighting agent) to the base drilling fluid (barite-weighted). Sag tendency of the drilling fluid samples was evaluated under static and dynamic conditions to determine the optimum concentration of ilmenite which was required to prevent the sag issue. A static sag test was conducted under both vertical and inclined conditions. The effect of adding ilmenite to the drilling fluid was evaluated by measuring fluid density and pH at room temperature, and rheological properties at 120 °F and 250 °F. Moreover, a filtration test was performed at 250 °F to study the impact of adding ilmenite on the drilling fluid filtration performance and sealing properties of the formed filter cake. The results of this study showed that adding ilmenite to barite-weighted drilling fluid increased fluid density and slightly reduced the pH within the acceptable pH range (9–11). Ilmenite maintained the rheology of the drilling fluid with a minimal drop in rheological properties due to the HPHT conditions, while a significant drop was observed for the base fluid (without ilmenite). Adding ilmenite to the base drilling fluid significantly reduced sag factor and 50 wt.% ilmenite was adequate to prevent solids sag in both dynamic and static conditions with sag factors of 0.33 and 0.51, respectively. Moreover, HPHT filtration results showed that adding ilmenite had no impact on filtration performance of the drilling fluid. The findings of this study show that the combined barite–ilmenite weighting material can be a good solution to prevent solids sag issues in water-based fluids; thus, drilling HPHT wells with such fluids would be safe and effective.
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Luo, Hui Hong, Ze Hua Wang, Yu Xue Sun, and Han Jiang. "Study of Drilling Fluid System of Resisting the High Temperature of 220 Degrees." Advanced Materials Research 753-755 (August 2013): 130–33. http://dx.doi.org/10.4028/www.scientific.net/amr.753-755.130.
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Focus on the high temperature rheological stability and the fluid loss control of resistance to high temperature drilling fluid system, further determine system formula and the formula of the high temperature drilling fluid system should be optimized. Eventually, a kind of organo-silica drilling fluid system of excellent performance which is resistant to high temperature of 220 degrees has been developed, and the system performances have been evaluated. The high temperature-resistant organo-silica drilling fluid system is of good shale inhibition, lubricity and borehole stability. The fluid loss is low and the filter cake is thin and tight, which can effectively prevent bit balling. The sand-carrying ability is good and the rheological property is easy to control. The performances of drilling fluid remain stable under high salinity and the system can resist the pollution of 6%NaCl and 0.5%CaC12. The materials used in this system are non-toxic, non-fluorescent and suitable for deep well drilling.
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Guo, Li Ping, and Lei Wang. "Study on the Flow Behavior of Underbalanced Circulative Micro-Foam Drilling Fluid." Advanced Materials Research 706-708 (June 2013): 1585–88. http://dx.doi.org/10.4028/www.scientific.net/amr.706-708.1585.
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Underbalanced drilling is a new method for the exploratory development of low pressure and permeability reservoirs; circulative micro-foam drilling fluid is a new technology which is developed for realizing near-balanced drilling and underbalanced drilling. The flow behavior of circulative micro-foam drilling fluid in wellbore was researched by applying HPHT experiment apparatus. It is concluded that the flow behavior parameters of circulative micro-foam drilling fluid is only related to temperature but not to pressure; the constitutive equation accords with the rheological law of power-law fluid, the expressions of consistency coefficient and liquidity index were obtained through analyzing the flow behavior experiment data under the condition of HTHP. The density of circulative micro-foam drilling fluid increases as the increase of pressure and decreases as the increase of temperature, but in wellbore the rate of increase as pressure is greater than that of decrease as temperature, so the density of drilling fluid in wellbore is greater than that under ground condition. The fluid drag force of micro-foam drilling fluid in annulus were analyzed theoretically and the pressure distribution formulas of micro-foam drilling fluid in wellbore were given.
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Ali, Muhammad, Husna Hayati Jarni, Adnan Aftab, Abdul Razak Ismail, Noori M. Cata Saady, Muhammad Faraz Sahito, Alireza Keshavarz, Stefan Iglauer, and Mohammad Sarmadivaleh. "Nanomaterial-Based Drilling Fluids for Exploitation of Unconventional Reservoirs: A Review." Energies 13, no. 13 (July 2, 2020): 3417. http://dx.doi.org/10.3390/en13133417.
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The world’s energy demand is steadily increasing where it has now become difficult for conventional hydrocarbon reservoir to meet levels of demand. Therefore, oil and gas companies are seeking novel ways to exploit and unlock the potential of unconventional resources. These resources include tight gas reservoirs, tight sandstone oil, oil and gas shales reservoirs, and high pressure high temperature (HPHT) wells. Drilling of HPHT wells and shale reservoirs has become more widespread in the global petroleum and natural gas industry. There is a current need to extend robust techniques beyond costly drilling and completion jobs, with the potential for exponential expansion. Drilling fluids and their additives are being customized in order to cater for HPHT well drilling issues. Certain conventional additives, e.g., filtrate loss additives, viscosifier additives, shale inhibitor, and shale stabilizer additives are not suitable in the HPHT environment, where they are consequently inappropriate for shale drilling. A better understanding of the selection of drilling fluids and additives for hydrocarbon water-sensitive reservoirs within HPHT environments can be achieved by identifying the challenges in conventional drilling fluids technology and their replacement with eco-friendly, cheaper, and multi-functional valuable products. In this regard, several laboratory-scale literatures have reported that nanomaterial has improved the properties of drilling fluids in the HPHT environment. This review critically evaluates nanomaterial utilization for improvement of rheological properties, filtrate loss, viscosity, and clay- and shale-inhibition at increasing temperature and pressures during the exploitation of hydrocarbons. The performance and potential of nanomaterials, which influence the nature of drilling fluid and its multi-benefits, is rarely reviewed in technical literature of water-based drilling fluid systems. Moreover, this review presented case studies of two HPHT fields and one HPHT basin, and compared their drilling fluid program for optimum selection of drilling fluid in HPHT environment.
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Wang, Yue Zhi, Chun Zhi Luo, and Yi Di Wang. "Research on Water-Based Drilling Fluid for Super Depth and Ultra-High-Temperature Horizontal Wells in Tarim Basin." Key Engineering Materials 730 (February 2017): 231–36. http://dx.doi.org/10.4028/www.scientific.net/kem.730.231.
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One area of northern Tarim Basin in China is carbonate reservoir, and the reservoir is between 6600 ~ 6900 m. The bottom hole static temperature is close to 170°C, the ECD of pore pressure is 1.1 ~ 1.15 g/cm3. In order to improve the development economic benefit, reservoir need to adopt horizontal well development. Water-based drilling fluid is required to resistant high temperatures and high salt, prevent leakage of limestone reservoir fracture, control the density, protect the reservoir from damage, and has good rheological properties. For old poly-sulfide drilling fluid system, through the indoor evaluation system of various treatment agent and temperature resistance, authors found that by using polymer viscosities, loss of water and temperature resistance of lubricant can reach 140°C. Therefore authors developed the temperature stability agent and high temperature resistant lubricants. This paper introduces the mechanism of the treatment, and evaluates the performance of synthetic products. Aiming at the shortage of the lubricant, authors develop a blister, crosslinking, good environmental protection and maintain water-based lubricant characteristics of resistance to high temperature lubricant. It has good environmental protection ability. Through the evaluation, it has good lubricity and temperature resistance. By introducing the resistance temperature resistance to high temperature drilling fluid system, and after the application in well H9-10H, new drilling fluid system was carried out, well meet the requirements of drilling engineering.
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Tang, Zhiqiang, Qian Li, and Hu Yin. "The near-wellbore pressure calculation model incorporating thermochemical effect." Thermal Science 22, no. 1 Part B (2018): 623–30. http://dx.doi.org/10.2298/tsci170329186t.
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The potential difference of hydraulic pressure, solute concentration and temperature between the drilling fluid and the formation fluid can induce the flow of solvent and cause changes in the pore pressure during drilling a tight formation, which may result in wellbore instability. According to the continuity equation of fluid, the pore pressure calculation model considering the effect of thermochemical coupling is established and the solution of the pore pressure in the Laplace domain is given. Using this model, the effects of the temperature, solute concentration and viscosity of drilling fluid on the pore pressure around the wellbore are simulated. The results show that, when the wellbore pressure is higher than the formation pressure and the solute concentration of the drilling fluid is larger than that of the formation fluid, the near-wellbore pore pressure will decrease first and then increase during drilling a tight formation, and increasing the drilling fluid temperature will decrease the pore pressure. Increasing the solute concentration of the drilling fluid can inhibit the increase of the pore pressure.
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Li, Tao, and Gannan Yuan. "Computational Fluid Dynamics Simulation of High Pressure and High Temperature Waterjet Downhole Drilling Environments for Design of Helix in Drilling Calibration Apparatus." Journal of Computational and Theoretical Nanoscience 13, no. 10 (October 1, 2016): 7176–83. http://dx.doi.org/10.1166/jctn.2016.5689.
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High pressure waterjet drilling (HPWD) as a cutting-edge upstream technology receives considerable attention in horizontal drilling fields. HPWD technology achieves great commercial benefits for the reentry multilateral well drilling in small diameter space where the conventional rotary drill bit needs high-cost tools to implement. The sophisticated waterjet downhole drilling environments are difficult to predict because the temperatures and pressures varied with the depth of the well and the chemical compositions of drilling fluid. Different proportion of waterjet drilling fluid (density or viscosity) may produce different pressures and temperatures for the waterjet drilling bit. Therefore, computational fluid dynamics (CFD) simulation of the waterjet drilling environments is of crucial significance, especially for the design of downhole navigation apparatus. This paper describes the design details of helix drilling calibration (HIDC) apparatus with MEMS gyroscope based measurement while drilling (MGWD) device in downhole harsh conditions. The design objective of HIDC apparatus is that the determined errors of MGWD device interrupted by scale factor errors and axis non-orthogonal errors can be modulated and the stochastic errors and the bias drift of MGWD device can be reduced. The drilling environments of HIDC apparatus are simulated by ANSYS INFLUENT software and the simulation results demonstrate that the temperature, the pressure and the flow rate of waterjet drilling fluid to HIDC apparatus are 172.85 °C, 4×108 Pa and 704.4823 m/s respectively.
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Wang, Ping Quan, Yang Bai, Gang Peng, and Zhi Wei Qian. "Drilling Fluid Development and Performance Evaluation of Deep and Ultra-Deep High-Density Saturated Brine." Advanced Materials Research 524-527 (May 2012): 1382–88. http://dx.doi.org/10.4028/www.scientific.net/amr.524-527.1382.
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Due to the high temperature , great pressure and complex lithology of super-deep well bottom, there exist such problems such as high solid concentration, multiple but inaccurate treating chemicals, complex formulation with instability of drilling fluid system, resulting in a frequent occurrence of underground complex accident and a waste of a lot of manpower and material resources. Therefore, based on the analysis of performance factors of ultra-deep drilling fluid system, the approach of regulating water based drilling fluid properties of super-deep well has been found. Moreover, through screening and processing optimization of treating chemicals of ultra-deep well by single-factor method, three sets of anti-high-density and anti-high-temperature saturated brine drilling fluid systems with few kinds of treating chemicals, concise and simplified system, including: ① saturated brine drilling fluid with anti-temperature 180 °C and density 2.40 g/cm3 ; ② saturated brine drilling fluid with anti-temperature 200 °C and density 2.40g/cm3; ③ saturated brine drilling fluid with anti-temperature 220 °C and density 2.40g/cm3 . After the the evaluation of the overall performance of these three systems under respective experimental conditions, the results show that all of these systems have such advantages as good and strong rheology, water loss building capacity, inhibition, lubricity and blocking ability, etc, which could meet the requirements of ultra-deep drilling under different circumstances.
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Wang, Nan Nan, Yong Ping Wang, Dong Zhang, and Hui Min Tang. "Micro Foam Drilling Fluid System Performance Research and Application." Advanced Materials Research 868 (December 2013): 601–5. http://dx.doi.org/10.4028/www.scientific.net/amr.868.601.
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Micro foam drilling fluid has irreplaceable advantages in reservoir protection, drilling speed, improve the cementing quality and leak plugging, especially suitable for the "three low" Daqing peripheral oilfield Haita area. Indoor the foaming agent, foam stabilizing agent were screened, Preferably choose the efficient composite foaming agent, stabilizer and thickener, the drilling fluid system is transformed into micro foam drilling fluid system. And evaluate the inhibition, anti temperature, anti pollution (anti clay, calcium, anti kerosene) reservoir protection capability, The micro foam drilling fluid leakage, oil reservoir protection, speed up mechanism and micro foam drilling fluid rheological characteristics were studied, Set up a specific rheological model of Micro Foam Drilling fluid, According to the characteristics of Gulong oilfield,R&D the calculation software of Micro Foam drilling fluid density changes with the temperature, pressure and provide guidance for safe drilling. Field application shows that the system has the advantages of simple preparation,convenient maintenance, easy transformation, drilling fluid properties can meet the requirements of drilling technology, To ensure the safe, fast, and high quality drilling of oil and gas,reduce pollution,improve the productivity of a single well.
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Ribeiro, F. B., and V. M. Hamza. "Stabilization of bottom‐hole temperature in the presence of formation fluid flows." GEOPHYSICS 51, no. 2 (February 1986): 410–13. http://dx.doi.org/10.1190/1.1442099.
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Reliable estimates of bottom‐hole temperature (BHT) in oil wells are of considerable interest in reservoir engineering problems as well as in geothermal research. Because BHT measurements are usually made soon after drilling, true formation temperature can be obtained only by correcting for the effects of drilling disturbances. The magnitude of drilling disturbance depends upon duration of drilling, time elapsed after stoppage of drilling, well characteristics, thermal properties of drilling fluid, and the nature of heat exchange between the well and the formation.
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Kozhevnykov, A. O., A. Yu Dreus, Liu Baochang, and A. K. Sudakov. "Drilling fluid circulation rate influence on the contact temperature during borehole drilling." Scientific Bulletin of National Mining University 1 (2018): 35–42. http://dx.doi.org/10.29202/nvngu/2018-1/14.
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Meng, Fanhe, Aiguo Yao, and Shuwei Dong. "Prediction of Wellbore Temperatures During the Scientific Ultra-Deep Drilling Process." Open Petroleum Engineering Journal 8, no. 1 (October 22, 2015): 451–56. http://dx.doi.org/10.2174/1874834101508010451.
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In order to carry out a series of key basic researches, a scientific ultra-deep drilling plan is being undertaken in China. Wellbore temperature is one of the key factors during the drilling process. In this paper, we established a twodimensional transient numerical model to predict the ultra-deep wellbore temperature distributions during circulation and shut-in stages. The simulation results indicate that the cooling effect of drilling fluid circulation is very obvious, especially during the inception phase. Drilling fluid viscosity has great influence on the temperature distributions during circulation stage: the lower the viscosity, the higher the bottomhole temperature. While drilling fluid displacement and inlet temperature have a little effect on the bottomhole temperature. During the shut-in stage, the wellbore temperature recovery is a slow process.
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Salam, Massara, Nada S. Al-Zubaidi, and Asawer A. Al-Wasiti. "Lubricating Properties of Water-Based Drilling Fluid Improvement Using Lignite NPs as well as Their Effect on Rheological and Filtration Properties." Association of Arab Universities Journal of Engineering Sciences 26, no. 1 (March 31, 2019): 81–88. http://dx.doi.org/10.33261/jaaru.2019.26.1.011.
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In the process of drilling directional, extended-reach, and horizontal wells, the frictional forces between the drill string and the wellbore or casing can cause severe problems including excessive torque which is one of the most important problems during drilling oil and gas well. Drilling fluid plays an important role by reducing these frictional forces. In this research, an enhancement of lubricating properties of drilling fluids was fundamentally examined by adding Lignite NPs into the water-based drilling fluid. Lubricity, Rheology and filtration properties of water-based drilling fluid were measured at room temperature using OFITE EP and Lubricity Tester, OFITE Model 900 Viscometer, and OFITE Low-Pressure Filter Press, respectively. Lignite NPs were added at different concentrations (0.05 %, 0.1 %, 0.2 %, 0.5 %, and 1 %) by weight into water-based drilling fluid. Lignite NPs showed good reduction in COF of water-based drilling fluid. The enhancement was increased with increasing Lignite NPs concentrations; 23.68%, 35.52%, and 45.3 % reduction in COF were obtained by adding 0.2%, 0.5%, and 1% by weight Lignite NPs concentration, respectively.
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JPT staff, _. "Temperature and Pressure Effects on Drilling-Fluid Rheology." Journal of Petroleum Technology 49, no. 11 (November 1, 1997): 1212–13. http://dx.doi.org/10.2118/1197-1212-jpt.
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Li, Feng Xia, Guang Chen Jiang, Zheng Ku Wang, and Mao Rong Cui. "Natural Vegetable Gum Drilling and Completion Fluids System for Industrial Control and Application." Key Engineering Materials 467-469 (February 2011): 1345–50. http://dx.doi.org/10.4028/www.scientific.net/kem.467-469.1345.
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To simplify the operation for the oil and gas development for drill and complete the well in the petroleum industry, a natural vegetable gum drilling and completion fluids system is developed for the industrial control and application. As the system combines the advantage of the drilling fluid and completion fluid, it need not change the two different fluids during the operation, which is beneficial to the operation control. In addition, it can improve the implementation of the oil and gas exploration for industrial application. An extensive laboratory work for the high-temperature resistance capability of the natural vegetable gum drilling and completion fluids system is carried out, including the formulation study of the detailed system and the corresponding performance evaluation. In the system, with the basic formula of the natural vegetable gum drilling and completion fluids system, several new formulas beneficial to improve the high-temperature resistance capability of the system have been described. The corresponding laboratory analysis has demonstrated that the prosperities of the system, with the temperature resistance capability up to 305℉, are proper for the industrial application.
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You, Fangyi, Jin Li, Huzi Cui, and Qiulian Dai. "Study of the influence of models on the drilling temperature of bone measured by thermocouples." Advanced Composites Letters 29 (January 1, 2020): 2633366X2092140. http://dx.doi.org/10.1177/2633366x20921406.
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Bone drilling is a standard procedure in medicine mainly for internal fixation with a gripper plate. Drilling bone generates much heat, then the heat causes the temperature of bone to rise, nearby the borehole rapidly, while drilling. Studies indicated that the bone would irreversibly be damaged after being heated up to 47°C for 60 s. Hence, it is vitally important to control the drilling temperature of bone. Two different models of the tibia for drilling simulation were established with ABAQUS software based on finite element analysis in this article. The first model is an approximate ideal model of the tibia with fluid in the bone cavity. And the other one is a tubular tibia without fluid in the bone cavity, and a pair of thermocouples is embedded to match the experimental condition when measuring the drilling temperature. The distribution of heat on the bone and the highest drilling temperature were revealed by simulation, and the influences of drilling parameters on drilling temperature of bone were also explored by variance analysis. The results show that the maximum drilling temperature increases with an increase in the diameter of bit and spindle speed. The drilling temperature also increases as the feed rate increase, but the effect of feed rate on drilling temperature is not as significant as that of spindle speed. The drilling temperatures of two models were obtained by the finite element method. The maximum temperature of model 1 is taken as the benchmark. The temperature of model 2 takes as the experimental result. A formula for modifying the experimental temperature to actual value was derived. Then predicted temperature of model 1 could be achieved to obtain the optimized drilling parameters.
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Li, Ben, Hui Li, Boyun Guo, Xiao Cai, and Mas lwan Konggidinata. "A New Numerical Solution To Predict the Temperature Profile of Gas-Hydrate-Well Drilling." SPE Journal 22, no. 04 (February 13, 2017): 1201–12. http://dx.doi.org/10.2118/185177-pa.
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Summary Gas-hydrate cuttings are conveyed upward by the drilling fluid through the outer drillpipe/wellbore annulus during the gas-hydrate-well-drilling process. The temperature profile along the wellbore during the drilling process has not been thoroughly investigated because the gas-hydrate cuttings could affect the temperature of the drilling fluid along the wellbore. As the mixture of drilling fluid and gas hydrates flows from the bottom to the surface, the methane and other hydrocarbons present in the gas hydrates would change from liquid to gas phase and further cause well-control issues. Furthermore, the bottomhole pressure would decrease and could not provide sufficient balance to the formation pressure, which could significantly increase the risk of well blowout. A numerical solution is presented in this paper to predict the temperature profile of the gas-hydrate well during the drilling process. The main considerations were the following: Hydrate cuttings entrained in the bottom of the hole would affect the temperature of the fluid in the annulus space. The entrained hydrate cuttings could affect the fluid thermal properties in the drillstring and in the annulus. Because of the Joule-Thomson cooling effect at the outlet of the nozzles, the fluid temperature at the bottom of the hole was lower than that above the drill-bit nozzles. Hence, the gas-hydrate-dissociation characteristics were considered and integrated in the proposed numerical model. The numerical model was validated by comparing the obtained data with the Shan et al. (2016) analytical model. In addition, the obtained data were also compared with the measured temperature data of a conventional well drilled in China and a gas-hydrate-well drilling record in India. Sensitivity analysis was used to evaluate the effects of the pumping rate, Joule-Thomson effect, and injection drilling-mud temperature on the annulus temperature-profile distribution. It was found that the injection drilling-mud temperature and pumping rate could affect the temperature profile in the annulus, whereas the Joule-Thomson effect could decrease the annulus temperature of the drilling mud near the bottom.
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Nee, Lim Symm, Badrul Mohamed Jan, Brahim Si Ali, and Ishenny Mohd Noor. "The Effects of Glass Bubbles, Clay, Xanthan Gum and Starch Concentrations on the Density of Lightweight Biopolymer Drilling Fluid." Applied Mechanics and Materials 625 (September 2014): 526–29. http://dx.doi.org/10.4028/www.scientific.net/amm.625.526.
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It is an open secret that currently oil and gas industry is focusing on increasing hydrocarbon production through underbalanced drilling (UBD) and finding ways to ensure the drilling process is less harmful to the environment. Water-based biopolymer drilling fluids are preferred compared to oil based drilling fluids owing to the fact that it causes less pollution to the environment. This paper investigates the effects of varying concentrations of environmentally safe raw materials, namely glass bubbles, clay, xanthan gum and starch concentrations on the density of the formulated biopolymer drilling fluid to ensure that it is suitable for UBD. As material concentrations were varied, the density for each sample was measured at ambient temperature and pressure. Results showed that the final fluid densities are within acceptable values for UBD (6.78 to 6.86 lb/gal). It is concluded that the formulated water-based biopolymer drilling fluid is suitable to be used in UBD operation.
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Murtaza, Mobeen, Sulaiman A. Alarifi, Muhammad Shahzad Kamal, Sagheer A. Onaizi, Mohammed Al-Ajmi, and Mohamed Mahmoud. "Experimental Investigation of the Rheological Behavior of an Oil-Based Drilling Fluid with Rheology Modifier and Oil Wetter Additives." Molecules 26, no. 16 (August 12, 2021): 4877. http://dx.doi.org/10.3390/molecules26164877.
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Drilling issues such as shale hydration, high-temperature tolerance, torque and drag are often resolved by applying an appropriate drilling fluid formulation. Oil-based drilling fluid (OBDF) formulations are usually composed of emulsifiers, lime, brine, viscosifier, fluid loss controller and weighting agent. These additives sometimes outperform in extended exposure to high pressure high temperature (HPHT) conditions encountered in deep wells, resulting in weighting material segregation, high fluid loss, poor rheology and poor emulsion stability. In this study, two additives, oil wetter and rheology modifier were incorporated into the OBDF and their performance was investigated by conducting rheology, fluid loss, zeta potential and emulsion stability tests before and after hot rolling at 16 h and 32 h. Extending the hot rolling period beyond what is commonly used in this type of experiment is necessary to ensure the fluid’s stability. It was found that HPHT hot rolling affected the properties of drilling fluids by decreasing the rheology parameters and emulsion stability with the increase in the hot rolling time to 32 h. Also, the fluid loss additive’s performance degraded as rolling temperature and time increased. Adding oil wetter and rheology modifier additives resulted in a slight loss of rheological profile after 32 h and maintained flat rheology profile. The emulsion stability was slightly decreased and stayed close to the recommended value (400 V). The fluid loss was controlled by optimizing the concentration of fluid loss additive and oil wetter. The presence of oil wetter improved the carrying capacity of drilling fluids and prevented the barite sag problem. The zeta potential test confirmed that the oil wetter converted the surface of barite from water to oil and improved its dispersion in the oil.
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Marum, Daniela Martins, Maria Diná Afonso, and Brian Bernardo Ochoa. "Rheological behavior of a bentonite mud." Applied Rheology 30, no. 1 (January 1, 2020): 107–18. http://dx.doi.org/10.1515/arh-2020-0108.
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Abstract Predicting drilling fluids rheology is crucial to control/optimize the drilling process and the gas extraction from drilling fluids in logging systems. A Couette viscometer measured the apparent viscosity of a bentonite mud at various shear rates and temperatures. The bentonite mud behaved as a yield-pseudoplastic fluid, and a modified Herschel-Bulkley model predicted the shear rate and temperature effects upon the shear stress. A pipe viscometer was built to seek a correlation between the mud flow rate and the pressure drop and thereby determine refined Herschel-Bulkley parameters. Coupling a rheological model to a pipe viscometer enables the continuous acquisition of apparent viscosities of Newtonian or non-Newtonian fluids at a rig-site surface.
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Wu, Pengcheng, Chengxu Zhong, Zhengtao Li, Zhen Zhang, Zhiyuan Wang, and Weian Huang. "Oil-Based Drilling Fluid Plugging Method for Strengthening Wellbore Stability of Shale Gas." Geofluids 2021 (February 16, 2021): 1–13. http://dx.doi.org/10.1155/2021/6674574.
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Finding out the reasons for wellbore instability in the Longmaxi Formation and Wufeng Formation and putting forward drilling fluid technical countermeasures to strengthen and stabilize the wellbore are very crucial to horizontal drilling. Based on X-ray diffraction, electron microscope scanning, linear swelling experiment, and hot-rolling dispersion experiment, the physicochemical mechanism of wellbore instability in complex strata was revealed, and thus, the coordinated wellbore stability method can be put forward, which is “strengthening plugging of micropores, inhibiting filtrate invasion, and retarding pressure transmission.” Using a sand bed filtration tester, high-temperature and high-pressure plugging simulation experimental device, and microporous membrane and other experimental devices, the oil-based drilling fluid treatment agent was researched and selected, and a set of an enhanced plugging drilling fluid system suitable for shale gas horizontal well was constructed. Its temperature resistance is 135°C and it has preferable contamination resistibility (10% NaCl, 1% CaCl2, and 8% poor clay). The bearing capacity of a 400 μm fracture is 5 MPa, and the filtration loss of 0.22 μm and 0.45 μm microporous membranes is zero. Compared with previous field drilling fluids, the constructed oil-based drilling fluid system has a greatly improved plugging ability and excellent performance in other aspects.
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Veisi, Erfan, Mastaneh Hajipour, and Ebrahim Biniaz Delijani. "Experimental study on thermal, rheological and filtration control characteristics of drilling fluids: effect of nanoadditives." Oil & Gas Science and Technology – Revue d’IFP Energies nouvelles 75 (2020): 36. http://dx.doi.org/10.2516/ogst/2020033.
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Cooling the drill bit is one of the major functions of drilling fluids, especially in high temperature deep drilling operations. Designing stable drilling fluids with proper thermal properties is a great challenge. Identifying appropriate additives for the drilling fluid can mitigate drill-bit erosion or deformation caused by induced thermal stress. The unique advantages of nanoparticles may enhance thermal characteristics of drilling fluids. The impacts of nanoparticles on the specific heat capacity, thermal conductivity, rheological, and filtration control characteristics of water‐based drilling fluids were experimentally investigated and compared in this study. Al2O3, CuO, and Cu nanoparticles were used to prepare the water-based drilling nanofluid samples with various concentrations, using the two-step method. Transmission Electron Microscopy (TEM) and X-Ray Diffraction (XRD) were utilized to study the nanoparticle samples. The nanofluids stability and particle size distribution were, furthermore, examined using Dynamic Light Scattering (DLS). The experimental results indicated that thermal and rheological characteristics are enhanced in the presence of nanoparticles. The best enhancement in drilling fluid heat capacity and thermal conductivity was obtained as 15.6% and 12%, respectively by adding 0.9 wt% Cu nanoparticles. Furthermore, significant improvement was observed in the rheological characteristics such as the apparent and plastic viscosities, yield point, and gel strength of the drilling nanofluids compared to the base drilling fluid. Addition of nanoparticles resulted in reduced fluid loss and formation damage. The permeability of filter cakes decreased with increasing the nanoparticles concentration, but no significant effect in filter cake thickness was observed. The results reveal that the application of nanoparticles may reduce drill-bit replacement costs by improving the thermal and drilling fluid rheological characteristics and decrease the formation damage due to mud filtrate invasion.
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Xu, Lin, Lin Zhao, Ming Biao Xu, Jie Xu, and Xu Wang. "Lab Investigations into High Temperature High Pressure Rheology of Water-Based Drilling Fluid." Applied Mechanics and Materials 418 (September 2013): 191–95. http://dx.doi.org/10.4028/www.scientific.net/amm.418.191.
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HTHP rheology was investigated for the water-based drilling fluid applied in Yuanba region of Southwest Gas Fields in China. The results showed that under the conditions of temperature up to 180°C and pressure up to 100MPa, the Bingham plastic model is adequate to predict transient rheology at the given HTHP conditions. Effects of temperature on rheology are more dominant than that of pressure, but the latter will enhance at high temperatures and low shear rates. Finally, HTHP viscosity models were established and evaluated for water-based drilling fluid.
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Błaż, Sławomir, Grzegorz Zima, Bartłomiej Jasiński, and Marcin Kremieniewski. "Invert Drilling Fluids with High Internal Phase Content." Energies 14, no. 15 (July 27, 2021): 4532. http://dx.doi.org/10.3390/en14154532.
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One of the most important tasks when drilling a borehole is to select the appropriate type of drilling fluid and adjust its properties to the borehole’s conditions. This ensures the safe and effective exploitation of the borehole. Many types of drilling fluids are used to drill holes for crude oil and natural gas. Most often, mainly due to cost and environmental constraints, water-based muds are used. On the other hand, invert drilling fluids are used for drilling holes in difficult geological conditions. The ratio of the oil phase to the water phase in invert drilling fluids the most common ratio being from 70/30 to 90/10. One of the disadvantages of invert drilling fluids is their cost (due to the oil content) and environmental problems related to waste and the management of oily cuttings. This article presents tests of invert drilling fluids with Oil-Water Ratio (OWR) 50/50 to 20/80 which can be used for drilling HPHT wells. The invert drilling fluids properties were examined and their resistance to temperature and pressure was assessed. Their effect on the permeability of reservoir rocks was also determined. The developed invert drilling fluids are characterized by high electrical stability ES above 300 V, and stable rheological parameters and low filtration. Due to the reduced content of the oil, the developed drilling fluid system is more economical and has limited toxicity.
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Konate, Nabe, and Saeed Salehi. "Experimental Investigation of Inhibitive Drilling Fluids Performance: Case Studies from United States Shale Basins." Energies 13, no. 19 (October 2, 2020): 5142. http://dx.doi.org/10.3390/en13195142.
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Shale formations are attractive prospects due to their potential in oil and gas production. Some of the largest shale formations in the mainland US, such as the Tuscaloosa Marine Shale (TMS), have reserves estimated to be around 7 billion barrels. Despite their huge potential, shale formations present major concerns for drilling operators. These prospects have unique challenges because of all their alteration and incompatibility issues with drilling and completion fluids. Most shale formations undergo numerous chemical and physical alterations, making their interaction with the drilling and completion fluid systems very complex to understand. In this study, a high-pressure, high-temperature (HPHT) drilling simulator was used to mimic real time drilling operations to investigate the performance of inhibitive drilling fluid systems in two major shale formations (Eagle Ford Shale and Tuscaloosa Marine Shale). A series of drilling experiments using the drilling simulator and clay swelling tests were conducted to evaluate the drilling performance of the KCl drilling fluid and cesium formate brine systems and their effectiveness in minimizing drilling concerns. Cylindrical cores were used to mimic vertical wellbores. It was found that the inhibitive muds systems (KCl and cesium formate) provided improved drilling performance compared to conventional fluid systems. Among the inhibitive systems, the cesium formate brine showed the best drilling performances due to its low swelling rate and improved drilling performance.
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Xu, Lin, Han Gao, Ming-biao Xu, Fu-chang You, and Xiao-liang Wang. "RDR Application: An Accurate HTHP Rheological Modeling for The Sulphonated Water-Based Drilling Fluid." Open Petroleum Engineering Journal 10, no. 1 (November 30, 2017): 251–62. http://dx.doi.org/10.2174/1874834101710010251.
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Introduction: An accurate HTHP rheological model of drilling fluids is critical for the safe and economic drilling operation. However, general HTHP rheological modeling methods appear to be very limited in the predictive accuracy. Materials and Method: In this work, a particular relative dial readings(RDR) modeling experiment was conducted on a weighted sulphonated water-based drilling fluid within a certain temperature and pressure range(30-150°C, 0.1-100MPa), in combination to dial reading data of six specific shear rates 3, 6, 100, 200, 300, and 600rpm, to develop a highly accurate HTHP rheological model. The RDR modeling procedure was investigated in details, including relative dial reading, Arrhenius relation, polynomial of pressure coefficients, and polynomial of shear rate coefficients. An equation relating RDR to temperature, pressure, and shear rate was determined. Results: The predictive deviation was calculated to be lower than 11.7%, and large errors occurred under the conditions of high pressure and low shear rates; all of which meet the requirement of in-field predictive accuracy. These results not only provide an accurate HTHP rheological equation for the weighted sulphonated water-based drilling fluid, but also propose an effective HTHP rheological modeling strategy for drilling fluids.
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Falih, Ghufran Falih, Asawer A. Alwasiti Alwasiti, and Nada S. Alzubaidi Alzubaidi. "Improving the Performance of Drilling Fluid Using MgO Nano Particles." Journal of Petroleum Research and Studies 8, no. 3 (May 6, 2021): 179–93. http://dx.doi.org/10.52716/jprs.v8i3.278.
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One of the most important factors that cause formation damage is drilling fluidinvasion caused by mud filtration. Hence, it is essential to minimize the mud filtration inorder to reduce its damage to the formation using drilling fluid additives that control andminimize the filtration rate. Magnesium Oxide (MgO) nanoparticles at different masses(0.01, 0.05, 0.07, 0.1, and 0.2) gm with water base mud have been investigated in thisresearch to measure its effect on the filtration rate. Four types of drilling fluid are used inthis research; API water base mud WBM, Saturated salt water mud, DURA THERM mudand polymer mud. Filtration rate was tested under high temperature high pressure (HTHP)conditions; at (75 and 100) C and (500 psi), and at room temperature and pressure at (100psi). The viscosity of all drilling fluid types is measured using a rotational viscometer atroom temperature and atmospheric pressure. In general, the results showed that addingMgO nano particle helped in reducing the filtration rate of drilling fluid, the best resultswere gained in DURA THERM mud and Saturated Salt Water Mud at MgOconcentrationof 0.07gm and 0.2gm, respectively; where the filtrate reduction 60% at 100C. Also, MgO addition improves rheological properties and drilling fluid stability
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Quan, Hongping, Huan Li, Zhiyu Huang, Tailiang Zhang, and Shanshan Dai. "Copolymer SJ-1 as a Fluid Loss Additive for Drilling Fluid with High Content of Salt and Calcium." International Journal of Polymer Science 2014 (2014): 1–7. http://dx.doi.org/10.1155/2014/201301.
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A ternary copolymer of 2-acrylamide-2-methyl propane sulfonic acid (AMPS), acrylamide (AM), and allyl alcohol polyoxyethylene ether (APEG) with a side chain polyoxyethylene ether(C2H4O)nSJ-1 were designed and synthesized in this work. Good temperature resistance and salt tolerance of “–SO3-” of AMPS, strong absorption ability of “amino-group” of AM, and good hydrability of side chain polyoxyethylene ether(C2H4O)nof APEG provide SJ-1 excellent properties as a fluid loss additive. The chemical structure of ternary copolymer was characterized by Fourier transform infrared (FTIR) spectroscopy. The molecular weight and its distribution were determined by gel permeation chromatography (GPC). The API fluid loss of drilling fluid decreased gradually with the increasing concentration of NaCl and CaCl2in the mud system. SJ-1 was applied well in the drilling fluid even at a high temperature of 220°C. Results of zeta potential of modified drilling fluid showed the dispersion stability of drilling fluid system. Scanning electron microscopy (SEM) analysis showed the microstructure of the surface of the filter cake obtained from the drilling fluid modified by SJ-1.
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Wheat, C. Geoffrey, Christopher Kitts, Camden Webb, Rachel Stolzman, Ann McGuire, Trevor Fournier, Thomas Pettigrew, and Hans Jannasch. "A new high-temperature borehole fluid sampler: the Multi-Temperature Fluid Sampler." Scientific Drilling 28 (December 1, 2020): 43–48. http://dx.doi.org/10.5194/sd-28-43-2020.
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Abstract. Deep (>1 km depth) scientific boreholes are unique assets that can be used to address a variety of microbiological, hydrologic, and biogeochemical hypotheses. Few of these deep boreholes exist in oceanic crust. One of them, Deep Sea Drilling Project Hole 504B, reaches ∼190 ∘C at its base. We designed, fabricated, and laboratory-tested the Multi-Temperature Fluid Sampler (MTFS), a non-gas-tight, titanium syringe-style fluid sampler for borehole applications that is tolerant of such high temperatures. Each of the 12 MTFS units collects a single 1 L sample at a predetermined temperature, which is defined by the trigger design and a shape memory alloy (SMA). SMAs have the innate ability to be deformed and only return to their initial shapes when their activation temperatures are reached, thereby triggering a sampler at a predetermined temperature. Three SMA-based trigger mechanisms, which do not rely on electronics, were tested. Triggers were released at temperatures spanning from 80 to 181 ∘C. The MTFS was set for deployment on International Ocean Discovery Program Expedition 385T, but hole conditions precluded its use. The sampler is ready for use in deep oceanic or continental scientific boreholes with minimal training for operational success.
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Elkatatny, Salaheldin. "Enhancing the Stability of Invert Emulsion Drilling Fluid for Drilling in High-Pressure High-Temperature Conditions." Energies 11, no. 9 (September 11, 2018): 2393. http://dx.doi.org/10.3390/en11092393.
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Drilling in high-pressure high-temperature (HPHT) conditions is a challenging task. The drilling fluid should be designed to provide high density and stable rheological properties. Barite is the most common weighting material used to adjust the required fluid density. Barite settling, or sag, is a common issue in drilling HPHT wells. Barite sagging may cause many problems such as density variations, well-control problems, stuck pipe, downhole drilling fluid losses, or induced wellbore instability. This study assesses the effect of using a new copolymer (based on styrene and acrylic monomers) on the rheological properties and the stability of an invert emulsion drilling fluid, which can be used to drill HPHT wells. The main goal is to prevent the barite sagging issue, which is common in drilling HPHT wells. A sag test was performed under static (vertical and 45° incline) and dynamic conditions in order to evaluate the copolymer’s ability to enhance the suspension properties of the drilling fluid. In addition, the effect of this copolymer on the filtration properties was performed. The obtained results showed that adding the new copolymer with 1 lb/bbl concentration has no effect on the density and electrical stability. The sag issue was eliminated by adding 1 lb/bbl of the copolymer to the invert emulsion drilling fluid at a temperature >300 °F under static and dynamic conditions. Adding the copolymer enhanced the storage modulus by 290% and the gel strength by 50%, which demonstrated the power of the new copolymer to prevent the settling of the barite particles at a higher temperature. The 1 lb/bbl copolymer’s concentration reduced the filter cake thickness by 40% at 400 °F, which indicates the prevention of barite settling at high temperature.
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Wang, Jian Hua, Jian Nan Li, Li Li Yan, and Yi Hui Ji. "Preparation of a Novel Nano-Polymer as Plugging and Filtration Loss Agent for Oil-Based Drilling Fluids." Advanced Materials Research 807-809 (September 2013): 2602–6. http://dx.doi.org/10.4028/www.scientific.net/amr.807-809.2602.
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Oil-based drilling fluids and synthetic based drilling fluids are frequently used in shale-gas plays when wellbore stability is necessary. In this paper, a novel nano-polymer, as a plugging agent in oil-based drilling fluid, was prepared and characterized by Fourier transform infrared (FTIR), thermo-gravimetric analyses (TGA) and scanning electron microscopy (SEM). The rheological properties, high temperature-high pressure (HTHP) filtration properties and permeability plugging properties of oil-based drilling fluids were greatly improved by adding the nano-polymer, due to its nanometer size and the compact layer formed on the surface of the core.
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Karfakis, M. G., and R. W. Heins. "Laboratory Measurement of Bit Bearing Temperatures in Rotary Drilling With the Garter Spring Pick-up System." Journal of Engineering for Industry 111, no. 3 (August 1, 1989): 187–92. http://dx.doi.org/10.1115/1.3188748.
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In order to determine the factors affecting bearing temperatures—factors such as formation temperatures, rotary speed, bit thrust, airflow rate, and temperature—a pilot-scale laboratory micro-bit drill rig was instrumented. The paper describes the successful control of variables and measurements of bearing temperature of a thermocouple instrumented micro-bit using the garter spring pick-up system. The first step in tapping the energy of a geothermal reservoir, once it is located, is drilling the necessary wells to allow the heat energy to be transported to the surface. Currently, drilling for geothermal wells in elevated temperature formations is done using unsealed bits with air as the drilling fluid. Reduced bit life, due to bearing failure, with the consequent reduced overall penetration rates, can be attributed to the high temperature encountered. Limited knowledge and understanding of how temperature affects drilling operations is a deterrent to the improvement of the existing drilling system.
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Bybee, Karen. "Formate-Based Reservoir-Drilling Fluid Meets High-Temperature Challenges." Journal of Petroleum Technology 58, no. 11 (November 1, 2006): 57–59. http://dx.doi.org/10.2118/1106-0057-jpt.
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Elward-Berry, Julianne, and J. B. Darby. "Rheologically Stable, Nontoxic, High-Temperature Water-Base Drilling Fluid." SPE Drilling & Completion 12, no. 03 (September 1, 1997): 158–62. http://dx.doi.org/10.2118/24589-pa.
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