Relevant bibliographies by topics / Water-based drilling fluids

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

Academic literature on the topic 'Water-based drilling fluids'

Author: Grafiati
Published: 4 June 2025
Last updated: 23 June 2025

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Journal articles on the topic "Water-based drilling fluids"

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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2

Yalman, Emine, Gabriella Federer-Kovacs, and Tolga Depci. "Development of Water-Based Drilling Fluid in Mitigation of Differential Sticking Tendency." Rudarsko-geološko-naftni zbornik 38, no. 2 (2022): 13–21. http://dx.doi.org/10.17794/rgn.2022.2.2.

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The objective of the study is to design a drilling fluid that prevents differential pressure pipe sticking tendency caused by drilling fluid with fly ash that is an industrial waste generated from the combustion of coal. To this end, drilling fluid samples were prepared with different particle sizes obtained through the sieving and grinding process and increasing concentrations of fly ash. Differential pipe sticking tests of the samples were performed by applying 3.447 MPa (500 psi) pressure and using a Fann Model 21150 Differential Sticking Tester in order to determine how the coefficient of sticking and torque reading varied with the fly ash. From the results, it was observed that the coefficient of sticking and torque reading of the water-based drilling fluids decreased up to a specific concentration as the concentration of fly ash increased. Furthermore, particle size analysis illustrated that the coefficient of sticking and torque of the drilling fluid differs depending on the particle size of fly ash introduced. The drilling fluid designed with ground fly ash demonstrated lower sticking coefficient and torque reading than that of drilling fluids formulated with raw and sieved fly ashes. The experimental study revealed that fly ash is a promising additive in the mitigation of differential sticking tendency caused by water-based drilling fluids.
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Belayneh, Mesfin, Bernt Aadnøy, and Simen Moe Strømø. "MoS2 Nanoparticle Effects on 80 °C Thermally Stable Water-Based Drilling Fluid." Materials 14, no. 23 (2021): 7195. http://dx.doi.org/10.3390/ma14237195.

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Bentonite-based drilling fluids are used for drilling, where inhibitive fluids are not required. The rheological and the density properties of the drilling fluids are highly affected by high temperature and pressure. Due to high temperature, the clay particles stick together, and the fluid system becomes more flocculated. Poorly designed drilling fluid may cause undesired operational issues such as poor hole cleaning, drill strings sticking, high torque and drag. In this study, the 80 °C thermally stable Herschel Bulkley’s and Bingham plastic yield stresses drilling fluids were formulated based on lignosulfonate-treated bentonite drilling fluid. Further, the impact of a MoS2 nanoparticle solution on the properties of the thermally stable base fluid was characterized. Results at room temperature and pressure showed that the blending of 0.26 wt.% MoS2 increased the lubricity of thermally stable base fluid by 27% and enhanced the thermal and electrical conductivities by 7.2% and 8.8%, respectively.
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4

Xie, Gang, Ming Yi Deng, Jun Lin Su, and Liang Chun Pu. "Study on Shale Gas Drilling Fluids Technology." Advanced Materials Research 868 (December 2013): 651–56. http://dx.doi.org/10.4028/www.scientific.net/amr.868.651.

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Via discussing the advantages and disadvantages of different types of oil-based drilling fluids, the main reason why oil-based drilling fluids are less used in our country is obtained that dont form a complete series of matching technology. The essence of wellbore instability caused by using water-based drilling fluids to drill shale is analyzed that the formation collapse pressure is greater than drilling fluids column pressure. The fundamental way of controlling borehole wall stability that use water-based drilling fluids to drill shale horizontal well was proposed that deeply researched the shale hydration mechanism, developed efficient blocking agent and inhibitors and established shale gas drilling fluid suppression system, which made water-based drilling fluids have excellent performance.
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Momeni, Ali, Seyyed Shahab Tabatabaee Moradi, and Seyyed Alireza Tabatabaei-Nejad. "A REVIEW ON GLYCEROL-BASED DRILLING FLUIDS AND GLYCERINE AS A DRILLING FLUID ADDITIVE." Rudarsko-geološko-naftni zbornik 39, no. 1 (2024): 87–99. http://dx.doi.org/10.17794/rgn.2024.1.8.

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A significant increase of energy demands all over the world and production decline from available oil and gas reservoirs have led the industry to invest in major offshore petroleum resources. However, drilling operations in offshore environments are usually restricted by environmental constraints. Therefore, recent studies are devoted to the development of environmentally compatible fluids with adequate technical properties. Glycerine is a non-toxic, lubricating, colorless, odorless substance with a higher density than water. Due to the properties of glycerine, it can be used as the base of drilling fluid to formulate synthetic-based fluids. This research aimed to review the studies on the applications of glycerine in the composition of drilling fluid. Based on the results, glycerine-based fluids can be considered as an environmentally compatible fluid with sufficient technical properties to replace other drilling fluids. However, there is a lack of experimental studies on the glycerine fluid properties for a reliable decision. For the application of glycerine fluids, an economic feasibility study is mandatory for both pure and crude glycerine. Also, the thermal stability of glycerine fluids is an important aspect, which should be covered in future research studies.
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Nekrasova, I. L., P. A. Khvoshchin, D. A. Kazakov, and O. V. Garshina. "Water-based drilling fluids utilization." Environmental Protection in Oil and Gas Complex, no. 4 (2022): 5–13. http://dx.doi.org/10.33285/2411-7013-2022-4(307)-5-13.

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7

Vamsi, Krishna Kudapa. "Experimental investigation of water based drilling mud by using graphene." i-manager's Journal on Material Science 10, no. 2 (2022): 9. http://dx.doi.org/10.26634/jms.10.2.19037.

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In the oil and gas industry, the need for a particular composition-based drilling mud is characterized by its rheological and fluid loss properties. Enhancing these properties will increase the efficiency of drilling fluid and, hence, the wellbore damage will be controlled. Recent advancements show that the application of nanoparticles in drilling fluids will enhance their efficiency. This research investigates the influence of adding graphene nanoparticles on the performance of water-based drilling fluids. The main objective of this experiment was to investigate the effect of nanoparticles on water-based drilling mud with different concentrations of nanoparticles added to the mud.
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Feneuil, Blandine, Bjørnar Lund, Inga Synnøve Nordhus, et al. "Flow Curves and Fluid Loss of Water-Based Drilling Fluids." Annual Transactions of the Nordic Rheology Society 33 (May 9, 2025): 103–16. https://doi.org/10.31265/atnrs.870.

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A drilling fluid must fulfill numerous functions during well drilling, ranging from particle transport, lubrication, to wall stabilization. In that aim, the composition is carefully chosen by the drilling engineer for each well section according to the required properties such as density, rheological properties, chemical stability, and fluid loss. In particular, fluid loss refers to the penetration of the liquid from the drilling fluid into the rock formation. It must be controlled and preferably avoided as it may reduce the permeability of the formation and change the fluid properties due to the depletion of the liquid. Fluids with low fluid loss can form an impermeable filter cake at the rock surface, i.e., a layer of accumulated particles on the wall of the well. As interest in CO2 storage has increased in the last decade, the need to design drilling fluids for CO2 well drilling has arisen. Lots of knowledge is inherited from oil & gas wells, and still, CO2 wells pose new challenges. These wells should not be optimized for production (receiving fluids from the formation into the well), but for injection (injecting CO2 from the well into the rock formation). Here, we present an experimental study aiming to optimize drilling fluids' rheological properties and fluid loss for CO2 wells. Flow curves are measured using a Couette cell in an Anton Paar rheometer. Fluid loss and filter cake formation are evaluated with a filter press. We investigate the effect of the fluid components on the flow curve, the fluid loss, and the filter cake mass.
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Shudryk, Oleksandr, Nataliia Shevchenko, Kseniya Rezvaya, Maryna Petruniak, and Viktor Bovkun. "FLOW ANALYSIS IN A ROLLER DRILL BIT DURING DRILLING USING WATER-BASED AND HYDROCARBON-BASED MUD." Bulletin of the National Technical University "KhPI". Series: Hydraulic machines and hydraulic units, no. 1 (November 29, 2024): 58–64. https://doi.org/10.20998/2411-3441.2024.1.08.

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Drilling is the main type of increase in hydrocarbon production. Bits of various types are used as a rock-destroying tool during drilling. When drilling any wells for oil and gas, drilling fluids are used as a working fluid. The flow of these types of liquids differs from the flow of water, which is an incompressible medium. The purpose of this work is to study the flow of the Newtonian fluid of water and two types of water-based drilling fluids, which is described by the power-law model of a non-Newtonian fluid and the hydrocarbon-based fluid of the Herschel-Bulkley type. In the work, the construction of the geometric model of the square bit was carried out, and the estimated unstructured grid of the liquid volume filling the internal area of the bit and the space behind the bit was constructed. Calculations of the three-dimensional flow of water, drilling fluids on water and hydrocarbon bases were carried out using the open platform OpenFOAM. It was found that during the flow of liquids described by non-Newtonian models, the kinematic viscosity of the liquid changes depending on the velocities and shear stresses. Another important factor in the use of non-Newtonian fluids when drilling wells is the reduction of hydraulic losses during their flow. This is achieved due to the presence of a certain structure of the liquid, non- zero values of shear stresses, lubricating properties even with their viscosity, which is ten times higher than the viscosity of water. Visualization of the flow of three types of fluids: Newtonian, non-Newtonian power-law and non-Newtonian Herschel-Bulkley type is presented. The use of non- Newtonian fluids makes it possible to reduce the formation of vortices and, as a result, also affects the amount of hydraulic losses in the direction of their reduction.
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Dong, Pu, Ren, Zhai, Gao, and Xie. "Thermoresponsive Bentonite for Water-Based Drilling Fluids." Materials 12, no. 13 (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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Dissertations / Theses on the topic "Water-based drilling fluids"

1

Kristensen, Aleksander. "Flow properties of water-based drilling fluids." Thesis, Norges teknisk-naturvitenskapelige universitet, Institutt for petroleumsteknologi og anvendt geofysikk, 2013. http://urn.kb.se/resolve?urn=urn:nbn:no:ntnu:diva-23107.

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The objective of this master thesis was to investigate the flow properties of water based drilling fluids, utilizing measurements in both the micro and macro scale. The research was performed on two realistic drilling fluids by the use of a viscometer, a rheometer and a realistic flow loop, where the latter represents the macro scale. The research outcome could possibly improve the understanding of flow behavior in wellbores, and remove uncertainties associated with annular friction. The two fluids utilized in the research was made up with the goal of having equal rheological qualities, when measured with a Fann 35 viscometer. A more thorough examination of the two fluid's rheology was then executed by using a Anton Paar MCR302 rheometer. The macroscopic properties was researched employing a flow loop, capable of simulating realistic wellbore conditions.The main outcome of this thesis is that even though two fluids appear to have the same rheoligical properties when measured on simple equipment, their fundamental different microscopic structure will exhibit variations when the fluids are utilized in real applications.Due to problems encountered when mixing the fluids, as well as problems with one of the fluids itself, not all intended experiments were conducted. The experiments should be replicated with an emphasis on temperature control, avoiding bubbles and foam, and be conducted within a shorter time period.
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Peng, Shuang Jiu. "Filtration properties of water based drilling fluids." Thesis, Heriot-Watt University, 1990. http://hdl.handle.net/10399/871.

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This thesis reports an experimental and theoretical study on filtration properties of water based drilling fluids under dynamic and static conditions. The tested muds cover Freshwater/Gypsum/Lignosulphonate mud and SeawaterlKCLlPolymer mud, bariteweighted and unweighted. The effects of the solid concentration, pressure and shear rate on the filter cake characteristics and the erodability were investigated. For static filtration experiments, all tests were conducted for two hours and the spurt loss, the filter cake thickness, the ratio of wet to dry cake mass and the cumulative filtrate volume against time were measured. For dynamic filtration experiments, however, only the spurt loss and the cumulative filtrate volume against time were measured and all tests were conducted for at least 8 hours. A general filtration equation was developed based on the cake filtration theory prevailing in the chemical engineering industry and it was utilised to obtain the modified classic static filtration equation and the dynamic filtration equation. The modified classic static filtration equation was then employed to fit the static filtration experimental data and the average specific static cake resistance and the effective filter medium resistance were calculated. The dynamic filtration equation showed a substantial agreement with the dynamic filtration experimental data. Using the static filter cake properties such as the ratio of wet to dry cake mass (m), the average specific dynamic cake resistance, the effective filter medium resistance and the dynamic filter cake erodability were calculated. In the study of the relationship between the static filtration data and the dynamic filtration data, an attempt of predicting the dynamic filtration data from the static filtration experimental data was conducted. Also, an attempt was carried out to predict the static filtration data and the dynamic filtration data in a sequential process. The experimental data suggests that a substantial difference exists between the specific resistances of static and dynamic filter cakes. No apparent distinction was found, however, between spurt loss and effective filter medium resistance. The reodability of dynamically deposited mud cake for Seawater/KCL/Polymer mud was found to be three fold for Freshwater/Gypsum/Lignosulphonate.
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Sia, Luke Kennedy Si Lung. "Improving rheological and filtration properties of water based drilling fluid using palm derived methyl ester sulphonate surfactant and waste polystyrene nano-particle." Thesis, Curtin University, 2018. http://hdl.handle.net/20.500.11937/74950.

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A new mud was formulated to improve the drilling efficiency under HPHT condition using green surfactant and nano-polystyrene. A series of rheological and filtration tests were done to ensure that the mud can maintain its integrity once used in ultra-deep wells. Scanning electron microscope based image analysis was done to evaluate the plugging abilities of nanopolystyrene. It was found that the nano-polystyrene is able to improve the performance of the mud under different conditions.
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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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Al, Mojil Abdullah Mohammed A. "Removal of Filter Cake Generated by Manganese Tetraoxide Water-based Drilling Fluids." Thesis, 2010. http://hdl.handle.net/1969.1/ETD-TAMU-2010-08-8335.

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Three effective solutions to dissolve the filter cake created by water-based drilling fluids weighted with Mn3O4 particles were developed. Hydrochloric acid at concentration lower than 5 wt% can dissolve most of Mn3O4-based filter cake. Dissolving the filter cake in two-stage treatment of enzyme and organic acid was effective and eliminated the associated drawbacks of using HCl. Finally, combining low and safe concentration of HCl with an organic acid in one-stage treatment was very effective. Hydrochloric acid (10-wt%) dissolved 78 wt% of Mn3O4-based filter cake at 250°F after 28 hours soaking time. However, Chlorine gas was detected during the reaction of 5 to 15-wt% HCl with Mn3O4 particles. At 190°F, 1- and 4-wt% HCl dissolved most Mn3O4 particles (up to 70-wt% solubility). Their reactions with Mn3O4 particles followed Eq. 8 at 190°F, which further confirmed the absence of chlorine gas production at HCl concentrations lower than 5-wt%. EDTA and DTPA at high pH (12) and acetic, propionic, butyric, and gluconic acids at low pH (3-5) showed very low solubilities of Mn3O4 particles. GLDA, citric, oxalic, and tartaric acids produced large amount of white precipitation upon the reactions with Mn3O4 particles. Similarly, DTPA will produce damaging material if used to dissolve Mn3O4-based filter cake in sandstone formation. At 4-wt% acid concentration, lactic, glycolic, and formic acids dissolved Mn3O4 particles up to 76 wt% solubility at 190°F. Malonic acid at lower concentration (2-wt%) dissolved 54 wt% of Mn3O4 particles at 190°F. Manganese tetraoxide particles were covered with polymeric material (starch), which significantly reduced the solubility of filter cake in organic acids. Therefore, there was a need to remove Mn3O4-based filter cake in two-stage treatment. Enzyme-A (10-wt%) and Precursor of lactic acid (12.5-wt%) dissolved 84 wt% of the filter cake. An innovative approach led to complete solubility of Mn3O4 particles when low and safe concentration of HCl (1-wt%) combined with 4-wt% lactic acid at 190°F. HCl (1-wt%) combined with lactic acid (4-wt%), dissolved 85 wt% of the Mn3O4-based filter cake after 18-22 hours soaking time at 250°F in one stage treatment.
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Elkatatny, Salaheldin Mahmoud. "New Techniques to Characterize and Remove Water-Based Drilling Fluids Filter Cake." Thesis, 2013. http://hdl.handle.net/1969.1/149400.

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Filter cake characterization is very important in drilling and completion operations. Heterogeneity of the filter cake plays a key role in the design of chemical treatments needed to remove the filter cake. The objectives of this study are to characterize the filter cake under static and dynamic conditions, evaluate the using of polylactic acid and chelating agents to remove calcium carbonate-based filter cake, assess glycolic acid to remove Mn3O4-based filter cake, and evaluate ilmenite as a weighting material for water-based drilling fluid. In order to characterize the filter cake, computer tomography (CT) was used in combination with the scanning electronic microscopy (SEM) to analyze the filter cake. A modified HPHT filter cell was developed to perform the filtration tests. A see-through-cell was used to check the compatibility of different chemicals that were used to remove the filter cake. The results obtained from the CT scan showed that the filter cake was heterogeneous and contained two layers with different properties under static and dynamic conditions. Under static conditions, the formation of filter cake changed from compression to buildup; while under dynamic conditions, the filter cake was formed under continuous buildup. Polylactic acid was used as a component of the drilling fluid components and the results obtained showed that the drill-in fluid had stable rheological properties up to 250˚F over 24 hrs. The removal efficiency of the filter cake was nearly 100% and the return permeability was about 100% for Indiana limestone and Berea sandstone cores, when using a weight ratio of polylactic acid to calcium carbonate 3 to 1. GLDA (pH 3.3) and HEDTA (pH 4) can be used to remove the filter cake in one step without using α-amylase enzyme solutions. GLDA (20 wt% in a 200 g solution and pH of 3.3) and HEDTA (20 wt% in a 200 g solution and pH 4) had 100% removal efficiency of the filter cake using Indiana limestone and Berea sandstone cores. Chelate solutions, GLDA (pH of 3.3 - 13) and HEDTA (pH of 4 and 7) were incompatible with α-amylase enzyme solutions over a wide range of temperatures. CT results showed that no formation damage was observed when using chelating agents as a breaker to remove the calcium carbonate filter cake. Manganese tetraoxide-based filter cake had a removal efficiency of 85% after 20 hrs soaking with glycolic acid (5 wt%) after soaking with α-amylase for 24 hrs, and 89% after reaction with acid mixture (1 wt% HCl and 7 wt% glycolic acid) for 16 hrs. for both methods, the retained permeability was 100% for Indiana limestone cores and 120% for Berea sandstone cores, which indication maximum productivity of these formations. Ilmenite-based filter cake was ideal for HPHT applications, 0.2 in. thickness and 12 cm3 filtrate under dynamic conditions. The filtrate volume was reduced by adding a minor amount of CaCO3 solids that improved the particles packing. No sag problem was observed when using the micronized ilmenite in water-based drilling fluids. Ilmenite has a negative zeta potential in alkaline media and had a stable dispersion in water at pH > 7.
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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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Books on the topic "Water-based drilling fluids"

1

United States. Environmental Protection Agency. Office of Water and National Health and Environmental Effects Research Laboratory (U.S.). Gulf Ecology Division, eds. Synthetic-based drilling fluids: An assessment of the spatial distribution of toxicants in sediments from Gulf of Mexico drilling platforms : a report prepared for the Office of Water. U.S. Environmental Protection Agency, National Health and Environmental Effects Research Laboratory, Gulf Ecology Division, 1998.

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United States. Environmental Protection Agency. Office of Water and National Health and Environmental Effects Research Laboratory (U.S.). Gulf Ecology Division, eds. Synthetic-based drilling fluids: An assessment of the spatial distribution of toxicants in sediments from Gulf of Mexico drilling platforms : a report prepared for the Office of Water. U.S. Environmental Protection Agency, National Health and Environmental Effects Research Laboratory, Gulf Ecology Division, 1998.

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United States. Environmental Protection Agency. Office of Water. and National Health and Environmental Effects Research Laboratory (U.S.). Gulf Ecology Division., eds. Synthetic-based drilling fluids: An assessment of the spatial distribution of toxicants in sediments from Gulf of Mexico drilling platforms : a report prepared for the Office of Water. U.S. Environmental Protection Agency, National Health and Environmental Effects Research Laboratory, Gulf Ecology Division, 1998.

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United States. Environmental Protection Agency. Office of Water and National Health and Environmental Effects Research Laboratory (U.S.). Gulf Ecology Division, eds. Synthetic-based drilling fluids: An assessment of the spatial distribution of toxicants in sediments from Gulf of Mexico drilling platforms : a report prepared for the Office of Water. U.S. Environmental Protection Agency, National Health and Environmental Effects Research Laboratory, Gulf Ecology Division, 1998.

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United States. Environmental Protection Agency. Office of Water. and National Health and Environmental Effects Research Laboratory (U.S.). Gulf Ecology Division., eds. Synthetic-based drilling fluids: An assessment of the spatial distribution of toxicants in sediments from Gulf of Mexico drilling platforms : a report prepared for the Office of Water. U.S. Environmental Protection Agency, National Health and Environmental Effects Research Laboratory, Gulf Ecology Division, 1998.

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Water-Based Chemicals and Technology for Drilling, Completion, and Workover Fluids. Elsevier, 2015. http://dx.doi.org/10.1016/c2014-0-02960-7.

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Fink, Johannes. Water-Based Chemicals and Technology for Drilling, Completion, and Workover Fluids. Elsevier Science & Technology Books, 2015.

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Water-Based Chemicals and Technology for Drilling, Completion, and Workover Fluids. Elsevier Science & Technology Books, 2015.

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Synthetic-based drilling fluids: An assessment of the spatial distribution of toxicants in sediments from Gulf of Mexico drilling platforms : a report prepared for the Office of Water. U.S. Environmental Protection Agency, National Health and Environmental Effects Research Laboratory, Gulf Ecology Division, 1998.

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Book chapters on the topic "Water-based drilling fluids"

1

Abu-Jdayil, Basim, and Mamdouh Ghannam. "Effect of Surfactants on the Performance of Water-Based Drilling Fluids." In Surfactants in Upstream E&P. Springer International Publishing, 2021. http://dx.doi.org/10.1007/978-3-030-70026-3_3.

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Wei, Liu, Lin Wenjie, Wang Lulu, and Quande Wang. "Study on the Performance of SMH Resin in Water-Based Drilling Fluids." In Springer Proceedings in Physics. Springer Nature Singapore, 2024. http://dx.doi.org/10.1007/978-981-97-3530-3_32.

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Li, He, Jin-sheng Sun, Kai-he Lv, and Xian-bin Huang. "Amine-Terminated Acrylamide Polymer as a Shale Inhibitor for Water-Based Drilling Fluids." In Springer Series in Geomechanics and Geoengineering. Springer Nature Singapore, 2023. http://dx.doi.org/10.1007/978-981-99-1964-2_388.

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Zhang, Fan, Zhi-hua Yong, Zhi-wen Dai, and Jin-sheng Sun. "A Copolymer Water-Based Drilling Fluids Fluid-Loss Additive for High-Temperature and Salt-Calcium Condition." In Springer Series in Geomechanics and Geoengineering. Springer Nature Singapore, 2023. http://dx.doi.org/10.1007/978-981-99-1964-2_402.

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Guo, Chunping, Guancheng Jiang, and Jintian Guan. "Hectorite Inorganic Nanoparticle as a Shear-Thixotropic Plugging Agent in Water-Based Drilling Fluids." In Springer Proceedings in Physics. Springer Nature Singapore, 2024. http://dx.doi.org/10.1007/978-981-97-3530-3_42.

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Dutta, Debashree, Akashdeep Hazarika, Angshuman Chetia, and Borkha Mech. "Synthesis of Green Nanoparticles from Plants and Their Applications in Water-Based Drilling Fluids." In Research and Innovation for Sustainable Development Goals. Springer Nature Singapore, 2024. http://dx.doi.org/10.1007/978-981-97-5870-8_4.

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Bardhan, Anirudh, Darshan Halari, Anurag Pandey, Amit Saxena, Shivanjali Sharma, and Shailesh Kumar. "Exploring the Role of Vinyl Copolymers in Next-Generation Water-Based Drilling Fluids for Geothermal Wells." In Lecture Notes on Multidisciplinary Industrial Engineering. Springer Nature Singapore, 2025. https://doi.org/10.1007/978-981-96-3667-9_10.

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Muhsan, Ali Samer, Norani M. Mohamed, Usman Siddiqui, and Muhammad U. Shahid. "Nano Additives in Water Based Drilling Fluid for Enhanced-Performance Fluid-Loss-Control." In ICIPEG 2016. Springer Singapore, 2017. http://dx.doi.org/10.1007/978-981-10-3650-7_57.

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Ye, Yuchen, Yong Guo, Nan Zhang, Yadong Li, and Zhongxi Zhu. "Research on Wellbore Temperature Control Method of Water-Based Drilling Fluid." In Computational and Experimental Simulations in Engineering. Springer Nature Switzerland, 2024. http://dx.doi.org/10.1007/978-3-031-44947-5_27.

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Yang, Xunkun, and Guancheng Jiang. "Application and Mechanism of Catechol-Based Amide Lubricant in Water-Based Drilling Fluid." In Environmental Science and Technology: Sustainable Development. Springer International Publishing, 2023. http://dx.doi.org/10.1007/978-3-031-27431-2_15.

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Conference papers on the topic "Water-based drilling fluids"

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Dewangan, Satish Kumar, Nishant Nathwani, and Ajay Kawade. "Experimental Evaluation of Rheological Properties of Water-Based Drilling Fluid with Fly Ash Additive." In 2024 8th International Conference on Materials Engineering and Nano Sciences & 2024 8th International Conference on Material Engineering and Manufacturing. Trans Tech Publications Ltd, 2024. http://dx.doi.org/10.4028/p-nrc2r2.

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Drilling fluid rheology is very important aspect for judging its suitability for the well-drilling operation. This study looked at how fly ash affected the rheological characteristics of drilling fluids that were based on water. Six different drilling fluid samples (combination of water-bentonite-fly ash) have been prepared: 4 samples without engine oil additives and 2 samples with engine oil additive. The shear stress between fluid layers vs. shear rate curves and the viscosity of fluid vs. shear rate curves have been plotted for the controlled shear rate application by rotational rheometer MCR 102 (Make: Anton-Paar Inc.). Curve fitting have been done successfully with the Herschel-Bulkley rheology model and various parameters have been obtained. It is found that addition of fly ash as well as additive oil imparts favorable rheology to water based drilling fluids.
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van Oort, Eric, R. G. Bland, S. K. Howard, R. J. Wiersma, and Loyd Roberson. "Improving HPHT Stability of Water Based Drilling Fluids." In SPE/IADC Drilling Conference. Society of Petroleum Engineers, 1997. http://dx.doi.org/10.2118/37605-ms.

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Growcock, F. B., T. P. Frederick, A. R. Reece, G. W. Green, and M. D. Ruffin. "Novel Lubricants for Water-Based Drilling Fluids." In SPE International Symposium on Oilfield Chemistry. Society of Petroleum Engineers, 1999. http://dx.doi.org/10.2118/50710-ms.

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Hasan Hamdan, Tariq, Vaughn Reza Traboulay, Mohamad Husien, et al. "New Generation of HTHP Water Based Drilling Fluid Changing Conventional Drilling Fluids Solutions." In Abu Dhabi International Petroleum Exhibition & Conference. Society of Petroleum Engineers, 2020. http://dx.doi.org/10.2118/203439-ms.

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Alqahtani, H. S., M. K. Alarfaj, and M. A. Alotaibi. "Environmentally Friendly Shale Inhibitor Water-Based Drilling Fluids." In International Petroleum Technology Conference. IPTC, 2024. http://dx.doi.org/10.2523/iptc-24070-ea.

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Abstract Environmentally friendly Mobil crystalline materials (MCM-41) from the family of Mesoporous Silica Nanoparticles (MSNs) has been used for the first time as shale inhibitors in water-Based Drilling Fluids with full drilling fluid compositions. This shale inhibitor used in this study to eliminate the use of toxic high potassium chloride (KCl) concentration in shale drilling operations and reduce the waste management associated cost with drilling fluid treatment and disposal. The hot rolling dispersion test of MCM41 shale inhibitor with Silurian shale samples revealed to be an effective candidate with significant interaction reduction between the drilling fluids and the shale particles. This new shale inhibitor maintains the integrity of the cuttings and minimize the interaction of fluids with shale sections during the rolling test. XRD, TEM and TGA have measured and discussed in previous publication. Although the application of nanoparticles to improve the performance of conventional water-based drilling fluid was studied by researchers, it is the novelty of this research to eliminate use of KCl and to develop the new generation of shale water-based drilling fluid with economical consideration and lower environmental impact.
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Alqahtani, Hassan Sakar, Mohammed Khaled Arfaj, Mohammed Faisal Alhassni, and Mohammed Abdullah Alotaibi. "Environmentally Friendly Nanoshale Inhibitor Water-Based Drilling Fluids." In Middle East Oil, Gas and Geosciences Show. SPE, 2023. http://dx.doi.org/10.2118/213755-ms.

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Abstract Metal Oxide Nanoparticles (MONPs) comparison has been used for the first time as Nanoshale inhibitors in water-Based Drilling Fluids. These Nanoshale inhibitors used in this study eliminate the use of toxic high potassium chloride (KCl) concentration in shale drilling operations and environmentally friendly with reducing the cost of drilling fluid treatment and waste disposal. The dispersion test of Nanoshale inhibitors based on MONPs with shale samples revealed to be an effective candidate with significant interaction reduction between the drilling fluids and the shale particles compared without these Nanoshale inhibitors samples. This new Nanoshale inhibitor maintains the integrity of the cuttings and minimize the interaction of fluids with shale sections during the rolling test. Zeta potential (ZP) has been conducted to determine the charge of shale and nanoparticles samples. Although the application of nanoparticles to improve the performance of conventional water-based drilling fluid was studied by researchers, it is the novelty of this research to eliminate use of KCl and to develop the new generation of Nanoshale water-based drilling fluid with economical consideration and lower environmental impact.
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Deng, Zhao, Philip W. Livanec, and Jay P. Deville. "Novel Water-Based Fluids for Oil-Sands Drilling." In SPE Canada Heavy Oil Technical Conference. Society of Petroleum Engineers, 2015. http://dx.doi.org/10.2118/174420-ms.

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Bland, R. G., G. L. Smith, and Pasook Eagark. "Low Salinity Polyglycol Water-Based Drilling Fluids as Alternatives to Oil-Based Muds." In SPE/IADC Drilling Conference. Society of Petroleum Engineers, 1995. http://dx.doi.org/10.2118/29378-ms.

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Ytrehus, Jan David, Bjørnar Lund, Ali Taghipour, and Arild Saasen. "Cuttings Transport With Oil- and Water-Based Drilling Fluids." In ASME 2021 40th International Conference on Ocean, Offshore and Arctic Engineering. American Society of Mechanical Engineers, 2021. http://dx.doi.org/10.1115/omae2021-61125.

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Abstract Deviated well sections are common in modern well construction. In mature areas like the North Sea region, practically all producers or injector wells will have highly deviated sections. These wells must be drilled and completed in an optimal manner with respect to drill time, cost, risk and functionality. Most cuttings transport and hydraulic models are developed based on tests with model fluids and often in small diameter test sections. Hole cleaning properties and hydraulic behaviour of field fluids differ from those of most model fluids. Furthermore, results from small diameter tests may not always be relevant for, nor scalable to, field applications due to time, length and other scale differences. Hence, there is a need for studies in controlled laboratory environments with various field application designed drilling fluids to improve engineering models and practices. This paper presents results from laboratory tests using field applied fluids. The drilling fluids have similar density and viscosity within the relevant shear rate range applied during drilling operations and in the tests. One of the fluids is oil-based and the other one is an inhibitive water-based drilling fluid.
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May, Preston, Jay P. Deville, and Jeffrey Miller. "Shale Inhibitor Tracking for High-Performance Water-Based Drilling Fluids." In IADC/SPE International Drilling Conference and Exhibition. SPE, 2022. http://dx.doi.org/10.2118/208721-ms.

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Abstract Drilling wells with water-based fluid systems can be problematic due to the water reactivity of clay-containing shale minerals. This fundamental issue is the most often cited performance gap between non-aqueous fluid (NAF) and water-based fluids (WBF). The consequences of uncontrolled shale hydration include issues such as bit-balling/accretion, reduced ROP, wellbore collapse, and overall increased wellbore construction costs. This problem is typically addressed by the addition of shale inhibitors which can span multiple types of chemistries. The maintenance of these additives is nuanced due to their inherent depletion on reactive minerals leading to uncertainty of active concentration of these additives during a drilling campaign. Considering the critical need to maintain concentrations of these additives, uncertainty is not an optimal plan to ensure success. To this end, we have designed quantitative shale inhibitor tracking technology to measure amine-based shale inhibitors in high-performance water-based fluids. The method is robust, detects only amine-based swelling inhibitors, and is fully amenable to be performed at a rig site. We developed a colorimetric assay that quantitatively measures amine-based shale inhibitors in filtrates of WBFs. The reaction to generate color utilizes proprietary reagents that selectively target only the amines of interest, and is not influenced by nitrogen-containing polymers such as polyacrylamides. Additionally, the results of the test are not influenced by any common drilling fluid additives, including black powders. The colored solutions produced in the test are measured by advanced spectroscopic analysis with a handheld, portable field meter at a specific wavelength. The absorbance is used to determine the concentration of the amine inhibitor in the fluid filtrate. Finally, we have tested reliability of the method through numerous approaches including Gage Repeatability and Reproducibility statistical analysis. With this new technology, we have explored amine depletion on reactive clays in a lab setting, uncovering unique depletion rates based on amine chemistry. Additionally, we have trialed this technology in multiple wells. We have validated the test method and equipment to be field friendly and accurate, as designed. Our field engineers have included this new measurement alongside a typical mud check. In our validation trials we have already observed different depletion rates based on well and operational procedures for amine inhibitor maintenance, and conflicting values of measured concentrations and product concentration estimates based on calculations. We have coupled high-performance fluid design with shale inhibitor tracking technology to reduce the uncertainty of WBF chemical composition. This technology will allow us to sustain effective concentrations of high-performance additives and improve operational reliability throughout the wellbore construction process. Furthermore, this technology will allow more effective re-use of WBF, reducing the environmental impact of our fluids, and lowering well costs.
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Reports on the topic "Water-based drilling fluids"

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Calculation of Worst-Case Discharge (WCD). SPE, 2016. http://dx.doi.org/10.2118/174705-tr.

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This technical report documents the findings of the 2014 WCD Summit (17-18 March 2014, New Orleans, Louisiana) and presents a SME consensus for calculating the WCD of liquid hydrocarbons to the environment resulting from a loss of control from a well during openhole drilling. The main purpose of a WCD calculation is to support oil spill response planning. It is not intended for well design, kill design, or casing design, but these processes are all integrally related. It may be the starting point for well containment planning, which may require additional alternate scenarios that may modify the total flow. The summit focused on defining methods for determining reasonable reservoir properties and fluid analog data to be used as modeling inputs for both shallow water and deep water wells. Discussions included the interaction of water sands and gas sands interspersed with oil sands; multiple sands in the same wellbore in various states of depletion; as well as the effects of secondary gas caps and water encroachment on calculated WCD values. The flowing scenario should be modeled over the duration of the spill to determine when the highest, single-day flow rate from the well occurs, which may or may not be the first day. In multi-well situations, it is important to remember that the WCD well may or may not be the first well drilled on the block or in the field. Each potential well location must be assessed and the WCD determined by the planned well that has the highest WCD flow rate. This document was created to address the calculation of WCD for exploratory or development wells being drilled in the federal waters of the US, as prescribed by the BOEM. However, the approaches presented in this report may be considered for wells drilled in other regions of the US or elsewhere in the world. This report is based on US Department of Interior regulations and interpretation as of March 2014. This document may be modified in the future.
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