Journal articles on the topic 'HPHT drilling fluid'
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1
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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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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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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Gautam, Sidharth, and Chandan Guria. "Optimal Synthesis, Characterization, and Performance Evaluation of High-Pressure High-Temperature Polymer-Based Drilling Fluid: The Effect of Viscoelasticity on Cutting Transport, Filtration Loss, and Lubricity." SPE Journal 25, no. 03 (March 11, 2020): 1333–50. http://dx.doi.org/10.2118/200487-pa.
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Summary Viscoelasticity plays a significant role in improving the performance of the drilling fluid by manipulating its elastic properties. An appropriate value of the first normal stress difference (N1), extensional viscosity (ηe), and relaxation time (θ) enhance the cutting transportability, hole-cleaning ability, filtration loss, and lubrication behavior. However, the performance of the drilling fluid deteriorates during the drilling of high-pressure and high-temperature (HPHT) wells under acid gas and salt(s) contamination. Therefore, it is a challenging task to synthesize a thermally and rheologically stable drilling fluid, which is acid as well as salt(s) resistant, and maintain its desired properties. Although several water-soluble synthetic polymer-based drilling fluids have been used widely for the drilling of HPHT wells, most of these are limited at less than 200°C. Polyanionic cellulose (PAC) has an excellent heat-resistant stability, salt tolerance, calcium and magnesium resistant, and strong antibacterial activity, and it exhibits exceptional filtration and rheological behavior under HPHT conditions. However, using PAC beyond 200°C is limited because of the presence of the biodegradable cellulose units in it. To use the extraordinary properties of PAC, it is aimed to increase the thermal stability of PAC through appropriate modification. In this study, PAC-grafted copolymers involving acrylamide (a salt-tolerant viscosifying agent), 2-acrylamide-2-methyl-1-propane sulfonic acid (a thermally stable lubricating and fluid-loss control agent), and sodium 4-styrene sulfonate (a high-temperature deflocculant) is synthesized optimally through maximizing the thermal degradation stability of the grafted copolymer and minimizing the filtration loss as well as the coefficient of friction (CoF) of the drilling fluid simultaneously. Optimally synthesized PAC-grafted copolymers are then used to prepare water-based mud (WBM) involving American Petroleum Institute (API)-grade bentonite and alpha-glycol functionalized nano fly ash, and the tests for steady shear viscosity and viscoelasticity are performed to determine the rheological stability of mud beyond 200°C. The amplitude sweep tests for viscoelasticity are performed to determine the linear viscoelasticity range (LVR), structural stability, gel strength, and dynamic yield point (YP), whereas frequency, time, and temperature sweep tests are performed to obtain the elastic modulus (G′), viscous modulus (G″), and complex viscosity under HPHT conditions to check the stability of the drilling fluids under different holding times. Dynamic and static aging tests of the developed drilling fluids are performed at elevated temperature and pressure, and the aged muds are tested by evaluating the rheology, frictional, and filtration-loss behavior as per the API recommended procedure. The stability of the aged muds is also tested by evaluating the N1, ηe, and θ using a cone and plate rheometer. The performance of the proposed drilling fluids is also tested under acidic, sodium chloride (NaCl), and calcium chloride (CaCl2) environments at HPHT bottomhole conditions. The experimental results under HPHT conditions reveal that the performance of the mud (i.e., thermal stability, cutting transportability, hole-cleaning ability, filtration loss, and lubrication behavior) could be considerably improved by increasing the elastic properties of the drilling fluid by manipulating the molecular weight of the proposed PAC-grafted copolymer. Finally, the environmental effect of the developed muds is evaluated by finding the lethal concentration that kills 50% of the shrimp population (i.e., LC50) and the Hg and Cd contamination, and they are found to be environmentally safe.
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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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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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Pérez, Miguel. "Petcoke composites as HPHT fluid-loss control additive for oil-based drilling fluids." Ciencia e Ingeniería 43 (2021): 177–84. http://dx.doi.org/10.53766/cei/2021.43.02.06.
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In the present work, composites based on petroleum coke (shot petcoke) and unmodified lignites as high pressure and high temperature fluid loss control additives (HPHT) in oil-based drilling fluids were synthesized and evaluated. Several petcoke composites were synthesized with coke content among 48 wt% and 85 wt%. Petroleum coke composites with lignites controlled the fluid-loss better than organophilic lignite. Petcoke composite with leonardite (a type of lignite) (FPC-L) was that showed the smaller fluid-loss (6.8 mL) in organophilic lignite (FOL) comparison (5.7 mL), because of colloidal lignite (fouling) helps plug off the permeable parts of filter-cake. Applying the reverse osmosis filtration models (Hermia’s models); the blocking mechanisms that occurred most probably were found. FOL fluid-loss control mechanism is by filter-cake formation, while FPC-L is by filter-cake fouling. Petcoke composites controlling fluid-loss by three mechanisms colloidal fouling of the cake filtration: (i) intermediate blocking, (ii) standard blocking and (iii) complete blocking. Colloidal lignite is a determinant factor in the fouling of pore volume and permeability the filter-cake. Cake filtration permeability was estimated by 1H-NMR. Use lignite-petcoke composites as fluid-loss control additive of lower environment impact for oil-based drilling fluids.
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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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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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Jassim, Lina, Robiah Yunus, and Umer Rashid. "Utilization of Nano and Micro Particles to Enhance Drilling Mud Rheology." Materials Science Forum 1002 (July 2020): 435–47. http://dx.doi.org/10.4028/www.scientific.net/msf.1002.435.
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Nanoparticles have been used to overcome the limitations of drilling oil and gas wellbores under harsh conditions of high pressure and high temperature (HPHT). In the present work, calcium carbonate (CaCO3: 5 µm particles), graphene (powder and platelets) and carbon nano sphere nanoparticles were used as rheology enhancer and fluid loss agent for HTHP drilling fluid technology. The results revealed that by adding only 0.1 wt% of nanoparticles to ester-based drilling mud improved the stability for drilling deep and ultra-deep wells up to 230°C. Furthermore, adding graphene powder gave more effective results comparing to graphene platelets and carbon nano sphere. The mud can plug 10 µm of formation size with 8 ml of filtration and 775 mD of permeability using (21/2 × 1/4 ) inch of ceramic disc. The nanoparticle enhanced ester-based drilling fluid also showed superior rheology, fluid loss amount and mud cake thickness. The application of nano ester based drilling fluid is in oil and gas drilling industry.
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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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Rahmati, Abdol Samad, and Afshin Tatar. "Application of Radial Basis Function (RBF) neural networks to estimate oil field drilling fluid density at elevated pressures and temperatures." Oil & Gas Science and Technology – Revue d’IFP Energies nouvelles 74 (2019): 50. http://dx.doi.org/10.2516/ogst/2019021.
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The petroleum industry today has no choice, but to explore new and ever more deep and challenging pay zones as the most of the shallow oil and gas producing pay zones are severely depleted during the years of production. For improved drilling fluid performance in deep and hostile environment wells, accurate knowledge about the fluid density at high temperature and pressure conditions is an essential step. To achieve this mission, this study is aiming at developing a new computer-based tool is designed and applied for accurate calculation of drilling fluid density at HPHT conditions. In order to seek the comprehensiveness of the developed tool, four different kinds of fluids including water based, oil based, Colloidal Gas Aphron (CGA) based and also synthetic fluids are selected for modeling purpose. Radial Basis Function (RBF) network is considered as the modeling network. The results calculated via the proposed algorithm are compared to data reported in the literature. To make a judgment based on various statistical quality measures, it is concluded that the developed tool is reliable and efficient for density calculations of various fluids at extreme conditions.
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Bo, Kehao, Yan Jin, Yunhu Lu, Hongtao Liu, and Jinzhi Zhu. "A Quantitative Evaluation Method of Anti-Sloughing Drilling Fluid Inhibition for Deep Mudstone." Energies 15, no. 3 (February 8, 2022): 1226. http://dx.doi.org/10.3390/en15031226.
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Wellbore instability resulting from deep mudstone hydration severely restricts the development of oil and gas resources from deep reservoir in western China. Accurate evaluation of drilling fluid inhibition properties plays an important role in selecting drilling fluid that can control deep mudstone hydration and then sustain wellbore stability. The previous evaluations are conducted by qualitative analysis and cannot consider the influence of complex hydration conditions of deep mudstone (high temperature, high pressure and flushing action). The study proposes a quantitative method to evaluate drilling fluid’s inhibition property for deep mudstone under natural drilling conditions. In this method, the cohesive strength of mudstone after hydration is adopted as the inhibition index of the tested drilling fluid. An experimental platform containing a newly designed HPHT (High pressure and high temperature) hydration experiment apparatus and mechanics characterization of mudstone after hydration based on scratch test is proposed to obtain the current inhibition index of tested drilling fluid under deep well drilling environments. Based on the mechanical–chemical wellbore stability model considering strength weakening characteristics of deep mudstone after hydration, a cross-correlation between drilling fluid density (collapse pressure) and required inhibition index (cohesive strength) for deep mudstone is provided as the quantitative evaluation criterion. Once the density of tested mud is known, one can confirm whether the inhibition property of tested mud is sufficient. In this study, the JDK mudstone of a K block in western China is selected as the application object of the proposed evaluation method. Firstly, the evaluation chart, which can demonstrate the required inhibition indexes of the tested fluids quantitatively with various densities for JDK mudstone, is constructed. Furthermore, the experimental evaluations of inhibition indexes of drilling fluids taken from two wells in K block are conducted under ambient and deep-well drilling conditions, respectively. In order to show the validity and advantage of the proposed method, a comparison between the laboratory evaluation results and field data is made. Results show that the laboratory evaluation results under deep-well drilling conditions are consistent with the field data. However, the evaluation under ambient conditions overestimates the inhibition property of the tested fluid and brings a risk of wellbore instability. The developed quantitative method can be a new way to evaluate and optimize the inhibition property of drilling fluid for deep mudstone.
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Bageri, Badr S., Mohammed Benaafi, Mohamed Mahmoud, Shirish Patil, Abdelmjeed Mohamed, and Salaheldin Elkatatny. "Effect of Arenite, Calcareous, Argillaceous, and Ferruginous Sandstone Cuttings on Filter Cake and Drilling Fluid Properties in Horizontal Wells." Geofluids 2019 (April 16, 2019): 1–10. http://dx.doi.org/10.1155/2019/1956715.
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Fine, small-size, drilled cuttings, if not properly separated using mud conditioning equipment at the surface, are circulated with the drilling fluid from the surface to the bottom hole. These drilled cuttings have a significant effect on the drilling fluid properties and filter cake structure. During drilling long lateral sandstone formations, different cuttings with varied properties will be generated due to sandstone formations being heterogeneous and having different mineralogical compositions. Thus, the impact of these cuttings on the drilling fluid and filter cake properties will be different based on their mineralogy. In this paper, the effect of different sandstone formation cuttings, including arenite (quartz rich), calcareous (calcite rich), argillaceous (clay rich), and ferruginous (iron rich) sandstones, on the filter cake and drilling fluid properties was investigated. Cuttings of the mentioned sandstone formations were mixed with the drilling fluid to address the effect of these minerals on the filter cake thickness, porosity, and permeability. In addition, the effect of different sandstone formation cuttings on drilling fluid density and rheology, apparent viscosity (AV), plastic viscosity PV), and yield point (YP) was investigated. High-pressure high-temperature (HPHT) fluid loss test was conducted to form the filter cake. The core sample’s petrophysical properties were determined using X-ray fluorescence (XRF) and X-ray diffraction (XRD) techniques and scanning electron microscopy (SEM). The results of this work indicated that all cutting types increased the rheological properties when added to the drilling fluid at the same loadings but the argillaceous sandstone (clay rich) has a dominant effect compared to the other types because the higher clay content enhanced the rheology. From the filter cake point of view, the ferruginous sandstone improved the filter cake sealing properties and reduced its thickness, while the argillaceous cuttings degraded the filter cake porosity and permeability and allowed the finer cuttings to penetrate deeply in the filter medium.
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Sulaimon, Aliyu A., Bamikole J. Adeyemi, and Mohamad Rahimi. "Performance enhancement of selected vegetable oil as base fluid for drilling HPHT formation." Journal of Petroleum Science and Engineering 152 (April 2017): 49–59. http://dx.doi.org/10.1016/j.petrol.2017.02.006.
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Xia, Hua, Nelson Settles, and David DeWire. "Moisture-Resistant Sealing Materials for Downhole HPHT Electrical Feedthrough Package." Journal of Microelectronics and Electronic Packaging 16, no. 3 (July 1, 2019): 141–48. http://dx.doi.org/10.4071/imaps.942864.
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Abstract A bismuth oxide–based multicomponent glass system, xH3BO3-yBi2O3-(1-x-y-δ)MO-δ· rare earth oxides (REOs) with MO = TiO2, BaO, ZnO, Fe2O3, etc., and lanthanum series–based REOs, for making downhole high-pressure and high-temperature electrical feedthrough package has been developed using high-temperature melt-quenching and sintering technologies. By properly controlling phase structures in material-manufacturing processes, the obtained sealing materials have shown moisture-resistant properties in their monoclinic and tetragonal mixed phase structures but strongly hydrophobic properties in their covalent bond tetragonal phase. Sealed electrical feedthrough packages have been evaluated under boiling water immersion and 200°C/30,000 PSI water-fluid–simulated downhole harsh environments. The post electrical insulation measurement has demonstrated to be greater than 1.0 × 1014 Ω electrical resistance. This article will show that such a high–bonding strength and high–insulation strength sealing material could be used to seal electrical feed-throughs and connectors for 300°C/30,000 PSI downhole and subsea wireline, logging while drilling, and measurement while drilling tools' signal, data, and electrical power transmissions.
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Xia, Hua, Nelson Settles, and David DeWire. "Moisture-resistant sealing materials for downhole HPHT electrical feedthrough package." Additional Conferences (Device Packaging, HiTEC, HiTEN, and CICMT) 2019, HiTen (July 1, 2019): 000022–27. http://dx.doi.org/10.4071/2380-4491.2019.hiten.000022.
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Abstract A bismuth oxide based multi-component glass system, xH3BO3-yBi2O3-(1-x-y-δ)MO-δ·REO with MO=TiO2, BaO, ZnO, Fe2O3, etc., and lanthanum series based rare earth oxides (REO), for making downhole high-pressure and high-temperature (HPHT) electrical feedthrough package, has been developed using high-temperature melt-quenching and sintering technologies. By properly controlling phase structures in the material manufacturing processes, the obtained sealing materials have shown moisture-resistant properties in their monoclinic and tetragonal mixed phase structures, but strongly hydrophobic properties in their covalent bond tetragonal phase. The sealed electrical feedthrough packages have been evaluated under boiling water immersion and 200°C/30,000PSI water-fluid simulated downhole harsh environments. The post measurement has demonstrated to be greater than 1.0×1014 Ω electrical resistance. This paper will show that such a high-bonding-strength and high-insulation-strength sealing material could be used to seal electrical feedthroughs and connectors for 300°C/30,000PSI downhole and subsea wireline, logging while drilling (LWD), and measurement while drilling (MWD) tools' signal, data, and electrical power transmissions.
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Igwilo, Kevin C., Emeka Emmanuel Okoro, Okorie Agwu, Christopher Onedibe, Sabinus I. Ibeneme, and Nnanna Okoli. "Experimental Analysis of Persea americana as Filtration Loss Control Additive for Non-Aqueous Drilling Fluid." International Journal of Engineering Research in Africa 44 (August 2019): 8–21. http://dx.doi.org/10.4028/www.scientific.net/jera.44.8.
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Persea Americana is well known for its short shelf life while the seed is widely considered a waste material by domestic consumers and industry processors. This paper presents the results of the study carried out to evaluate the possibility of using three parts of the Persea Americana namely: its seed, a combination of the Persea Americana seed and its pulp and the Persea Americana pulp as filtration loss control additives in a non-aqueous drilling fluid while using Sodium Asphalt Sulfonate as a control. The evaluation was conducted under high pressure, high temperature (HPHT) static filtration test conditions (at 250°F and 500 psi) based on American Petroleum Institute Standard. From the study, the result showed that all three samples from the Persea Americana fruit showed good potential to control filtration loss when used to formulate a synthetic oil based mud. The filtration control capacity increased as their concentration in the mud was increased. However, in comparison, the pulp was 2.5 times and 1.5 times more efficient in controlling filtration loss when compared to the seed only and the seed and pulp combination respectively. Also, in terms of filtrate volume and filtered cake thickness, an equal concentration of Sodium Asphalt Sulfonate and the proposed additive gave good results; but the existing filtration loss control additive is slightly better than the proposed one. The low fluid loss volumes recorded with Persea Americana as fluid loss additives at HPHT conditions is an indication of its stability at elevated temperature conditions. The cake thickness was thin, impermeable and 1mm in size for all the samples of the Persea Americana. This meets the API requirement of mud cake thickness of less than 2mm.
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Paul, Anawe A. L., and Folayan J. Adewale. "Experimental investigation of fluid loss and cake thickness control ability of zirconium (IV) oxide (Z_R O_2) nanoparticles in water based drilling mud." International Journal of Engineering & Technology 7, no. 2 (May 10, 2018): 702. http://dx.doi.org/10.14419/ijet.v7i2.10273.
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A major technical and economical concern of the oil well drilling industry is the potential damage to productive formations because of excessive drilling fluid filtration and its multiplier effect on cake thickness. High fluid loss (high cake permeability) results in thick filter cake which reduces the effective diameter of the hole (tight holes) and causes various problems such as excessive torque when rotating the pipe, excessive drag when pulling it and high swab and surge pressures due to reduced hole diameter and differential pipe sticking due to increase in pipe contact.It is in this light that the potential of Zirconium (IV) oxide (Z_r O_2) nanoparticles in combating excessive filtration problem in Water Based Mud was investigated. Preliminary results show that addition of 0.50g (Z_r O_2) nanoparticle concentration brought about 19.10% reduction in fluid loss and 14.29 % reduction in cake thickness for the High Temperature/ High Pressure (HPHT) filtration test at 500psi and 250 OF. Similarly, the highest reduction of 48.31% and 38.10% in fluid loss and cake thickness respectively was achieved with addition of an optimum concentration of 2.0g of (Z_r O_2) nanoparticles for the HTHP filtration test at the same temperature and pressure.
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Dvoynikov, Mikhail, Dmitry Sidorov, Evgeniy Kambulov, Frederick Rose, and Rustem Ahiyarov. "Salt Deposits and Brine Blowout: Development of a Cross-Linking Composition for Blocking Formations and Methodology for Its Testing." Energies 15, no. 19 (October 9, 2022): 7415. http://dx.doi.org/10.3390/en15197415.
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Uncontrolled inflow of formation fluid (brine) into a well adversely affects the cation–anion bonds in solutions and leads to their dissociation and loss of aggregative stability. Blow-out significantly complicates the drilling process and leads to an increase in non-productive time and in financial costs for problem solving. It is necessary to create a blocking screen that allows separation of the layer from the well and prevents brine flow. This article is devoted to the development of polymeric-blocking compositions that work due to the crystallization reaction of divalent salts of calcium and magnesium chlorides. More than 14 components were detected in the formation fluid on the atomic emission spectrometer. Based on the study of the compatibility of components with brine and the study of rheology and filtration processes through a real core under HPHT conditions, the optimal component polymer composition was selected. The reason for the increase in the rheology of composition during its thickening was established. With the help of tomographic studies, the depth of penetration of the filtrate into the core of layers was determined. For further studies, an experimental stand was designed for physical simulation of the isolation process under HPHT conditions and backpressure from the formation.
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Mansoor, Hameed Hussain Ahmed, Srinivasa Reddy Devarapu, Robello Samuel, Tushar Sharma, and Swaminathan Ponmani. "Experimental Investigation of Aloe-Vera-Based CuO Nanofluid as a Novel Additive in Improving the Rheological and Filtration Properties of Water-Based Drilling Fluid." SPE Drilling & Completion 36, no. 03 (January 12, 2021): 542–51. http://dx.doi.org/10.2118/205004-pa.
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Summary Drilling technology in petroleum engineering is associated with problems such as high fluid loss, poor hole cleaning, and pipe sticking. Improvement of rheological and filtration properties of water-based drilling fluids (WDFs) plays a major role in resolving these drilling problems. The application of nanotechnology to WDF in the recent past has attracted much attention in addressing these drilling operations problems. In the present work, we investigate the application of natural aloe vera and CuO nanofluids combined as an additive in WDF to address the drilling problems. The nanofluids of three different concentrations of CuO nanoparticle (0.2, 0.4 , and 0.6 wt%) with aloe vera as a base fluid are prepared for this study by adopting a two-step method. The prepared nanofluids are characterized by their particle size and morphological characteristics. Conventional WDF (DF.0) is synthesized, and the prepared aloe-vera-based CuO nanofluid is added to the WDF to prepare nanofluid-enhanced water-based drilling fluid (NFWDF) of different concentrations of nanoparticles, namely, 0.2 , 0.4, and 0.6 wt%. The prepared drilling fluid mixture is then characterized for its rheological and filtrate loss properties at various temperatures. Thermal stability and aging studies are performed for both WDF and NFWDF. The experimental results are then modeled using rheological models. The results reveal that aloe-vera-based CuO nanofluids improve the thermal stability and rheological properties of drilling fluid and significantly decrease the American Petroleum Institute (API) filtrate. Viscosity for WDF shows an approximately 61.7% decrease in heating up to 90°C. Further, the hot roll aging test causes a 63% decrease in the viscosity of WDF at 90°C. However, the addition of aloe-vera-based CuO nanofluids is found to aid in recovering the viscosities to a great extent. The fluid loss values before hot rolling are observed to be 6.6 mL after 30 minutes, whereas fluid loss values for the NFWDFs are found to be 5.9, 5.4, and 4.6 mL, respectively. The fluid loss value after hot rolling for the WDF is found to be 10.8 mL after 30 minutes, whereas fluid loss values for the NFWDFs are found to be 9.2, 8.5, and 7.7 mL, respectively. The rheological performance data of NFWDF project a better fit with the Herschel-Bulkley model and suggest improvement in rheological and filtration properties. There has been limited research work available in understanding the impact of aloe-vera-gel-based nanofluids in improving the performance of WDFs through the improvement of its rheological and filtration properties. This study aims to exploit the property of native aloe vera and CuO nanofluids combined together to enhance the rheological and filtration properties of WDF by conducting the tests both before and after hot rolling conditions. This study acts as an important precursor for developing novel additives for WDF to improve its rheological and filtration properties. This study is also expected to benefit the industry and solve the major challenges in deep-well drilling operations and high-pressure and high-temperature (HPHT) drilling operations.
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Ahmed, Abdulmalek, Salaheldin Elkatatny, Abdulwahab Ali, Mahmoud Abughaban, and Abdulazeez Abdulraheem. "Application of Artificial Intelligence Techniques in Predicting the Lost Circulation Zones Using Drilling Sensors." Journal of Sensors 2020 (September 22, 2020): 1–18. http://dx.doi.org/10.1155/2020/8851065.
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Drilling a high-pressure, high-temperature (HPHT) well involves many difficulties and challenges. One of the greatest difficulties is the loss of circulation. Almost 40% of the drilling cost is attributed to the drilling fluid, so the loss of the fluid considerably increases the total drilling cost. There are several approaches to avoid loss of return; one of these approaches is preventing the occurrence of the losses by identifying the lost circulation zones. Most of these approaches are difficult to apply due to some constraints in the field. The purpose of this work is to apply three artificial intelligence (AI) techniques, namely, functional networks (FN), artificial neural networks (ANN), and fuzzy logic (FL), to identify the lost circulation zones. Real-time surface drilling parameters of three wells were obtained using real-time drilling sensors. Well A was utilized for training and testing the three developed AI models, whereas Well B and Well C were utilized to validate them. High accuracy was achieved by the three AI models based on the root mean square error (RMSE), confusion matrix, and correlation coefficient (R). All the AI models identified the lost circulation zones in Well A with high accuracy where the R is more than 0.98 and RMSE is less than 0.09. ANN is the most accurate model with R=0.99 and RMSE=0.05. An ANN was able to predict the lost circulation zones in the unseen Well B and Well C with R=0.946 and RMSE=0.165 and R=0.952 and RMSE=0.155, respectively.
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Cheng, Han. "Research and Application of Micronized Barite Drilling Fluid in HPHT Wells of the Western South China Sea." International Journal of Oil, Gas and Coal Engineering 4, no. 2 (2016): 9. http://dx.doi.org/10.11648/j.ogce.20160402.11.
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Jones, D. W., B. J. Taylor, C. E. Gill, M. Bevaart, P. F. van Bergen, J. S. Watson, S. De Gennaro, and M. Hodzic. "The Shearwater Field – understanding the overburden above a geologically complex and pressure-depleted high-pressure and high-temperature field." Geological Society, London, Petroleum Geology Conference series 8, no. 1 (July 3, 2017): 429–43. http://dx.doi.org/10.1144/pgc8.36.
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AbstractThe Shearwater Field, located in Block 22/30b in the UK Central Graben, remains one of the best-known fields in the UK Continental Shelf (UKCS). At the time of the initial development, Shearwater represented one of the most complex and technically challenging high-pressure and high-temperature (HPHT) developments of its kind in the North Sea. During the early life of the field, pressure depletion resulted in compaction of the Fulmar reservoir, leading to mechanical failure of the development wells. The compaction also resulted in weakening of the overburden due to an effect known as stress arching. Over time, this resulted in in situ stress changes in the overburden which have been observed from 4D seismic datasets and are in line with geomechanical modelling. This is particularly true for the Hod Formation in the Chalk Group, and resulted in the need to make changes to infill well design, including the use of new drilling technologies, to ensure safe and effective well delivery. The insights presented here, which relate to the understanding of pore pressure and fluid fill in the overburden, and how the overburden has responded to stress changes over time, are of relevance to current and future HPHT field developments in both the UK North Sea and elsewhere.
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Siddig, Osama, Saad Al-Afnan, Salaheldin Elkatatny, and Mohamed Bahgat. "Novel Cake Washer for Removing Oil-Based Calcium Carbonate Filter Cake in Horizontal Wells." Sustainability 12, no. 8 (April 22, 2020): 3427. http://dx.doi.org/10.3390/su12083427.
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An impermeable layer “filter cake” usually forms during the overbalanced drilling technique. Even though it helps in protecting the formation from a further invasion of drilling fluids, the removal of this layer is essential for a proper cement job and to avoid any reduction in wellbore deliverability. The design of the removal process is complicated and depends on the filter cake composition and homogeneity. This paper presents an experimental evaluation on the usage of a novel cake washer (NCW) in the removal of a filter cake formed by an invert emulsion oil-based drilling fluid that contains calcium carbonate as a weighting material while drilling a horizontal reservoir. The proposed NCW is a mixture of organic acid, mutual solvent and nonionic surfactant. It is designed to enable restored wellbore permeability for a sustainable production. Since the filter cake mainly consists of the weighting material, the solubility of calcium carbonate in NCW at different ranges of temperature, duration and concentration was investigated. An actual casing joint was used to test the corrosion possibility of the treating solution. High-pressure and high-temperature (HPHT) filtration tests on ceramic discs and Berea sandstone core samples were conducted to measure the efficiency of the filter cake removal and the retained permeability. Ethylene glycol mono butyl ether (EGMBE) was used as a mutual solvent and the solubility was higher compared to when the mutual solvent was not used in the washer formulation. A significant increase in calcium carbonate dissolution with time was observed for a duration of 24 h. The solubility was found to be proportional to the concentration of NCW with optimum results of 99% removal at a temperature of around 212 °F. At those conditions, no major corrosion problems were detected. Permeability of the core retained its pristine value after the treatment.
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Ghazali, Nurul Aimi, T. A. T. Mohd, Nur Hashimah Alias, A. Azizi, and A. A. Harun. "The Effect of Lemongrass as Lost Circulation Material (LCM) to the Filtrate and Filter Cake Formation." Key Engineering Materials 594-595 (December 2013): 68–72. http://dx.doi.org/10.4028/www.scientific.net/kem.594-595.68.
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Lost circulation is one of the most troublesome encountered in drilling due to uncontrolled flow of mud into the formation that likely to be caused of unsuccessful filter cake. The lost circulation material (LCM) is the additives that added to the drilling fluid to control loss of mud to the formation. In this research, the lemongrass was used as LCM. The objectives of this experiment are to investigate the effect of lemongrass as LCM to the filtrate and filter cake thickness and to determine the effective size of lemongrass as LCM. The experiments were conducted to measure the filtrate and filter cake thickness with different size and different based of drilling fluid. Low Pressure Low Temperature (LPLT) filter press is for water based mud (WBM) and High Pressure High Temperature (HPHT) filter press is for oil based mud (OBM) were used to perform the filtration process under static condition and constant filtration time which is 30 minutes. Both WBM and OBM are prepared four samples with three difference sizes of LCM and native mud. The sizes of lemongrass are 150 microns, 250 microns and 500 microns. After each experiment, the filtrate volume and filter cake thickness were determined to represent. The result shows that lemongrass able to perform a good LCM in both WBM and OBM based on filtrate volume and filter cake thickness. For WBM, the mud with LCM is lower filtrate volume than native mud which is less than 6.0 ml and for OBM, the mud with LCM is lower filtrate volume than native mud which is less than 5.0 ml. Both WBM and OBM show the thickness of filter cake obtained was in the range of 2 to 25 mm. The result also shows that the effective size of LCM is 150 micron due to less filtrate volume and filter cake thickness compare to other size of LCM which is 250 microns and 500 microns. The findings revealed that then lemongrass with the size of 150 microns is the suitable material to be used as LCM to replace conventional LCM.
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Sepehri, Sanam, Rouhollah Soleyman, Akbar Varamesh, Majid Valizadeh, and Alireza Nasiri. "Effect of synthetic water-soluble polymers on the properties of the heavy water-based drilling fluid at high pressure-high temperature (HPHT) conditions." Journal of Petroleum Science and Engineering 166 (July 2018): 850–56. http://dx.doi.org/10.1016/j.petrol.2018.03.055.
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Zima, Grzegorz, Bartłomiej Jasiński, Małgorzata Uliasz, and Sławomir Błaż. "Polimery syntetyczne do regulowania filtracji płuczek wiertniczych w warunkach podwyższonej temperatury." Nafta-Gaz 78, no. 5 (May 2022): 375–85. http://dx.doi.org/10.18668/ng.2022.05.05.
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W artykule przedstawiono badania laboratoryjne nad zastosowaniem do regulowania filtracji polimerów syntetycznych takich jak kopolimery i terpolimery zbudowane z merów winylowoamidowych, winylowosulfonowych, akrylowosulfonowych lub bezwodnika maleinowego. Środki te według danych literaturowych wykazują odporność termiczną powyżej 200°C. Na podstawie przeprowadzonych badań z wykorzystaniem nowych środków syntetycznych dokonano ich doboru do regulowania filtracji i parametrów reologicznych płuczek wiertniczych w różnych warunkach geologicznych oraz określono korelację pomiędzy wynikami badań filtracji uzyskanymi na statycznej i dynamicznej prasie filtracyjnej HPHT oraz wynikami filtracji otrzymanymi za pomocą aparatu Grace M2200 HPHT. Badania polimerów syntetycznych przeprowadzono w płuczce, w której składzie zastosowano środek skrobiowy i biopolimer XCD. Płuczka ta zawierała dodatkowo 7% inhibitora jonowego KCl i 7% blokatora węglanowego w celu utworzenia osadu filtracyjnego. Dla badanych płuczek przeprowadzono pomiary ich podstawowych właściwości oraz wykonano pomiary statycznej i dynamicznej filtracji HPHT na standardowych sączkach do pomiaru filtracji oraz krążkach ceramicznych o porowatości 20 µm. Filtrację statyczną określono w temperaturach 60°C i 120°C, natomiast dynamiczną w temperaturze 120°C. Filtrację przy użyciu aparatu Grace M2200 HPHT zmierzono również w temperaturach 60°C i 120°C na rdzeniach o porowatości 20 µm. W celu odtworzenia warunków otworowych do płuczek dodawano zwierciny (zmielony łupek mioceński) i skażenia chemiczne w postaci chlorków wapnia i magnezu oraz obciążano je barytem. Wyniki pomiarów na aparacie Grace M2200 HPHT podane w artykule zostały przeliczone na podstawie stosunku powierzchni filtracji w celu porównania z filtracją HPHT na krążkach ceramicznych. Dla płuczek dodatkowo przeprowadzono badanie dyspersji skały ilastej w celu określenia i porównania ich właściwości inhibicyjnych. Uzyskane wyniki badań mogą znaleźć zastosowanie w warunkach przemysłowych podczas głębokich wierceń oraz pozyskiwania energii geotermalnej.
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Dihingia, Mritunjoy. "Review on Applications of Non-ionic and Anionic Surfactants in Water Based Drilling Fluids." International Journal for Research in Applied Science and Engineering Technology 9, no. VII (July 25, 2021): 2054–60. http://dx.doi.org/10.22214/ijraset.2021.36808.
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In recent times, with the advent of exploSration activities in deeper hydrocarbon reserves, drilling of wells in HPHT conditions is one of the most studied field in the upstream oil and gas industry. Water-based fluids are the most common and frequently used drilling fluids oil and gas well construction. Although, water-based drilling fluids are environment friendly and relatively in-expensive, it is often associated with many problems when used in HPHT conditions. In order to overcome these problems in such viable conditions, modified surfactants are used with the mud to counteract the problems associated with it. This paper discusses the different applications of anionic and non-ionic surfactants in water-based drilling fluids both in laboratory and field scales. The paper also discusses the mechanisms of the surfactants and the effect on various mud properties to overcome hole problems like wellbore instability, rheology and filtration loss, foaming and flocculation of mud.
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M, Halafawi. "Offset Wells Data Analysis and Thermal Simulations Improve the Performance of Drilling HPHT Well." Petroleum & Petrochemical Engineering Journal 6, no. 1 (2022): 1–15. http://dx.doi.org/10.23880/ppej-16000298.
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To drill new HPHT development wells safely, an exact estimate of their stability is essential. Analyzing previously drilled offset wells can assist in this determination, eliminating any stratigraphic column issues and saving nonproductive time. The challenges found with offset wellbores, their consequences on well design, possible remedies, and preventative measures are discussed in this paper. It examines drilling data from offset wells in order to discover, diagnose, and treat serious issues. Furthermore, thermal simulation was done in order to study the temperature distribution of the wellbore, annuli and fluids during drilling, tripping, circulation, logging, casing and cementing in HPHT zone.
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Xu, Lin, Ming Biao Xu, and Lin Zhao. "Design of a Novel HPHT Lubricity Tester and its Preliminary Application." Applied Mechanics and Materials 220-223 (November 2012): 504–8. http://dx.doi.org/10.4028/www.scientific.net/amm.220-223.504.
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Manifestation of friction between the drill string and the borehole is of special importance for modern drilling. A novel lubricity tester, in combination with high pressure high temperature(HPHT) actuators, has been designed to permit the evaluation and testing of various types and the lubricity of drilling fluids by simulating the rotational speed of the drill pipe and pressure exerted against the borehole. This instrument mainly consists of four parts, i.e., a friction mechanism, HPHT actuators, the computational control system, and a load apparatus. The key test cell has been introduced. The lubricity of the typical drilling-in system(PRD) has been evaluated using this instrument. The results showed that except for the filtration, the designed lubricity tester can effectively describe the friction behaviors in the whole dynamic drilling, by rotating the rod in the given environment.
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Huaike, Li, Geng Tie, Guo Lei, and Luo Jiansheng. "High Performance Water-based Drilling Fluids—A High Efficiency Muds Achieving Superior Shale Stability While Drilling Deepwater Well with HPHT in South China Sea." Science Journal of Energy Engineering 7, no. 4 (2019): 98. http://dx.doi.org/10.11648/j.sjee.20190704.16.
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Lin, Ling, Xin Li, Chenliang Shi, and Yifan Mao. "Desorption of hydrolyzed poly(AM/DMDAAC) from bentonite and its decomposition in saltwater under high temperatures." e-Polymers 19, no. 1 (October 4, 2019): 527–34. http://dx.doi.org/10.1515/epoly-2019-0056.
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AbstractUnder harsh conditions, the desorption of polyampholytes from bentonite (Bent) can affect the performance of drilling fluids. To study the desorption of polyampholyte from bentonite, partially hydrolyzed copolymers of acrylamide and diallyl dimethyl ammonium chloride (HPAD), containing carboxyl groups, quaternary ammonium groups and amide groups was synthesized via free radical copolymerization followed by hydrolyzation. The molecular structure of HPAD was characterized by 1H NMR and 13C NMR. The adsorption equilibrium of HPAD on Bent in the presence of 10 wt% NaCl was 106 mg·g–1. The adsorption-desorption behavior of HPAD on Bent was studied using a high pressure and high temperature (HPHT) filtration apparatus, to obtain the filtrate liquid and filter cakes. The content of HPAD in the filtration and the filter cakes was determined via UV and element analysis, respectively. As the temperature increased, the desorption of HPAD from Bent accelerated owing to molecular thermal motion and thermal degradation of the adsorptive groups. Notably, the decomposition rate of the amide group was more than twice that of the quaternary ammonium group. The critical temperature for HPAD desorption was 135°C, as the decomposition of the adsorptive groups became predominant over intensified molecular thermal motion at high temperatures.
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Gharib Shirangi, Mehrdad, Roger Aragall, Reza Ettehadi Osgouei, Roland May, Ted Furlong, Thomas Dahl, and Charles Thompson. "Development of Digital Twins for Drilling Fluids: Local Velocities for Hole Cleaning and Rheology Monitoring." Journal of Energy Resources Technology, May 2, 2022, 1–32. http://dx.doi.org/10.1115/1.4054463.
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Abstract In this work, we present our advances to develop and apply digital twins for drilling fluids and associated wellbore phenomena during drilling operations. A drilling fluid digital twin is a series of interconnected models that incorporate the learning from the past historical data in a wide range of operational settings to determine the fluids properties in real-time operations. Our specific focus is prediction of cuttings bed thickness along the wellbore in hole cleaning and prediction of high-pressure high-temperature (HPHT) rheological properties (in downhole conditions). In both applications, we present procedures to develop accurate digital twins for prediction of drilling fluid properties in real-time drilling operations. In the hole cleaning application, we develop accurate computational fluid dynamics (CFD) models to capture the effects of rotation, eccentricity, and bed height on local fluid velocities above cuttings bed. We then run 55,000 CFD simulations for a wide range of operational settings to generate training data for machine learning. For rheology monitoring, thousands of lab experiment records are collected as training data for machine learning. In this case, the HPHT rheological properties are determined based on rheological measurement in the American Petroleum Institute (API) condition (14.7 psi and 150 F) together with the fluid type and composition data. We compare the results of application of several machine learning algorithms to represent CFD simulations (for hole cleaning) and lab experiments (for monitoring HPHT rheological properties). Rotating cross-validation method is applied to ensure accurate and robust results. In both cases, models from the Gradient Boosting and the Artificial Neural Network algorithms provided the highest accuracy (about 0.95 in terms of R2) for test datasets. With developments presented in this paper, the hole cleaning calculations can be performed in real-time, and the HPHT rheological properties of drilling fluids can be estimated at the rig site avoiding the need to wait for the laboratory experimental results.
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Prakash, Ved, Neetu Sharma, and Munmun Bhattacharya. "Effect of silica nano particles on the rheological and HTHP filtration properties of environment friendly additive in water-based drilling fluid." Journal of Petroleum Exploration and Production Technology, September 27, 2021. http://dx.doi.org/10.1007/s13202-021-01305-z.
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AbstractRheological and filtration properties of drilling fluid contribute a vital role in successful drilling operations. Rheological parameters such as apparent viscosity (AV), plastic viscosity (PV), yield point (YP) and gel strength of drilling fluids are very essential for hydraulic calculations and lifting of drill cuttings during the drilling operation. Control of filtration loss volume is also very important for cost effective and successful drilling operations. Therefore, the main goal of this research is to improve the rheological and filtration properties of Grewia Optiva fibre powder (GOFP) by using 30–50 nm size of silica nano particles (SNP) in water-based drilling fluid. The experimental outcomes revealed that after hot rolling of mud samples at 100 °C for 16 h, the low pressure-low temperature (LPLT) and high pressure-high temperature (HPHT) filtration loss of GOFP additives was improved, after the addition of SNP on it. The mixture of 5% GOFP + 4% SNP has reduced the LPLT and HPHT filtration loss of drilling fluid by 74.03 and 78.12%, respectively, as compared to base mud. Thus, it was concluded that after the addition of 0.4% SNP, the LPLT and HPHT filtration control ability of GOFP additive in WBM were increased by 17.6 and 15%, respectively. The rheological parameters such as AV, PV, YP and gelation of drilling fluids were also improved by the addition of GOFP + SNP mixture in the base mud. Therefore, the implementation of GOFP + SNP mixture in water-based mud showed auspicious results which reaffirm the feasibility of using them in the successful drilling operations.
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Wagle, Vikrant, Abdullah AlYami, Mohammad Aljubran, and Hussain Al-Bahrani. "High Density Drilling Fluids for Managed Pressure Drilling: Lab Development and Field Trial." Journal of Energy Resources Technology, June 16, 2022, 1–32. http://dx.doi.org/10.1115/1.4054824.
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Abstract Managed pressure drilling (MPD) offers a closed loop circulation system in which formation fracture pressure, bottom hole pressure and pore pressure are managed at surface. The right choice of drilling fluid used during MPD operation facilitates correct mud management and treatment. Lab formulation and field trial of a high-density water-based drilling fluid comprising a mixture of barite (BaSO4) and manganese tetroxide (Mn3O4) as weighting agents has been described in the paper. Drilling fluids having a mixture of Mn3O4 and BaSO4 as weighting agents would have lower equivalent circulating density (ECD), better sag, better acid solubility and lower fluid cost as compared to conventional BaSO4 based fluids. This paper describes the formulation of three different water-based drilling fluids viz. 100, 120, and 150pcf drilling fluids having a mixture of Mn3O4 and BaSO4 and hot rolled at temperatures of 270, 250, and 300oF, respectively. Rheological properties, sag resistance and high pressure-high temperature (HPHT) filtration properties of the three fluids have been described in the paper. Data obtained from the field trial of 160pcf high density drilling fluids having a mixture of Mn3O4 and BaSO4 for wells with a 300oF bottom hole static temperature has been described. HPHT operations across naturally fractured formations with 0.5–1.0pcf drilling fluid window have been described in the paper. During the field trial, the fluid having a mixture of Mn3O4 and BaSO4 showed good rheological, filtration and sag properties thereby resulting in successful drilling of the well with no issues. MPD operation became more successful and practical with high density drilling fluids having a mixture of Mn3O4 and BaSO4 as it facilitated better drilling fluid management and treatment in comparison to conventional fluids.
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Sulaimon, Aliyu Adebayo, Sarah Abidemi Akintola, Mohd Adam Bin Mohd Johari, and Sunday Oloruntoba Isehunwa. "Evaluation of drilling muds enhanced with modified starch for HPHT well applications." Journal of Petroleum Exploration and Production Technology, October 31, 2020. http://dx.doi.org/10.1007/s13202-020-01026-9.
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Abstract The use of carboxymethyl cellulose (CMC) in oil and gas well drilling operations has improved the filtration loss and mud cake properties of drilling muds. The introduction of starch has also reduced, for example, the viscosity, fluid loss, and mud cake properties of the drilling fluids. However, normal starch has some drawbacks such as low shear stress resistance, thermal decomposition, high retrogradation, and syneresis. Hence, starch modification, achieved through acetylation and carboxymethylation, has been introduced to overcome these limitations. In this study, modified starches, from cassava and maize, were used to enhance the properties of water-based muds under high-pressure high temperature (HPHT) conditions, and their performances were compared with that of the CMC. The mud samples added with acetylated cassava or maize starch exhibited the smallest filtrate volumes and filtrate losses within the American Petroleum Institute specification. Therefore, these modified starch-added muds could replace CMC as fluid loss agents since, unlike it, they can withstand HPHT conditions.
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Alvi, Muhammad Awais Ashfaq, Mesfin Belayneh, Kjell Kåre Fjelde, Arild Saasen, and Sulalit Bandyopadhyay. "Effect of Hydrophobic Iron Oxide Nanoparticles on the Properties of Oil-Based Drilling Fluid." Journal of Energy Resources Technology 143, no. 4 (September 22, 2020). http://dx.doi.org/10.1115/1.4048231.
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Abstract Lately, nanoparticles (NPs) have shown the potential to improve the performance of oil well fluids significantly. Several studies have reported the ability of NPs to produce improved properties of both water and oil-based drilling fluids. In this study, hydrophobic iron oxide NPs were synthesized by thermal decomposition of iron pentacarbonyl in an inert atmosphere, and its performance was tested in the oil-based drilling fluid with 90/10 oil-to-water ratio (base fluid). Oil-based drilling fluids treated with nanofluids were formulated by adding 0.5 wt% and 1.0 wt% iron oxide NPs in hexane solution to the base drilling fluid. The base fluid and the nanofluid-treated drilling fluids were evaluated by characterizing their rheological properties at different temperatures, viscoelastic properties, lubricity, filtrate loss, static and dynamic settling, and separation properties. Results showed that 0.5 wt% iron oxide dispersed in hexane reduced the high pressure high temperature (HPHT) filtrate loss by 70%, filter cake thickness by 55%, and the coefficient of friction by 39%. Moreover, the nanofluid based drilling fluid reduced the free oil layer caused by syneresis during aging at high temperature by 16.3% compared to the base fluid. This study has shown that hydrophobic iron oxide NPs have the potential to improve the properties of oil-based drilling fluid.
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Dong, Xuelin, Zhiyin Duan, Haoyu Dou, Yinji Ma, and Deli Gao. "A Parametric Study for Radial Cracking in Cement Under Different Loading Events Based on the Stress Intensity Factor." Journal of Energy Resources Technology 144, no. 5 (July 30, 2021). http://dx.doi.org/10.1115/1.4051742.
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Abstract Cement is one of the primary barriers in a wellbore and critical to well integrity. Radial cracking is a pervasive failure mode in cement due to the temperature and pressure variation during drilling, completion, or production. This work presents a comprehensive analysis of radial cracking in cement under various loading events. The proposed model estimates the stress intensity factor and fracture surface displacement as indicators for crack propagation and opening, respectively, through a distributed dislocation technique. Three types of radial cracks, divided by their tips terminating at the casing–cement interface, inside cement, or at the cement–formation interface, are considered. Based on this model, we conduct a parametric study for radial cracking under typical loading events such as steam injection, CO2 injection, and high-pressure and high-temperature (HPHT) drilling. Results indicate that the crack near the casing–cement interface has an increased risk for steam injection and HPHT drilling, while all three types of radial cracks are destructive during CO2 injection. The thermal expansion coefficient of cement is a significant parameter for steam and CO2 injection wells. The fluid pressure and the cement’s thickness are crucial to radial cracking under HPHT conditions. Stiffer cement could promote crack opening for steam injection but prohibit the crack deformation for CO2 injection or HPHT wells. Thicker cement would accelerate radial cracking under the three loading events. These findings are helpful in designing cement to maintain long-term integrity.
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Kutlu, Bahri, Nicholas Takach, Evren M. Ozbayoglu, Stefan Z. Miska, Mengjiao Yu, and Clara Mata. "Drilling Fluid Density and Hydraulic Drag Reduction With Glass Bubble Additives." Journal of Energy Resources Technology 139, no. 4 (May 11, 2017). http://dx.doi.org/10.1115/1.4036540.
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This study concentrates on the use of materials known as hollow glass spheres, also known as glass bubbles, to reduce the drilling fluid density below the base fluid density without introducing a compressible phase to the wellbore. Four types of lightweight glass spheres with different physical properties were tested for their impact on rheological behavior, density reduction effect, survival ratio at elevated pressures, and hydraulic drag reduction effect when mixed with water-based fluids. A Fann75 high pressure high temperature (HPHT) viscometer and a flow loop were used for the experiments. Results show that glass spheres successfully reduce the density of the base drilling fluid while maintaining an average of 0.93 survival ratio, the rheological behavior of the tested fluids at elevated concentrations of glass bubbles is similar to the rheological behavior of conventional drilling fluids and hydraulic drag reduction is present up to certain concentrations. All results were integrated into hydraulics calculations for a wellbore scenario that accounts for the effect of temperature and pressure on rheological properties, as well as the effect of glass bubble concentration on mud temperature distribution along the wellbore. The effect of drag reduction was also considered in the calculations.
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Contreras, Oscar, Mortadha Alsaba, Geir Hareland, Maen Husein, and Runar Nygaard. "Effect on Fracture Pressure by Adding Iron-Based and Calcium-Based Nanoparticles to a Nonaqueous Drilling Fluid for Permeable Formations." Journal of Energy Resources Technology 138, no. 3 (February 5, 2016). http://dx.doi.org/10.1115/1.4032542.
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This paper presents a comprehensive experimental evaluation to investigate the effects of adding iron-based and calcium-based nanoparticles (NPs) to nonaqueous drilling fluids (NAFs) as a fluid loss additive and for wellbore strengthening applications in permeable formations. API standard high-pressure-high-temperature (HPHT) filter press in conjunction with ceramic disks is used to quantify fluid loss reduction. Hydraulic fracturing experiments are carried out to measure fracturing and re-opening pressures. A significant enhancement in both filtration and strengthening was achieved by means of in situ prepared NPs. Our results demonstrate that filtration reduction is essential for successful wellbore strengthening; however, excessive reduction could affect the strengthening negatively.
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Wagle, Vikrant, Abdullah AlYami, Michael Onoriode, and Jacques Butcher. "Low Equivalent Circulating Density Organoclay-Free Invert Emulsion Drilling Fluids." Journal of Energy Resources Technology 144, no. 9 (February 15, 2022). http://dx.doi.org/10.1115/1.4053557.
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Abstract High pressure and high temperature (HPHT) wells especially those with narrow pore/fracture pressure gradient margins present challenges in drilling. Maintaining optimum and low rheology for such wells becomes a challenge where a slight change in the bottom-hole pressure conditions can lead to nonproductive time. However, maintaining low viscosity profile for a drilling fluid can pose a dual challenge in terms of maintaining effective hole-cleaning and barite-sag resistance. This paper describes the formulation of 95pcf medium-density organoclay-free invert emulsion drilling fluids (OCIEF) with a low viscosity profile. The fluids gave lower plastic viscosity (PV), which ensured that the fluid presents low equivalent circulating density (ECD) contribution while drilling/circulating. These fluids were formulated with acid-soluble manganese tetroxide as weighting agent and a specially designed bridging-agent package. The fluids were hot rolled at 300 °F and their filtration and rheological properties were measured. The paper describes the static-aging, contamination, and high pressure/high temperature rheology measurements of the fluids at 300 °F. Particle plugging experiments were performed on the fluids to determine the invasion characteristics and the nondamaging nature of the fluids. These organoclay-free invert emulsion fluids (OCIEFs) were then field-trialed in different wells with good results. Field deployment of the 95pcf organoclay-free invert emulsion fluid helped to maintain the required hole stability in the high temperature and high pressure (HTHP) well. The well was displaced to 95pcf production screen test (PST) fluid and completed with a 4 ½ in. sand screen. The paper demonstrates the superior performance of the developed fluid in achieving the desired lab and field performance.
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"Substituting Locally Sourced Carbon Nano Particle with the Conventional Additives." International Journal of Multidisciplinary Research and Analysis 05, no. 07 (July 15, 2022). http://dx.doi.org/10.47191/ijmra/v5-i7-18.
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Nanoparticle drilling fluids have the potential to minimize wellbore instability problems. There is a need for the development of a new generation of drilling fluids to handle wellbore instability problems especially in lost circulation zones and shale problems. A rheological model is needed to accurately describe the rheology of nano base drilling fluid because limited experimental data are currently available for using carbon nano particles in water base mud and Inability of current methods to address shale strength with increased open hole time reduction of critical mud weight to prevent hole collapse in challenging environment like depleted formation, narrow margin, HPHT wells. The study attempted to produce nano particles locally where the in-situ formation of floating catalyst was used. It involved the floating of catalyst particles by thermal decomposition of organometallic where argon, acethelene and nitrogen gas were used. The CNP WBM formulation was compared with the conventional base mud. Result Show that the CNP mud gave a better result for the fluid loss which can be used as a fluid loss property in the study mud, CNP gave 6.2mls while soltex gave 8.2mls and also CNP gave a thin and firm filter cake of 0.18cm as compared to the soltex formulated mud. Therefore, CNP is a good fluid loss additive and enhances the rheological properties of mud, also helped to improve and add value to local content in the oil and gas industry and save us the cost through the application of locally sourced drilling fluid and save foreign exchange and It has export potentials in the Gulf of Guinea and other oil provinces.
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S., Winarto, and Sugiatmo Kasmungin. "Modification of DS-01 Drilling Fluid to Reduce Formation Damage." Journal of Earth Energy Science, Engineering, and Technology 2, no. 3 (February 6, 2020). http://dx.doi.org/10.25105/jeeset.v2i3.6389.
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<em>In the process of drilling for oil and gas wells the use of appropriate drilling mud can reduce the negative impacts during ongoing drilling and post-drilling operations (production). In general, one of the drilling muds that are often used is conventional mud type with weighting agent barite, but the use of this type of mud often results in skin that is difficult to clean. Therefore in this laboratory research an experiment was carried out using a CaCO3 weigting agent called Mud DS-01. CaCO3 is widely used as a material for Lost Circulation Material so that it is expected that using CaCO3 mud will have little effect on formation damage or at least easily cleaned by acidizing. The aim of this research is to obtain a formula of mud with CaCO3 which at least gives formation damage. Laboratory experiments on this drilling mud using several mud samples adjusted to the property specifications of the mud program. Mud sample consists of 4, namely using super fine, fine, medium, and conventional CaCO3. First measuring mud properties in each sample then testing the filter cake breaker, testing the initial flow rate using 200 ml of distilled water and a 20 micron filter disk inserted in a 500 ml HPHT cell then assembled in a PPA jacket and injecting a pressure of 100 psi. The acidification test was then performed using 15% HCL and then pressured 100 psi for 3 hours to let the acid work to remove the cake attached to the filter disk (acidizing). Laboratory studies are expected which of these samples will minimize the formation damage caused by drilling fluids.</em>
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Chagas, Felipe, Paulo R. Ribeiro, and Otto L. A. Santos. "Well Control Simulation With Nonaqueous Drilling Fluids." Journal of Energy Resources Technology 143, no. 3 (December 14, 2020). http://dx.doi.org/10.1115/1.4049177.
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Abstract The demand for energy has increased recently worldwide, requiring new oilfield discoveries to supply this need. Following this demand increase, challenges grow in all areas of the petroleum industry especially those related to drilling operations. Due to hard operational conditions found when drilling complex scenarios such as high-pressure/high-temperature (HPHT) zones, deep and ultradeep water, and other challenges, the use nonaqueous drilling fluids became a must. The reason for that is because this kind of drilling fluid is capable to tolerate these extreme drilling conditions found in those scenarios. However, it can experience changes in its properties as a result of pressure and temperature variations, requiring special attention during some drilling operations, such as the well control. The well control is a critical issue since it involves safety, social, economic, and environmental aspects. Well control simulators are a valuable tool to support well control operations and preserve the well integrity, verifying operational parameters and to assist drilling engineers in the decision-making process during well control operations and kick situations. They are also important computational tools for rig personnel training. This study presents well control research and development contributions, as well as the results of a computational well control simulator that applies the Driller's method and allows the understanding the thermodynamic behavior of synthetic drilling fluids, such as n-paraffin and ester base fluids. The simulator employed mathematical correlations for the drilling fluids pressure–volume–temperature (PVT) properties obtained from the experimental data. The simulator results were compared to a test well data set as well to the published results from other kick simulators.
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Alizadeh, S. M., Issam Alruyemi, Reza Daneshfar, Mohammad Mohammadi-Khanaposhtani, and Maryam Naseri. "An insight into the estimation of drilling fluid density at HPHT condition using PSO-, ICA-, and GA-LSSVM strategies." Scientific Reports 11, no. 1 (March 29, 2021). http://dx.doi.org/10.1038/s41598-021-86264-5.
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AbstractThe present study evaluates the drilling fluid density of oil fields at enhanced temperatures and pressures. The main objective of this work is to introduce a set of modeling and experimental techniques for forecasting the drilling fluid density via various intelligent models. Three models were assessed, including PSO-LSSVM, ICA-LSSVM, and GA-LSSVM. The PSO-LSSVM technique outperformed the other models in light of the smallest deviation factor, reflecting the responses of the largest accuracy. The experimental and modeled regression diagrams of the coefficient of determination (R2) were plotted. In the GA-LSSVM approach, R2 was calculated to be 0.998, 0.996 and 0.996 for the training, testing and validation datasets, respectively. R2 was obtained to be 0.999, 0.999 and 0.998 for the training, testing and validation datasets, respectively, in the ICA-LSSVM approach. Finally, it was found to be 0.999, 0.999 and 0.999 for the training, testing and validation datasets in the PSO-LSSVM method, respectively. In addition, a sensitivity analysis was performed to explore the impacts of several variables. It was observed that the initial density had the largest impact on the drilling fluid density, yielding a 0.98 relevancy factor.
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Ismail, Issham, Rosli Illias, Amy Shareena Abd. Mubin, and Masseera Machitin. "Degrading Drilling Fluid Filter Cake Using Effective Microorganisms." Jurnal Teknologi, November 2, 2012, 1–22. http://dx.doi.org/10.11113/jt.v57.1249.
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The effective cleanup of filter cakes in long, horizontal open-hole completions can maximize an oil well’s productivity. A cleaning solution was formulated which comprised effective microorganisms and a viscoelastic surfactant in order to degrade filter cakes of water-based mud. Generally, the effectiveness of the microorganisms in degrading filter cakes is influenced by temperature and its concentration. To overcome the problem, the viscoelastic surfactant has been used to extend the application of temperature range and increase the viscosity of the cleaning solution. Laboratory studies were conducted to examine the effectiveness of the microorganisms in degrading filter cakes. The apparent viscosity of cleaning solution was measured as a function of shear rate (102.2 s and 1022 s ) and temperature (25 to 80°C). The surface tension of the cleaning solution was measured at room temperature. Static fluid loss tests were performed using the HPHT Filter Press in order to determine the effectiveness of the cleaning solution in degrading filter cake at different temperatures ranging from 100°F to 300°F. Experimental results showed that the cleaning solution could effectively degrade the filter cake. Soaking process was performed until 48 hours and it showed that at temperature 200°F and below, the pure effective microorganisms achieved the highest efficiency of filter cake degradation, i.e. 34.9%. However, at temperature 300°F, cleaning solution that contained effective microorganisms and higher concentration of viscoelastic surfactant was found to perform better. The viscoelastic surfactant succeeded in increasing the viscosity of the cleaning solution, thus enhanced the rate of degradation of filter cakes, i.e. 33.4% at 300°F. The surface tension of the cleaning solution did not change significantly at various concentrations at room temperature.
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Martin, C., M. Babaie, A. Nourian, and G. G. Nasr. "Rheological Properties of the Water-Based Muds Composed of Silica Nanoparticle Under High Pressure and High Temperature." SPE Journal, March 1, 2022, 1–14. http://dx.doi.org/10.2118/209786-pa.
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Summary Research currently has shown two contradicting conclusions about silica nanoparticle (SNP) application in mud fluid. While different studies have concluded that adding SNPs reduces the rheological properties, others have found that this is not the case. Therefore, this work was carried out to add to the literature and research that has already been done by different scholars on the performance of SNPs in water-based muds (WBMs). The synthesis of SNPs was performed by the sol-gel process based on the Stöber method in a mixture of a catalyst ammonium hydroxide containing tetraethyl orthosilicate (TEOS), ethanol, and water. The distribution of particle dispersion, size, and zeta potential of SNP analysis was obtained using the dynamic light scattering analysis. Rheological analysis indicated good rheology at different temperatures with 0.5 wt% and 1.0 wt% silica concentration. Furthermore, viscosity and yield point (YP) were stabilized with nanoparticles (NPs at elevated temperatures (up to 176°C) as well as the reference mud maintained rheology (up to 121°C) and above that temperature, there was a drastic change indicating failure. Aging at temperatures above 121°C for 16 hours showed that NP WBMs remained stable with minor changes in rheology. Using bigger sized SNPs than previously used resulted to enhancement in the rheology of WBMs. Previous studies had used SNPs in sizes of 20–40 nm which negatively affected mud rheology. In this study, SNP of a bigger size resulted in rheological property enhancement. It is believed that particle size with other dynamics and mechanisms that still need to be investigated, for example, zeta potential, repulsive and attractive forces are some of the factors in play that affect nanoparticle performance in mud fluids. The obtained rheological data for different NP muds were matched to the traditional drilling mud rheological models to ascertain the best fit model that would be applied to an efficient design and the data fitted the Herschel-Bulkley model. Filtration tests at high pressure and high temperature (HPHT) conditions also indicated that synthesized SNPs used in the mud fluid resulted in a slightly low permeable thin mudcake and a low API gravity filtration loss which have great advantages when drilling through highly permeable formations. Filtrate loss was reduced by 7.5, 9.1, 15.4, and 6.7% when temperature increased to 100, 121, 149, and 176 °C at 1 wt% silica concentration, respectively. The mudcake was also improved and thickness reduced by 30 and 25% at 0.5 wt% silica concentration when temperatures increased from 149 and 176°C, respectively, compared to the reference mud (R) under HPHT conditions. The research results provide a comprehensive evaluation of an enhanced WBM using SNPs for HPHT applications. The investigated NP has the potential to improve drilling mud properties which may led to less formation damage and efficient drilling operations.
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Bageri, Badr, Jaber Aljaberi, and Salaheldin Elkatatny. "Effect of Hematite Dosage on Water-Based Drilling Fluid and Filter Cake Properties." Journal of Energy Resources Technology, August 11, 2022, 1–11. http://dx.doi.org/10.1115/1.4055209.
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Abstract Drilling deep wells became common in the oil and gas sector as a result of the high demand for energy in the world. This type of wells is not trivial to drill as a result several challenges that they encounter, such as harsh conditions represented by high-pressure and high-temperature (HPHT), and the high hydrostatic column required to prevent the kick. Therefore, advanced materials are desired and accordingly higher concentration of weighting material is required to drill such resources. In this work, a systematic investigation of the hematite concentration effect on the water-based drilling fluid properties is performed. Three doses were overloaded to a constant drill fluid recipe. Then the drilling fluid properties including density, viscosities, filtration, and filter cake properties were evaluated. The viscosities were assessed at the temperature of 120 °F, before and after aging in a hot rolling oven for 16 hrs. at 250 °F and 500 psi. The API filtration test was performed at ambient temperature and 100 psi. The results showed that the hematite concertation has proportional relation to the apparent viscosity, plastic viscosity, and yield point before and after the hot rolling. The YP/PV ratio was decreased as the hematite dose increased in the drilling fluid. Similarly, the gel strengths at 10 seconds and 10 minutes were increased as the concentration of hematite increased. The filter cake thinness, filtration volume, and filter cake permeability were also amplified as the hematite concertation increased, where the filter cake porosity was almost kept constant. In addition, several correlations were drawn as function of the hematite dosage for the examined drilling properties.
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Razzaq, Waseem, Salaheldin Elkatatny, Hany Gamal, and Ariffin Samsuri. "The Utilization of Steelmaking Industrial Waste of Silicomanganese Fume as Filtration Loss Control in Drilling Fluid Application." Journal of Energy Resources Technology 144, no. 2 (May 31, 2021). http://dx.doi.org/10.1115/1.4051197.
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Abstract Drilling fluid is considered the backbone of drilling operations in the oil and gas industry to unlock hydrocarbon from subterranean formations. Maintaining the drilling fluid properties, for example, flow properties such as rheology, plastic viscosity (PV), yield point (YP), gel strength (GS), and circulation loss, is the challenge for fluid/mud engineers to carry out successful drilling operations. A variety of chemicals have been added to improve the drilling fluid properties by introducing new chemicals or optimizing the existing chemicals without affecting the other essential fluid properties. The present study for the first time employs the eco-innovation concept to explore the utilization of steelmaking industry waste, i.e., silicomanganese fume (SMF), as a bridging material. The objective of this article is to design an eco-friendly framework that comprehensively explains and utilizes SMF as a bridging material in water-based fluid (WBF). The eco-innovation/eco-friendly framework includes the steps required for processing and understanding the new material and evaluating its effects on flow and the bridging properties of WBF. A scanning electron microscope (SEM), X-ray fluorescence (XRF), and particle size distribution (PSD) were used to understand the physicochemical properties of SMF. The flow properties were studied using a Fann rheometer before and after hot rolling at 120 °F. A high-pressure high-temperature (HPHT) filter press equipment was used to investigate the bridging capability of seepage losses following conditions of 190 °F and 300 psi differential pressure. Minimal cleaning and disintegration with a mortar and pestle are enough to prepare SMF to be incorporated in drilling fluid. The SEM and XRF results showed that SMF contains oxides of manganese, silicon, potassium, calcium, and magnesium, while the PSD revealed a natural bimodal distribution with an average grain size of D50 of around 29 μm. SMF showed a noticeable and measurable enhancement of flow properties and bridging capability in WBF. The SMF-based WBF showed improved rheological properties, plastic viscosity, and yield point compared with marble-based WBF. Adding SMF to WBF with and without marble showed a ten-fold superior plugging performance compared with marble-based WBF using 20-μm ceramic discs. The findings revealed the successful utilization of SMF in WBF by improving the rheology, plastic viscosity, yield point, and bridging capability.