Academic literature on the topic 'HPHT drilling fluid'
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Journal articles on the topic "HPHT drilling fluid"
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Ali, Muhammad, Husna Hayati Jarni, Adnan Aftab, Abdul Razak Ismail, Noori M. Cata Saady, Muhammad Faraz Sahito, Alireza Keshavarz, Stefan Iglauer, and Mohammad Sarmadivaleh. "Nanomaterial-Based Drilling Fluids for Exploitation of Unconventional Reservoirs: A Review." Energies 13, no. 13 (July 2, 2020): 3417. http://dx.doi.org/10.3390/en13133417.
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The world’s energy demand is steadily increasing where it has now become difficult for conventional hydrocarbon reservoir to meet levels of demand. Therefore, oil and gas companies are seeking novel ways to exploit and unlock the potential of unconventional resources. These resources include tight gas reservoirs, tight sandstone oil, oil and gas shales reservoirs, and high pressure high temperature (HPHT) wells. Drilling of HPHT wells and shale reservoirs has become more widespread in the global petroleum and natural gas industry. There is a current need to extend robust techniques beyond costly drilling and completion jobs, with the potential for exponential expansion. Drilling fluids and their additives are being customized in order to cater for HPHT well drilling issues. Certain conventional additives, e.g., filtrate loss additives, viscosifier additives, shale inhibitor, and shale stabilizer additives are not suitable in the HPHT environment, where they are consequently inappropriate for shale drilling. A better understanding of the selection of drilling fluids and additives for hydrocarbon water-sensitive reservoirs within HPHT environments can be achieved by identifying the challenges in conventional drilling fluids technology and their replacement with eco-friendly, cheaper, and multi-functional valuable products. In this regard, several laboratory-scale literatures have reported that nanomaterial has improved the properties of drilling fluids in the HPHT environment. This review critically evaluates nanomaterial utilization for improvement of rheological properties, filtrate loss, viscosity, and clay- and shale-inhibition at increasing temperature and pressures during the exploitation of hydrocarbons. The performance and potential of nanomaterials, which influence the nature of drilling fluid and its multi-benefits, is rarely reviewed in technical literature of water-based drilling fluid systems. Moreover, this review presented case studies of two HPHT fields and one HPHT basin, and compared their drilling fluid program for optimum selection of drilling fluid in HPHT environment.
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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.
Conference papers on the topic "HPHT drilling fluid"
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Bland, Ronald G., Gregory Alan Mullen, Yohnny N. Gonzalez, Floyd Ernest Harvey, and Marvin L. Pless. "HPHT Drilling Fluid Challenges." In IADC/SPE Asia Pacific Drilling Technology Conference and Exhibition. Society of Petroleum Engineers, 2006. http://dx.doi.org/10.2118/103731-ms.
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Vryzas, Zisis, Omar Mahmoud, Hisham Nasr-El-Din, Vassilis Zaspalis, and Vassilios C. Kelessidis. "Incorporation of Fe3O4 Nanoparticles as Drilling Fluid Additives for Improved Drilling Operations." In ASME 2016 35th International Conference on Ocean, Offshore and Arctic Engineering. American Society of Mechanical Engineers, 2016. http://dx.doi.org/10.1115/omae2016-54071.
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A successful drilling operation requires an effective drilling fluid system. Due to the variety of downhole conditions across the globe, the fluid system should be designed to meet complex challenges such as High-Pressure/High-Temperature (HPHT) environments, while promoting better productivity with a minimum interference for completion operations. This study aims to improve the rheological and fluid loss properties of water-bentonite suspensions by using both commercial (C-NP) and custom-made (CM-NP) iron oxide (Fe3O4) nanoparticles (NP) as drilling fluid additives. Superparamagnetic Fe3O4 NP were synthesized by the co-precipitation method. Both types of nanoparticles were characterized by a High Resolution Transmission Electron Microscope (TEM) and X-ray Diffraction (XRD). Base fluid (BF), made of deionized water and bentonite at 7wt%, was prepared according to American Petroleum Institute (API) procedures and nanoparticles were added at 0.5wt%. A Couette-type viscometer was used to analyze the rheological characteristics of these fluids at different shear rates and various temperatures (up to 158°F). The rheological parameters were obtained from analysis of viscometric data using non-linear regression. The API Low-Pressure/Low-Temperature (LPLT) and HPHT fluid filtrate volumes were measured, using a standard API LPLT static filter press (100 psi, 77°F) and an API HPHT filter press (300 psi, 250°F). Observation of the porous matrix morphology of the produced filter cakes was done with Scanning Electron Microscope (SEM). TEM showed that the mean diameter of the CM-NP was 7–8 nm, with measured surface areas between 100–250 m2/g. The C-NP had an average diameter of <50 nm, as per manufacturer specifications. The XRD of the CM-NP revealed peaks corresponding to pure crystallites of magnetite (Fe3O4) with no impurities. Rheological analysis showed very good fitting by the Herschel-Bulkley model with coefficient of determination (R2) greater than 0.99. Rheological properties of all samples were affected by higher temperatures, with increase in yield stress, decrease in flow consistency index (K) and slight increase in flow behavior index (n). Fluid filtration results indicated a decrease in the LPLT fluid loss and an increase in the filter cake thickness compared to the BF upon addition of higher concentrations of C-NP, because of a decrease in filter cake permeability. At HPHT conditions, samples with 0.5wt% C-NP had a smaller fluid loss by 34.3%, compared to 11.9% at LPLT conditions. CM-NP exhibited even higher reduction in the fluid loss at HPHT conditions of 40%. Such drilling fluids can solve difficult drilling problems and aid in achieving the reservoir’s highest potential by eliminating the use of aggressive, potentially damaging chemicals. Exploitation of the synergistic interaction of the utilized components can produce a water-based system with excellent fluid loss characteristics while maintaining optimal rheological properties.
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Lee, John, Arash Shadravan, and Steven Young. "Rheological Properties of Invert Emulsion Drilling Fluid under Extreme HPHT Conditions." In IADC/SPE Drilling Conference and Exhibition. Society of Petroleum Engineers, 2012. http://dx.doi.org/10.2118/151413-ms.
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Torsvik, Anja, Jan Ole Skogestad, and Harald Linga. "Impact on Oil-Based Drilling Fluid Properties from Gas Influx at HPHT Conditions." In IADC/SPE Drilling Conference and Exhibition. Society of Petroleum Engineers, 2016. http://dx.doi.org/10.2118/178860-ms.
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Ghazali, Nurul Aimi, Shigemi Naganawa, Yoshihiro Masuda, Wan Asma Ibrahim, and Noor Fitrah Abu Bakar. "Eco-Friendly Drilling Fluid Deflocculant for Drilling High Temperature Well: A Review." In ASME 2018 37th International Conference on Ocean, Offshore and Arctic Engineering. American Society of Mechanical Engineers, 2018. http://dx.doi.org/10.1115/omae2018-78149.
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Conventional clay-based drilling fluids often experienced difficulties in controlling the rheological properties, gelation, and filtration due to flocculation of clay at the temperature higher than 121°C. Deflocculant or thinner, one of the drilling fluid additives, serves a significant role in preventing the association of clay particles particularly in high temperature environments such as high-pressure and high-temperature (HPHT) deep-water drilling. Lignosulfonate has been commonly used in the industry as deflocculant for clay-based drilling fluids since the late 1950s as a replacement for Quebracho tannin. Degradation at the elevated temperature limits the usage of anionic polymer and lignosulfonate. In improving the stability of deflocculant at high temperature, lignosulfonate is admixed or reacted with chromium and iron compound to obtain ferro-chrome lignosulfonate whose temperature limit is approximately 190°C. While recent ferro-chrome lignosulfonate contains less chrome than in the past, development of more environmentally friendly and higher thermally stable deflocculant is still needed. In HPHT environment which requires high-density drilling fluid, a higher thermally-stable deflocculant is also valuable for barite sagging that becomes problematic at a temperature higher than 200°C. Several findings in the past development of adhesives show that addition of tannin improves the thermal stability of lignosulfonate. Tannin is a polyphenolic compound that is natural, non-toxic and biodegradable and can be found in various part of a vascular plant other than Quebracho. Lignosulfonate, on the other hand, is a byproduct of the paper pulping process. Tannin and lignosulfonate are cross-linked to obtain tannin–lignosulfonate for use as a high-temperature drilling fluid deflocculant. Tannin and lignin are the most abundant compounds extracted from biomass. The wide availability of tannin and lignosulfonate is an advantage from a manufacturing cost viewpoint. In this paper, an overview of drilling fluids, classification of drilling fluid, high temperature reservoir environment, and mechanisms of dispersion and deflocculation are presented. Further discussion on the potential development of eco-friendly tannin–lignosulfonate based drilling fluid system for the high temperature well development also presented.
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Mohammed, Auwalu Inuwa, Gbenga Oluyemi, and Sulaiman Dodo Ibrahim. "CFD Investigation of Application Potentials of Molybdenum Trioxide as Drilling Fluid Additive for HPHT Drilling Applications." In SPE Nigeria Annual International Conference and Exhibition. Society of Petroleum Engineers, 2013. http://dx.doi.org/10.2118/167576-ms.
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Chodankar, Abhijeet D., and Cheng-Xian Lin. "Borehole Temperature Modelling in High Temperature Drilling Environment Based on Heat Transfer Laws." In ASME 2019 International Mechanical Engineering Congress and Exposition. American Society of Mechanical Engineers, 2019. http://dx.doi.org/10.1115/imece2019-10085.
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Abstract High temperature drilling environment has a drastic effect on drilling fluids, wellbore stability, and drilling system components. It has been observed that drilling fluids displace conventional halide based fluids in High Pressure and High Temperature (HPHT) wells leading to corrosion and environmental hazards, while wellbore strengthens further as a result of an increase in fracture initiation pressure in high temperature environment. However, it seriously damages the downhole tools like sensors, elastomer dynamic seals, lithium batteries, electronic component and boards leading to increases in cost and non-productive time. The main objective of this paper is to present an analytical borehole temperature model based on classical heat transfer laws in a high temperature drilling environment. The borehole is modelled using two approaches: composite wall and concentric cylinders. The composite wall and concentric cylinder approaches consist layers of geological formations, drilling fluids outside the drill string, drill string, and drilling fluid inside the drill string. Temperature, heat transfer coefficient, and heat transfer variations along the borehole layers are determined using the derived analytical solutions and tested for different drilling fluid types, air drilling environment, and different drill string materials. The results of composite wall and concentric cylinder models are obtained by using the input field temperatures data in the geological formation and inner annulus of drill pipe to determine the borehole temperature profile in HPHT wells. Therefore, a thorough borehole heat transfer analysis will help in wellbore stability, drilling fluid selection, corrosion control, and optimal placement and material selection of drilling components in HPHT drilling environments.
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Gharib Shirangi, Mehrdad, Roger Aragall, Reza Ettehadi, Roland May, Edward Furlong, Charles A. Thompson, and Thomas G. Dahl. "Development of Digital Twins for Drilling Fluids: Local Velocities for Hole Cleaning and Rheology Monitoring." In ASME 2021 40th International Conference on Ocean, Offshore and Arctic Engineering. American Society of Mechanical Engineers, 2021. http://dx.doi.org/10.1115/omae2021-62987.
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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 realtime operations. From several drilling fluid functionalities and operational parameters, we describe advancements to improve hole cleaning predictions and high-pressure high-temperature (HPHT) rheological properties monitoring. In the hole cleaning application, we consider the Clark and Bickham (1994) approach which requires the prediction of the local fluid velocity above the cuttings bed as a function of operating conditions. 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 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 application) 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 R-squared) for test datasets. With developments presented in this paper, the hole cleaning calculations can be performed more accurately in real-time, and the HPHT rheological properties of drilling fluids can be estimated at the rigsite before performing the lab experiments. These contributions advance digital transformation of drilling operations.
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Reyna, Ricardo, Viridiana Parra, Daniel Volbre, Raul Ballinas, Reinaldo Maldonado, and Jene Rockwood. "Innovative Drilling Fluid Technology Conquered Tough Geomechanics Offshore Mexico." In SPE/IADC International Drilling Conference and Exhibition. SPE, 2021. http://dx.doi.org/10.2118/204109-ms.
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Abstract The reservoir field highlighted in this paper is located Offshore Mexico in the southeast part of Campeche Bay and hidden below a troublesome, unstable formation that must be transacted before reaching the new production zone. During the exploration phase, this section experienced severe lost circulation and unstable conditions before reaching the final depth. Based on lessons learned, the team worked to develop a best- practices approach using geomechanics analysis and a novel fluid technology which enabled the operator to safely drill through this problematic intermediate section under high-pressure, high-temperature (HPHT) conditions. The methodology started with identifying the geomechanics challenges, implementing operational best practices, and finally, use of an innovative, low-invasion fluid technology, which creates a thin and impermeable shield at the wellbore wall, effectively sealing the fractures and preventing fracture propagation in the highly unstable formation of interspersed carbonates, shales, and sandstones. The strong mechanical properties of the thin, but firm, barrier created at the wellbore wall minimized the destabilizing effect of fluid invasion. Synergy from the geomechanical team, best practices for the operation, and innovative drilling fluid technology solved the wellbore instability drilling challenge encountered in the exploration well. In offset wells, losses of more than 2,200 m3 of drilling fluid, stuck pipe, and major NPT were observed. By incorporating the shielding technology, wellbore instability was improved in the intermediate section. In addition, the fluid technology was easily pumped through the bottomhole assembly (BHA) to seal formation fractures between 2,000 and 3,000 μm in size. This well, utilizing the barrier technology to mitigate the wellbore instability and drill within a narrow fracture gradient operating window, was the first in the area to have zero loss of drilling fluid as compared to the typical 5 to 10-m3/hr circulation losses experienced during exploration drilling in the intermediate section characterized by interbedded layers of carbonates, shales, and sandstone under high-pressure, high-temperature (HPHT) conditions. The coordination between the teams using best practices was critical to meeting the challenge of the intermediate geomechanically weak formation. This case history in offshore Mexico will demonstrate both the importance of teamwork and the utilization of a proven technology that improves wellbore instability, minimizes NPT, mitigates pipe tripping issues and avoids huge volumes of drilling fluid lost into the geomechanically weak formation. This barrier technology can be applied globally to troublesome formations - such as interbedded carbonates, shales, and sandstones - to improve operations and provide cost savings for the operator.
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Witthayapanyanon, Anuradee, Kathi Chandramouleeswaran, Ahmad Bin Dollah, Dennis Clapper, Ronald Bland, Akachai Kongsawast, Michael Manfred Pepple, Khairul Anwar Nasrudin, and M. Abshar. "Ultra-HPHT Drilling Fluid Design for Frontier Deep Gas Exploration in South Malay Basin." In Offshore Technology Conference-Asia. Offshore Technology Conference, 2014. http://dx.doi.org/10.4043/24830-ms.
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