Water-based Drilling Fluids Research Articles

Improving the rheological and thermal stability of water-based drilling fluids by incrementing xanthan gum concentration

Water-based drilling fluids (WBDF) are often used over oil-based drilling fluids due to economic reasons and environmental regulations. Bentonite-free WBDF is preferred to aid in the reduction of formation damage. In many cases, this WBDF is formulated with xanthan gum. The performance of drilling operations is mainly affected by the drilling fluid formulation. The complex interactions among polymer concentration, thermal, and shear histories influence the rheological behavior of drilling fluids. The present study aims to analyze the effects of xanthan gum concentration on the rheological behavior of water-based drilling fluids. The experimental results performed in rotational rheometers revealed a relationship between concentration, yield stress, and thixotropic phenomena. The increase in xanthan gum concentration not only enhances the stability of the drilling fluid, allowing for more prolonged process interruptions without risking the fluid degradation but also improves the thermal stability of the sample. These findings show that the concentration of xanthan gum improves water-based drilling fluids' rheological and thermal stability.

High temperature degradable pullulan microsphere/polymer composite for filtration loss control of water-based drilling fluids

The effective control of water-based drilling fluid filtration rates in deep and ultra-deep wells poses a significant challenge. This study introduced a novel approach utilizing pullulan microsphere (PM) grafted with N,N-dimethylacrylamide, 2-acrylamido-2-methylpropanesulfonic acid, and dimethyl diallyl ammonium chloride as a filtrate reducer (PM-DAD). The polymer's structure was analyzed through Fourier transform infrared spectroscopy, nuclear magnetic resonance, thermogravimetric analysis, and scanning electron microscopy. Structural characterization confirmed the successful polymerization and good thermal stability of PM-DAD. PM-DAD showed the pH response characteristics of particle size decreasing with the increase of alkalinity and the temperature response characteristics of degradation into nanoparticles after high temperature aging. The filtration loss and rheological properties of PM-DAD were assessed in accordance with the American Petroleum Institute standards. The rheological evaluation results indicated that PM-DAD could effectively maintain optimal rheological properties of the base mud after aging. PM-DAD showed remarkable filtration loss reduction ability. After aging at 200 °C, the filtration loss of the base mud was 4.7 mL, and that of the base mud containing 15 wt% NaCl was 8.2 mL. The filtration reduction mechanism of PM-DAD was investigated through mud cake analysis, particle size distribution, and X-ray diffraction. The filtration loss reduction mechanism showed that degraded nano PM-DAD intercalated between smectite clay minerals, creating electrostatic attraction and hydrogen bonds with the smectite surface, thereby facilitating the formation of a dense filter cake This research not only presents a novel approach for the utilization of pullulan but also offers a new path for controlling high-temperature filtration in water-based drilling fluids.

Synthesis of a Novel Modified Polysiloxane Filtrate Reducer and its Application in Water-Based Drilling Fluids

Synthesis of a Novel Modified Polysiloxane Filtrate Reducer and its Application in Water-Based Drilling Fluids

Experiment and Simulation of Nanoparticles from the Assembly of Poly(St-(1-Octene)-EGDMA) as a Nano-Plugging Agent in Water-Based Drilling Fluids

Experiment and Simulation of Nanoparticles from the Assembly of Poly(St-(1-Octene)-EGDMA) as a Nano-Plugging Agent in Water-Based Drilling Fluids

Effect of Ionic Liquids with Different Structures on Rheological Properties of Water-Based Drilling Fluids and Mechanism Research at Ultra-High Temperatures.

The rheology control of water-based drilling fluids at ultra-high temperatures has been one of the major challenges in deep or ultra-deep resource exploration. In this paper, the effects of 1-ethyl-3-methylimidazolium bis(trifluoromethanesulfonimide) (ILA), 1-ethyl-3-methylimidazolium tetrafluoroborate (ILB) and N-methyl, butylpyrrolidinium bis(trifluoromethanesulfonimide) (ILC) on the rheological properties and filtration loss of polymer-based slurries at ultra-high temperatures (200 °C and 240 °C) are investigated by the American Petroleum Institute (API) standards. The results show that ionic liquids with different structures could improve the high-temperature rheological properties of polymer-based drilling fluids. The rheological parameter value (YP/PV) of the polymer-based slurry formulated with ILC is slightly higher than that with ILA at the same concentration, while the YP/PV value of the polymer-based slurry with ILA is slightly higher than that with ILB, which is consistent with the TGA thermal stability of ILA, ILB, and ILC; the thermal stability of ILC with pyrrolidine cations is higher than that of ILA with imidazole cations, and the thermal stability of ILA with bis(trifluorosulfonyl)amide anions is higher than that of ILB with tetrafluoroborate anions. Cation interlayer exchange between organic cation and sodium montmorillonite can improve the rheological properties of water-based drilling fluids. And meantime, the S=O bond in bis(trifluorosulfonyl)amide ions and the hydroxyl group of sodium montmorillonite may form hydrogen bonds, which also may increase the rheological properties of water-based drilling fluids. ILA, ILB, and ILC cannot reduce the filtration loss of polymer-based drilling fluids at ultra-high temperatures.

Improving shale hydration inhibition with hydrophobically modified graphene oxide in water-based drilling fluids

Frequent wellbore instability issues caused by shale hydration and dispersion are encountered in water-based drilling fluids. In order to mitigate shale hydration, a hydrophobic graphene oxide (HGO) was prepared as a new shale inhibitor and characterized. The effectiveness of HGO in inhibiting shale hydration was evaluated through hydration expansion, hydration dispersion, and bentonite sheets immersion tests. The expansion height of bentonite in HGO (3.87 mm) was lower than that of commercial shale inhibitors potassium chloride (KCl, 4.64 mm) and polyether amine (PA, 4.33 mm). The shale recovery rate in HGO at 80 °C was 86.25 %, which was superior to KCl (46.60 %) and PA (78.25 %). Furthermore, the morphology of bentonite sheet remained more intact after immersion in HGO. Additionally, the inhibitory mechanism of HGO was studied in-depth, employing zeta potential, particle size, surface tension, wettability, capillary rise height, and scanning electron microscopy (SEM) tests. By virtue of electrostatic attraction, HGO could tightly adsorb to the shale surface, resulting in a hydrophobic blocking membrane, thereby greatly reducing water infiltration. Following interaction with shale at a concentration as low as 0.5 %, the water contact angle exhibited a notable enhancement, rising from 22.49° to 86.69°. And it could also decrease the capillary self-suction capacity of shale, further reducing water adsorption. Consequently, HGO exhibited significant potential for inhibiting hydration in shale drilling.

On the colloidal and filtration properties of a polymer-amended waste K+-rich bentonite for use as a low-density solid additive in water-based drilling fluids

On the colloidal and filtration properties of a polymer-amended waste K+-rich bentonite for use as a low-density solid additive in water-based drilling fluids

Experimental Investigation on the Effect of the Aphron Drilling Fluid in Mitigating Formation Damage of Dawood Bai-Hassan Reservoir

Drilling fluid is one of the crucial parts of the drilling operation and has a significant role in carrying rock cuttings to the surface, stabilizing the wall of the borehole and controlling formation pressure. Most of the depleted reservoirs drilled by water-based drilling fluid are subjected to high overbalance pressures due to the difference in density of drilling fluid compared with the formation fluid. This overbalance pressure creates the lost circulation of mud, pipes sticking and formation damage. Underbalanced drilling can be considered to eliminate the above-mentioned problems. However, it has safety issues and prohibitive in many depleted fields. This study focuses on the development of the Aphrons-based drilling fluid from adding two types of surfactants (City-Termidyl Ammonium Bromide (CTAB) as a stabilizer, and Sodium Dodecyl Benzene Sulfate ( SDBS) as a generator) and xanthan gum (XC) polymer to be used for drilling of Dawood Bai-Hassan Reservoir. (20) samples of Aphrons drilling fluids were formulated at different concentration of xanthan gum (0.2 and 0.4 wt.%), CTAB (0.2 and 0.4 wt.%) and SDBS (0.1 to 1 wt.%). All the developed drilling fluids subjected different experiments of rheological and filtration properties. The obtaining results show that better rheological behavior were obtained with adjusting the concentration of the used additives as 0.4 wt.% xanthan gum, 0.2 wt.% CTAB and 0.4 wt. SDBS when achieved and added to the base drilling fluid. The results showed that (XC) Polymer combination with surfactants (CTAB and SDBS) have a major effect on mud filtration at even under-surface conditions, where it was lowered by 47% at surface ( 20°C, 100 psi) and lowered by 41.67%, 50% at conditions 60 °C, 90 °C (600 psi) temperature respectively. In addition, for maintaining other mud properties such as viscosity, yield point, gel strength and cleaning capacity as well.

Improved Rheological Properties and Lubricity of Drilling Fluids at Extreme Temperatures and Pressures Using Graphene Oxide and Flowzan

Summary The use of graphene-based lubricants in water-based drilling fluids (WDFs) has emerged as a promising avenue for enhancing their tribological properties, particularly under high-temperature (HT) conditions, by incorporating inorganic-material-based additives. For this study, we used a green and adsorption-based approach to prepare highly-dispersed graphite for modification, utilizing a cationic surfactant. Our research demonstrated the effective dispersion of the prepared graphite in water, characterized by low sedimentation rates and small contact angles in distilled water. The concentration dosage of Flowzan® on graphite was determined to be 0.02 g/g. To assess the effectiveness of modified graphite as a lubricating additive in water-based drilling, we conducted rheological studies and measured viscosity coefficients. The results revealed a significant decrease in the viscosity coefficient of the drilling fluid by 68% at 300°F when incorporating 0.05% modified graphene. Furthermore, the study investigated the thickness of six WDFs under high-temperature, high-pressure (HTHP) conditions. The addition of 3% graphene expansion resulted in a notable reduction in the volume of HTHP liquid filtrate by up to 30% compared with the control. These experimental findings underscore the advantageous effects of nanoparticle addition on properties such as lubricity, rheology, fluid loss, and thermal stability, potentially revolutionizing the drilling process. In addition to evaluating the performance of modified graphite, we analyzed its primary, crystalline, and morphological properties using various techniques, including particle size tests, zeta potential tests, Fourier transform infrared (FTIR), powder X-ray diffraction (XRD), and scanning electron microscopy (SEM). These analyses elucidated the lubrication mechanism, demonstrating that graphite modification primarily occurred through physical adsorption without altering the crystal structure. These insights provide valuable guidance for the development of high-performance WDFs tailored to endure the challenges of drilling operations.

Effect of Olivine, Barite and Calcium Carbonate on Cutting Carrying Capacity of Water-Based Drilling Fluids

Introduction: In this study, the effect of different weighing material such as olivine, barite and calcium carbonate on cutting carrying of water-based drilling fluids was investigated. Initially, characterization studies were performed for the additive materials. Method: Then, spud type muds were prepared with bentonite and the weighing materials were added at different rates ranging from wt.1-6%. After the sample preparation, mud weight, 600 and 300 rpm dial reading, plastic viscosity, yield point, flow behavior index and power law consistency factor values were measured/calculated. Result: With these results, cutting carrying index of the muds was calculated and the effect of the additive materials was compared. According to the results, it was determined that the barite added muds had better cutting carrying capacity than others and the calcium carbonate added muds showed worse cutting carrying capacity. Optimal CCI results were obtained from O-5 as 3.7869 and, from B-6 as 5.9417 and from C-4 as 2.7113. Conclusion: Results of this study show that olivine can be used as low additive ratios in drilling muds to clean the hole.

Application of Nanofibrous Clay Minerals in Water-Based Drilling Fluids: Principles, Methods, and Challenges

Nanofibrous clay minerals, specifically palygorskite (Pal) and sepiolite (Sep), have been becoming a new generation of rheological additives for drilling fluid systems due to their unique nanostructure, high performance, environmentally benign nature, and cost-effectiveness. These nanoclay minerals exhibit excellent colloidal and rheological properties in aqueous systems, even in saline and high-temperature environments. Although Pal and Sep have been employed as auxiliary rheological additives in a few cases to enhance the salt resistance of conventional water-based drilling fluids (WBDFs), these two clay minerals have not yet been used on a large scale due to a lack of understanding of their structures and properties, as well as the control of their performance. This paper presents a comprehensive review of the clay mineralogy, colloidal chemistry, rheological behaviors, and filtration properties of nanofibrous clay minerals in WBDFs, with critical comments. It also discusses the challenges and prospects for further research. This review provides new insights into fundamental and applied studies of nanofibrous clay minerals and helps promote the large-scale application of nanofibrous clay products in drilling fluids.

Effect and consequence of the rheological properties of nano Fe2O3-modified drilling muds in the Dibella oil field

The development of supportable, cost-effective, and high-performance nanoparticles (NPs) is one of the new examination points within penetrating applications. The consideration of tailorable nanoparticles offers the chance to figure out water-based drilling fluids (WBDFs) with upgraded properties, providing exceptional opportunities in the energy, oil, gas, water, or framework enterprises. In WBDFs, nano and micron materials are investigated to control their rheological properties and their influence. This paper aims to analyze the influence of nano Fe2O3 on the rheological behavior of drilling fluid muds under high temperatures and pressure. Additionally, we seek to identify the optimal concentration of iron oxide nanoparticles that maintain consistent rheology; we examined the interfering effects of shear rates and iron oxide nanoparticle temperature on the shear type of the changed depleting liquid in the Dibella oil field to make the penetrating activity efficient, realistic, and skilled. We observe that as the temperature increases, the water-based mud (WBM), plastic viscosity (PV), yield point (YP), and gel strength (Gs) decrease until the reject structure is disrupted. Therefore, we must proceed with our assessment using nano Fe2O3 to resolve the shortcomings of the slope framework. Six water-based mud cakes containing 0.5, 1, 1.5, 2, 2.5, and 3 g weight percent of iron oxide (Fe2O3) nanoparticles were prepared for this evaluation. The experimental outcomes revealed an optimal nanoparticle mixing of 2.5 g weight percent, which resulted in a 13.8% reduction in the API filtrate volume and a 40% reduction in filter cake thickness. At 300°F temperature and type 10.00 pressure, the results of our experiments consistently demonstrate a decrease of 14.77% in the rheological properties of PV and YP and 10 s and 10 min in the gel strength of carbon oxide nanoparticles. The YP–PV span is 2.7, and the yield strength is 11 lb/100 ft2. On the other hand, mud cake A, which contains 0.5 wt% NPs, loses 6 mL of fluid after 30 min. In contrast, drilling mud cake E, which is composed of 3 wt% NPs, shows a fluid loss of 5.1 mL in the API filter press test. Based on the Bingham plastic model, the maximum shear stress versus shear rate was observed for bentonite drilling muds E and F, with 2.5 wt% and 3 wt% NPs, respectively, and this result indicates that the use of nano Fe2O3 can effectively adjust the properties of drilling fluids.

Maltodextrin polymer nanospheres as a filtrate reducer for filtration control in water-based drilling fluids

With the development of deep and ultra-deep wells, there is a need to enhance the rheological and filtration properties of water-based drilling fluids under high temperature and salinity conditions. In this study, maltodextrin polymer nanospheres (MDPN) were synthesized through cross-linking maltodextrin and methylene bisacrylamide (MBA) via inverse emulsion polymerization. Then, the polymer MDPN-DAN was synthesized via aqueous solution polymerization, using maltodextrin polymer nanospheres, N, N-dimethylacrylamide (DMAA), 2-acrylamide-2-methylpropanesulfonic acid (AMPS), and N-vinylpyrrolidone (NVP) as raw materials. Structural characterization confirmed the successful synthesis of the polymer MDPM-DAN, with a median particle size of 234.4 nm. Thermogravimetric analysis revealed a thermal decomposition temperature of 242 °C for MDPM-DAN. This polymer demonstrated excellent settling stability at 220 °C in high-temperature and weakly alkaline environments. Rheological assessments demonstrated a 754 % enhancement in the drilling fluid’s rheological properties when MDPM-DAN was added compared to the base mud. MDPM-DAN demonstrated significant reduction in filtration loss, with polymer mud aged at 220 °C showing only 5.6 mL of loss, and polymer mud aged at 220 °C with 15 wt% NaCl exhibiting 8.9 mL loss. The filtration loss reduction mechanism elucidated that MDPM-DAN could adsorb onto bentonite particles via hydrogen bonds, while nanoparticles filled the micropores of the filter cake, promoting the formation of a dense filter cake. Furthermore, plugging experiments showcased MDPM-DAN’s ability to block nano-pore throats, with the molecular chain’s amide groups reinforcing the plugging through hydrogen bonding with rocks, while bentonite coats the micro-pore throats.

Mechanistic Performance of Modified Carbon Nanotubes Stabilized in Water-Based Drilling Fluids for High-Temperature Applications

Mechanistic Performance of Modified Carbon Nanotubes Stabilized in Water-Based Drilling Fluids for High-Temperature Applications

Investigation on the plugging mechanism of nanocomposite polyacrylate copolymers in water-based drilling fluids: Experiments and applications

The plugging of nanopores and cracks in shale formation has become the critical technology that promotes the development of shale gas. Herein, nanocomposite polyacrylate (Poly-TALC) copolymers were successfully prepared by emulsion polymerization using butyl acrylate and triallyl isocyanurate as the raw material. Poly-TALC was characterized by fourier transform infrared spectroscopy (FTIR), laser light scattering particle size analysis, scanning electron microscope (SEM) and thermogravimetric analysis (TGA). The rheological properties and plugging performance of Poly-TALC were evaluated by a six-speed rotational viscometer, filter cake permeability test, core permeability test and pressure transfer experiment. Results revealed that Poly-TALC exhibited a particle size distribution ranging from 75.27 to 95.29 nm, while maintaining notable stability at 327.75 °C. Upon the addition of Poly-TALC to the drilling fluid, both the apparent viscosity and plastic viscosity insignificantly changes. At a Poly-TALC dosage of 1.0%, the filter cake's permeability was 1.2 × 10−5 μm2 with a plugging rate of 56.9%, while the permeability of the core was 1.2 × 10−6 μm2 with a plugging rate of 84.0%. The decrease in permeability was not significant beyond a Poly-TALC dosage of 1.0 wt%. Pressure transfer experiments demonstrate that Poly-TALC is able to form a multi-stage dense seal within the rock core, which can effectively prevent formation water from immersing into shale formation and improve shale wellbore stability.

-Effects and mechanisms of acrylamide-based polymer containing N-vinylpyrrolidone on drilling fluids at high temperature

The exploration of ultra-deep oil and gas presents higher temperature resistance requirements for water-based drilling fluids. However, the lack of temperature resistance mechanism of drilling fluid polymers limits the development of key materials and drilling fluids. In this paper, by comparing the preparation of acrylamide polymers for drilling fluids, the influence of cyclic monomer N-vinylpyrrolidone (NVP) on the properties of polymers for drilling fluids was investigated, and the mechanism of NVP was deeply discussed. The results show that the NVP-containing copolymer PAAN has superior viscosity enhancement and filtration control in high-temperature drilling fluids. This is mainly due to the fact that PAAN has a more stable and complex polymer chain structure than PAA, the polymer that does not contain NVP, and its thermal stability is improved by 18.6 % up to 268°C. At the same time, NVP provides more adsorption spots, and the high-temperature clay adsorption capacity of PAAN in drilling fluids is increased by more than 66.9 % compared with that of PAA, which improves clay hydration and promotes clay dispersion, and ultimately reduces filtration of drilling fluids and stabilizes drilling fluids at high temperatures by more than 23.7 %. The introduction of NVP and the in-depth analysis of its action mechanism supplemented the anti-temperature mechanism of drilling fluid polymers, aiming to support the research and development of ultra-deep drilling fluid technology.

Improving Shale Stability through the Utilization of Graphene Nanopowder and Modified Polymer-Based Silica Nanocomposite in Water-Based Drilling Fluids

Shale formations present significant challenges to traditional drilling fluids due to fluid infiltration, cuttings dispersion, and shale swelling, which can destabilize the wellbore. While oil-based drilling fluids (OBM) effectively address these concerns about their environmental impact, their cost limits their widespread use. Recently, nanomaterials (NPs) have emerged as a promising approach in drilling fluid technology, offering an innovative solution to improve the efficiency of water-based drilling fluids (WBDFs) in shale operations. This study evaluates the potential of utilizing modified silica nanocomposite and graphene nanopowder to formulate a nanoparticle-enhanced water-based drilling fluid (NP-WBDF). The main objective is to investigate the impact of these nanoparticle additives on the flow characteristics, filtration efficiency, and inhibition properties of the NP-WBDF. In this research, a silica nanocomposite was successfully synthesized using emulsion polymerization and analyzed using FTIR, PSD, and TEM techniques. Results showed that the silica nanocomposite exhibited a unimodal particle size distribution ranging from 38 nm to 164 nm, with an average particle size of approximately 72 nm. Shale samples before and after interaction with the graphene nanopowder WBDF and the silica nanocomposite WBDF were analyzed using scanning electron microscopy (SEM). The NP-WBM underwent evaluation through API filtration tests (LTLP), high-temperature/high-pressure (HTHP) filtration tests, and rheological measurements conducted with a conventional viscometer. Experimental results showed that the silica nanocomposite and the graphene nanopowder effectively bridged and sealed shale pore throats, demonstrating superior inhibition performance compared to conventional WBDF. Post adsorption, the shale surface exhibited increased hydrophobicity, contributing to enhanced stability. Overall, the silica nanocomposite and the graphene nanopowder positively impacted rheological performance and provided favorable filtration control in water-based drilling fluids.

Research on resin modified gelatin as environmental-friendly high temperature resistant wellbore stabilizer

In the development of deep shale oil and gas, the working temperature of the water-based drilling fluids is relatively high, which can cause wellbore instability due to the poor temperature resistance of the traditional environmental-friendly additives. To address this issue, this study presents a wellbore stabilizer called PMG, prepared by modifying gelatin (GT) with a resin synthesized by polyvinyl alcohol (PVA) and methacrylic acid (MA) through hydrothermal free radical polymerization, and it can withstand temperature up to 200 °C. The synthesis and thermal stability of PMG were confirmed by Fourier transform infrared spectroscopy (FT-IR) and thermogravimetric analysis (TGA). The wellbore stability performance of PMG was evaluated by linear swelling test, rolling recovery test, core immersion experiment and point load test and the wellbore stability mechanism was also investigated. The results reveal that the swelling height of sodium-based bentonite (Na-BT) in 2.0 % PMG solution at 150 °C is only 0.97 mm; the hot-rolling recovery rate in 2.0 % PMG solution at 200 °C is 72 %; the artificial core still maintains its original appearance after being immersed in 2.0 % PMG solution at 200 °C for 16 h, and the compressive strength increases by 12 %, effectively strengthening the wellbore. In addition, the EC50 value of PMG is > 106 mg/L, and the BOD5/CODcr value is 31 %, indicating that it is non-toxic and biodegradable. PMG has excellent wellbore stability performance, in addition to being able to adsorb on the surface of Na-BT by electrostatic action and hydrogen bonding, the PMG micelles that precipitated from the aqueous solution due to the breaking of hydrogen bonds in the molecular chain at high temperature also form a film on the clay surface, aggregating and cementing the clay particles together, further enhancing the wellbore stability.

Synthesis and characterization of natural rosin-modified silica nanocomposite and its green multifunctional applications for drilling fluid

The increasing energy demand and environmental pressure require the utilization of high-performance and eco-friendly drilling fluid materials for oil/gas exploration. Herein, a green nanocomposite involving the core structure of silica (SiO2), the resin shell structure of rosin dehydroabietic acid (DHAA) derivative [poly(DHAA-co-styrene) (PDS)], and the crown structure of hydrophilic layer [crosslinked poly(2-acrylamido-2-methyl-1-propanesulfonic acid-co-N, N-dimethylacrylamide) (CAD)] was prepared through semi-continuous emulsion polymerization and utilized as a high-performance and multifunctional additive for drilling fluid. The optimal composition of core, shell and crown was determined to be 0.3: 10: 2 in mass, and the DHAA component accounted for 50 wt% in the shell structure and the molar ratio of 2-acrylamido-2-methyl-1-propanesulfonic acid and N, N-dimethylacrylamide in the crown was 3:7. The core-shell-crown nanocomposite (SiO2-PDS-CAD) exhibited a well-organized multi-layered nanostructure with an effective encapsulation of PDS on nano-SiO2 and CAD on PDS, facilitating a uniform nano-dispersion of SiO2-PDS-CAD. The bulky copolymerized rosin-based segments coupled with nano-SiO2 resulted in high thermal stability of SiO2-PDS-CAD and broadened the softening point of raw rosin from 87°C to 141°C. Meanwhile, the environmental assessments of acute toxicity and biodegradability showed that SiO2-PDS-CAD was nontoxic and readily biodegradable, and the higher incorporation of rosin components enabled SiO2-PDS-CAD more biodegradable in contrast to the non-biodegradability of the analog without rosin. Moreover, SiO2-PDS-CAD showed versatile functions in bentonite-based drilling fluid by maintaining high yield points, lowering fluid loss and enhancing nano-porous plugging capacity (100–400 nm), especially at elevated temperatures (140–180°C). A maximum increment of 1200 % on yield point occurred after aging 170°C, and the highest improvement of approximately 72 %-75 % on fluid loss occurred at 150–180°C. It also could effectively inhibit clay swelling and decrease the lubrication coefficient. The enhancement mechanism was revealed to be the core-shell-crown synergistic effects, in which the hydrophilic crown contributed to the dispersion stability of SiO2-PDS-CAD and affinity with bentonite clay, and the rigid bridging of core and flexible deformation of rosin shell strengthened the interparticle interactions. The study highlighted a novel strategy for preparing high-value-added rosin-based biomass material for green multifunctional applications in water-based drilling fluids.

Enhancement of Rheological Properties of Nano-Fe2O3-Modified Drilling Fluids

Summary In this study, we explore the potential of using nanoparticles (NPs) to enhance the properties of water-based drilling fluids (WBDFs). Specifically, we investigate the effects of nano-Fe2O3 on the rheological behavior of drilling fluid muds under high-temperature and high-pressure (HTHP) conditions to determine the optimal concentration of Fe2O3 NPs to maintain consistent rheology and improve drilling fluid systems. Results show that as temperature increases, the rheological properties of water-based muds (WBMs) decrease, leading to compromised structural integrity. To address this issue, nano-Fe2O3 is introduced into the system. We prepared and evaluated six WBM formulations with varying weight percentages of Fe2O3 NPs, and found that an optimal NP concentration of 2.5 g wt% resulted in a 13.8% reduction in American Petroleum Institute (API) filtrate volume and a 40% reduction in filter-cake thickness. Under conditions of 300°F temperature and 10,000 psi pressure, consistent reductions were observed in the rheological properties of plastic viscosity (PV), yield point (YP), and gel strength with the addition of Fe2O3 NPs. The YP-PV span was measured at 2.7, and the yield strength was determined to be 11 lb/100 ft2. Regarding fluid loss, Drilling Mudcake A containing 0.5 wt% NPs experienced a loss of 6 mL of fluid after 30 minutes, whereas Mudcake E containing 3 wt% NPs exhibited a fluid loss of 5.1 mL in the API filter press test. According to the Bingham plastic model, Muds E and F, containing 2.5 wt% and 3 wt% NPs, respectively, displayed the maximum shear stress vs. shear rate. This highlights the efficacy of nano-Fe2O3 in adjusting the properties of drilling fluids, presenting opportunities for enhanced performance and efficiency in drilling operations.