Performance Of Drilling Fluids Research Articles

Influence of Perlite on the Stability of Filter Cake in Low-Density Drilling Fluids System

Enhancing drilling fluid performance in the oil and gas industry involves addressing various criteria across technical, environmental, and economic aspects. Consequently, this study encompassed several factors such as rheology, filtration, formation damage, and additives to design appropriate and cost-effective drilling fluid. The potential of perlite as an additive for low-density drilling was assessed in this work. A comprehensive laboratory experimental approach was applied to gain an in-depth understating of perlite's performance. The investigation included evaluating the rheological properties, filter cake quality, and characterizing filtration medium pore distribution. Additionally, sensitivity tests were also conducted to judge the effectiveness of perlite as a primary viscosifier and filtration agent. Through these tests, a holistic assessment of perlite's capabilities was achieved. The findings indicated that while perlite was not suitable for use as the primary viscosifier or as the main filtration agent, its use as a secondary agent exhibited a positive impact, particularly in reducing solid invasion by approximately 93%. The optimum perlite concentration was 3 lb./bbl., with good enhancements in filtration volume, filter cake thickness and porosity by 50%, 40%, and 14%, respectively. Additionally, employing a combined particle distribution approach for the calcite, rather than a singular grade, resulted in substantial improvements in the examined properties. The most notable improvement was observed in filter cake permeability, which decreased by nearly 93%. The other parameters were improved by 80% for filtration volume, 74% for filter cake thickness, and 24% for solid invasion. This work highlighted the usability of perlite in low-density mud and how it can improve the drilling fluid properties.

Preparation of Ultra-High Temperature Resistant Cyclodextrin-Based Filtration Loss Reducer for Water-Based Drilling Fluids.

In the development of ultra-deep wells, extremely high temperatures can lead to inefficiency of additives in drilling fluids. Hence, there is a need to prepare additives with a simple preparation process and good effects at ultra-high temperatures to ensure stable drilling fluid performance. In this study, a high temperature resistant filtration loss polymer (LY-2) was prepared using γ-methacryloyloxypropyltrimethoxysilane (KH570), N,N-dimethylallyl ammonium chloride (DMDAAC), sodium p-styrenesulfonate (SSS), and β-cyclodextrin (β-CD). The impact of the different monomer ratios on particle size, rheology, and filtration performance was systematically investigated. Infrared spectroscopy afforded the structural features. Thermogravimetric Analysis detected the temperature stability, and scanning electron microscopy characterized the polymer micromorphology. LY-2 was completely decomposed at a temperature above 600 °C. Experiments showed FLAPI of the drilling fluid containing 3% LY-2 aged at 260 °C/16 h was only 5.1 mL, which is 85.4% lower compared to the base fluid. This is attributed to the synergistic effect of the polymer adsorption through chemical action at high temperatures and the blocking effect of carbon nanoparticles on the filter cake released by cyclodextrin carbonization at high temperatures. Comparing LY-2 with commercial filter loss reducers shows that LY-2 has excellent temperature resistance, which exhibited five times higher filtration performance and relatively low cost, making it possible to be applied to ultra-high temperature drilling operations in an industrial scale-up.

The Application Potential of Artificial Intelligence and Numerical Simulation in the Research and Formulation Design of Drilling Fluid Gel Performance.

Drilling fluid is pivotal for efficient drilling. However, the gelation performance of drilling fluids is influenced by various complex factors, and traditional methods are inefficient and costly. Artificial intelligence and numerical simulation technologies have become transformative tools in various disciplines. This work reviews the application of four artificial intelligence techniques-expert systems, artificial neural networks (ANNs), support vector machines (SVMs), and genetic algorithms-and three numerical simulation techniques-computational fluid dynamics (CFD) simulations, molecular dynamics (MD) simulations, and Monte Carlo simulations-in drilling fluid design and performance optimization. It analyzes the current issues in these studies, pointing out that challenges in applying these two technologies to drilling fluid gelation performance research include difficulties in obtaining field data and overly idealized model assumptions. From the literature review, it can be estimated that 52.0% of the papers are related to ANNs. Leakage issues are the primary concern for practitioners studying drilling fluid gelation performance, accounting for over 17% of research in this area. Based on this, and in conjunction with the technical requirements of drilling fluids and the development needs of drilling intelligence theory, three development directions are proposed: (1) Emphasize feature engineering and data preprocessing to explore the application potential of interpretable artificial intelligence. (2) Establish channels for open access to data or large-scale oil and gas field databases. (3) Conduct in-depth numerical simulation research focusing on the microscopic details of the spatial network structure of drilling fluids, reducing or even eliminating data dependence.

Temperature-sensitive polymer grafted with nano-SiO2 improves sealing and inhibition performance of shale water-based drilling fluid

Drilling fluid loss is an important factor restricting oil and gas production. The development of pores and micro-fractures in shale formations is the main cause of drilling fluid loss. In this study, silane coupling agent modified nano-SiO2 was used as the rigid core, and N-isopropylacrylamide and 2-hydroxyethyl methacrylate were used as the flexible outer shell. The temperature-sensitive blocking agent PKSHN was synthesized by inverse microemulsion polymerization method. PKSHN was analyzed and tested through Fourier transform infrared spectroscopy, simultaneous thermal analysis, transmission electron microscopy, dynamic laser scattering and other methods. The results show that PKSHN can achieve a hydrophilic/hydrophobic transition under the response temperature, with a median particle size of 189.35 nm, which can form a hydrophobic layer on the shale surface and reduce fluid intrusion into the shale formation. This study tested the performance of three drilling fluids with different densities by adjusting the amount of weighting agent. The results showed that the high-temperature and high-pressure filter losses of the three different densities of drilling fluids were all less than 10 mL. The addition of PKSHN can effectively reduce fluid loss. The rolling recovery experiment and linear expansion experiment show that after aging for 16 h at 150 °C, the rolling recovery rate is above 90 % and the linear expansion rate is below 7 %, indicating that the addition of PKSHN can effectively control the hydration expansion of shale.

Effects of polymers with different anionic groups in drilling fluids and their properties of temperature and salt resistance

To investigate the performance characteristics of polymers with different functional groups in drilling fluid matrix (clay suspension), two anionic acrylamide-based polymers with molecular weights of approximately 1 million and the same monomer ratio, namelypoly(acrylamidoacrylate) (P(AM-AA)) and poly(acrylamidoallyl sulfonate) (P(AM-SAS)), were synthesized using a water-dispersion polymerization method. Using polyacrylamide (PAM) with the same molecular weight as a reference, thermogravimetric analysis, scanning electron microscopy, zeta potential analysis, particle size distribution test, and drilling fluid performance test were conducted to assess the thermal stability of the polymers as well as the microstructures and properties of the corresponding drilling fluids. The results demonstrated that both P(AM-AA) and P(AM-SAS) exhibited significant intercalation effects on clay in drilling fluids, leading to an increase in the zeta potential of clay particles and the formation of a bimodal particle size distribution. These polymers also effectively reduced filtration loss and altered the rheological properties of the drilling fluids. However, the influence of polymers on temperature and salt resistance did not conform to the traditional understanding that sulfonic acid groups offer better hydration and salt resistance compared to carboxyl groups. The performance characteristics of the polymers were influenced not only by their own structure, but also by the clay content, salt content, temperature in the drilling fluids. Specifically, in freshwater drilling fluids, P(AM-AA) exhibited a slightly lower but comparable reduction in filter loss compared to P(AM-SAS). Furthermore, P(AM-AA) was less affected by clay content than P(AM-SAS) and showed stronger filter loss reduction in brine drilling fluids with NaCl content ≤3 wt%, while exhibiting less sensitivity to variations in NaCl content. Conversely, P(AM-SAS) demonstrated stronger filter loss reduction and lower sensitivity to NaCl content in brine drilling fluids with NaCl content >3 wt%. The influence of high-temperature aging (120–180 °C) on filter loss reduction function was similar for both P(AM-AA) and P(AM-SAS). The rheology of the formulated drilling fluid was less sensitive to clay content when utilizing P(AM-AA) compared to P(AM-SAS). Moreover, the apparent viscosity of the drilling fluid with P(AM-AA) was more impacted by NaCl when the NaCl content was below 5 wt%, showing greater sensitivity than P(AM-SAS). However, there was no significant difference in rheological stability between P(AM-AA) and P(AM-SAS) under high-temperature aging conditions.

Thermo-thickening/amphoteric polymer nanocomposite incorporating vinyl-functionalized nano-silica as a viscosifier for high-salt and ultra-high temperature water-based drilling fluids

In the relentless extraction of oil and gas from deeper reservoirs, the harsh geological conditions pose significant rheological challenges for conventional polymer viscosifiers. Hence, the spotlight has turned to the unique potential of thermo-thickening polymers to enhance drilling fluid performance. In this study, a novel polymer nanocomposite (VMS-ATA) was designed to associate thermo-thickening responses, amphoteric characteristics, and vinyl-functionalized nano-silica (VMS) as nanofillers for the formation of a thermally stable polymer nanocomposite-bentonite hybrid system. VMS-ATA was prepared via in-situ polymerization under optimal synthetic conditions, and the unique chemical structure was analyzed using various techniques such as Fourier transform spectroscopy, proton nuclear magnetic resonance, elemental analysis, thermogravimetric analysis, X-ray spectroscopy, transmission electron microscopy, and scanning electron microscopy. The study systematically investigated the enhancement of in-situ covalent bonding characteristics of VMS on the thermo-thickening behavior of VMS-ATA, while comparing it with amine-nano-silica (AMS) incorporated in a polymer composite (AMS-CGBA). TGA analysis revealed that VMS-ATA exhibits excellent thermal stability compared to AMS-CGBA, attributed to the thermally stable VMS (370 °C) compared to AMS (355 °C). Interestingly, VMS-ATA displayed relatively stable and prolonged thermo-thickening responses (100–200 °C) owed to high thermal-induced activation responses above the lower critical solution temperature (LCST) in both salt-free and saturated salt contamination. The rheological results of VMS-ATA viscosity retention at 220 °C and 20 wt% NaCl, exceeded 60 %, which is twice that of AMS-CGBA-containing fluids. As demonstrated, VMS-ATA and AMS-CGBA exhibited similar macro-interactions with rigid imidazole and caprolactam rings, but significantly differed in their micro-interactions owed to in-situ covalent binding induced by VMS compared to hydrogen bonding in AMS. This breakthrough exhibited the potential of VMS nanofillers to effectively maintain thickening response by facilitating efficient heat distribution to minimize rapid viscosity decay and revolutionize the landscape of high-salt and high-temperature (HSHT) drilling applications.

Polymer-laponite composites as filtrate reducer for high temperature and salt resistant drilling fluid: Characterization and performance evaluation

In deep and ultra-deep well drilling, ultra-high temperatures and high salt lead to poor drilling fluid performance. In this study, N, N-dimethylacrylamide (DMAA), dimethyldiallylammonium chloride (DMDAAC), 2-acrylamido-2-methyl-1-propanesulfonic acid (AMPS), 4-acryloylmorpholine (ACMO) and modified laponite (m-LAP) were polymerized into polymer nanocomposites PDADA-LAP by free radical polymerization in aqueous solution. The structure of PDADA-LAP was characterized by FT-IR, 1H NMR and XPS. The microstructure of PDADA-LAP was characterized by TEM, SEM and EDS. The results showed that LAP improved the network structure of the polymer by hydrogen bonding and covalent bonding. The effect of temperature on the degradation of the polymer solution was investigated. The experiment showed that the degradation temperatures of the polymer was 220 °C. PDADA-LAP was used as a filtrate reducer in drilling fluids. The results showed that 3.0 wt% PDADA-LAP could improve the filtration performance of drilling fluids at high temperature of 220 °C and resist contamination with 20 wt% NaCl. The FLAPI and FLHTHP were 7.0 mL and 28.6 mL, respectively. PDADA-LAP is adsorbed on bentonite particles through hydrogen bonding and electrostatic interaction, which slows down the contamination of bentonite particles by NaCl and gives the drilling fluid a good effect to reduce fluid loss at high temperature and high salt.

Evaluating the Effect of Claytone-EM on the Performance of Oil-Based Drilling Fluids.

This study provides a detailed characterization and evaluation of Claytone-EM as a rheological additive to enhance the performance of oil-based drilling fluids (OBDFs) under high-pressure, high-temperature (HPHT) conditions. It also offers a comparative evaluation of the effectiveness of Claytone-EM with an existing organoclay, analyzing their mineral and chemical compositions, morphologies, and particle sizes. A series of experiments are performed to evaluate Claytone-EM's influence on crucial drilling mud properties, such as mud density, electrical stability, sagging tendency, rheology, viscoelastic properties, and filtration properties, to formulate a stable and high-performing OBDF. Results indicated that Claytone-EM had no significant impact on mud density but remarkably enhanced emulsion stability. Claytone-EM effectively mitigated sagging issues under both static and dynamic conditions, leading to improvements in the plastic viscosity (PV), yield point (YP), apparent viscosity (AV), and YP/PV ratio. The PV, YP, AV, and YP/PV ratios were improved by 11, 85, 28, and 66% increments, respectively, compared with those of the drilling fluid formulated with MC-TONE. The addition of Claytone-EM resulted in enhancing gel strength and improving the filtration properties of the drilling fluid. The filtration volume was reduced by 2% from 5.0 to 4.9 cm3, and the filter cake thickness had a 13% reduction from 2.60 to 2.26 mm. These findings highlight Claytone-EM as a valuable additive for enhancing OBDF performance, particularly under challenging HPHT conditions. Its ability to provide emulsion stability, reduce static and dynamic sag, and control filtration holds the potential to enhance drilling operations, minimize downtime, and bolster wellbore stability. This study acknowledges certain limitations, including its temperature range, which could benefit from exploration at extreme temperatures. Additionally, the absence of flow experiments limits a comprehensive understanding of sag effects, and further research and field-scale evaluations are recommended to validate and optimize the application of Claytone-EM in OBDFs.

Investigating the efficacy of novel organoclay as a rheological additive for enhancing the performance of oil-based drilling fluids

Oil-based drilling fluids (OBDFs) are extensively used in the drilling industry due to their superior performance in challenging drilling conditions. These fluids control wellbore stability, lubricate the drill bit, and transport drill cuttings to the surface. One important component of oil-based drilling fluids is the viscosifier, which provides rheological properties to enhance drilling operations. This study evaluates the effectiveness of Claytone-IMG 400, a novel rheological agent, in enhancing the performance of OBDFs under high-pressure and high-temperature (HPHT) conditions. A comparative analysis was conducted with a pre-existing organoclay (OC) to assess the improvements achieved by Claytone-IMG 400. The OCs were analyzed using X-ray diffraction (XRD), X-ray fluorescence (XRF), scanning electron microscopy (SEM), and particle size distribution (PSD) to identify their mineral and chemical compositions, morphologies, and particle sizes. The drilling fluid density, electrical stability, sagging tendency, rheological properties, viscoelastic properties, and filtration properties were studied to formulate a stable and high-performance drilling fluid. The results confirmed that the novel OC does not affect the drilling fluid density but enhances the emulsion stability with a 9% increment compared with the drilling fluid formulated with MC-TONE. The sagging experiments showed that Claytone-IMG 400 prevented the sagging issues in both static and dynamic conditions. Also, Claytone-IMG 400 improved the plastic viscosity (PV), yield point (YP), and apparent viscosity (AV). The PV, YP, and AV were improved by 30%, 38%, and 33% increments respectively compared with the drilling fluid formulated with MC-TONE. The YP/PV ratio increased with a 6% increment from 1.12 to 1.19. Moreover, the gel strength (GS) was significantly increased, and the filtration properties were enhanced. The filtration volume was reduced by 10% from 5.0 to 4.5 cm3, and the filter cake thickness had a 37.5% reduction from 2.60 to 1.89 mm. The novelty of this study is highlighted by the introduction and evaluation of Claytone-IMG 400 as a new rheological additive for safe, efficient, and cost-effective drilling operations. The results indicate that Claytone-IMG 400 significantly improves the stability and performance of OBDFs, thereby reducing wellbore instability and drilling-related problems.

Comparing the Tribological Performance of Water-Based and Oil-Based Drilling Fluids in Diamond–Rock Contacts

Oil-based drilling fluids are usually assumed to provide lower friction compared to their water-based alternatives. However, clear evidence for this has only been presented for steel–rock and steel–steel contacts, which are representative of the interface between the drillstring and the borehole or casing. Another crucial interface that needs to be lubricated during drilling is that between the cutter (usually diamond) and the rock. Here, we present pin-on-disc tribometer experiments that show higher boundary friction for n-hexadecane-lubricated diamond–granite contacts than air- and water-lubricated contacts. Using nonequilibrium molecular dynamics simulations of a single-crystal diamond tip sliding on α-quartz, we show the same trend as in the experiments of increasing friction in the order: water < air < n-hexadecane. Analysis of the simulation results suggests that the friction differences between these systems are due to two factors: (i) the indentation depth of the diamond tip into the α-quartz substrate and (ii) the amount of interfacial bonding. The n-hexadecane system had the highest indentation depth, followed by air, and finally water. This suggests that n-hexadecane molecules reduce the hardness of α-quartz surfaces compared to water. The amount of interfacial bonding between the tip and the substrate is greatest for the n-hexadecane system, followed by air and water. This is because water molecules passivate terminate potential reactive sites for interfacial bonds on α-quartz by forming surface hydroxyl groups. The rate of interfacial bond formation increases exponentially with normal stress for all the systems. For each system, the mean friction force increases linearly with the mean number of interfacial bonds formed. Our results suggest that the expected tribological benefits of oil-based drilling fluids are not necessarily realised for cutter–rock interfaces. Further experimental studies should be conducted with fully formulated drilling fluids to assess their tribological performance on a range of rock types.Graphical

Microwave-assisted synthesis of zinc oxide nanoflowers for improving the rheological and filtration performance of high-temperature water-based drilling fluids

Zinc Oxide (ZnO) nanostructures have proved useful across a wide range of applications like medical technology, electronics, sulfur removal as well as microbial growth control. In the petroleum industry, ZnO nanostructures have been widely researched for application in Drilling Fluids. ZnO has been previously reported to work excellently in enhancing the electrical and thermal properties of water-based drilling fluids (WBDFs). However, the role of morphological features of the nanostructures in influencing the properties of bentonite-laden WBDFs is less understood. In this work, ZnO nanostructures were synthesized under microwave irradiation which resulted in different shapes like rods and flowers. The effect of microwave power and time was observed with Field Emission Scanning Electron Microscopy (FE-SEM) and Dynamic Light Scattering (DLS), and a suitable synthesis criterion was selected for achieving the smallest complex ZnO nanoflowers. These nanoflowers were further characterized for functional group and structural identification. Bentonite/Polymer Nanofluids were prepared and tested for properties like rheology, API, and HPHT filtration before and after thermal aging at 150 °C. The results show ZnO nanoflowers in WBDFs have excellent filtration control ability with ∼56% reduction in HPHT filtrate volume and can impart a flat-line rheological profile. Also, the breaking of nanoflowers into smaller nanorods and some further textural changes is predicted to enhance the stability of the WBDFs due to better dispersion and compact mud cake formation. The study shows that the morphological features of metal oxide nanostructures can be controlled with microwave irradiation and play an effective role in controlling the properties of bentonite/polymer WBDFs.

Preparation and performance evaluation of PDDSA-MS composite as high temperature and high salinity filtration additive

Drilling operations in deep and ultra-deep wells encounter challenges arising from high temperature and saltwater intrusion, leading to reduced drilling efficiency and deteriorated performance of water-based drilling fluids. In order to alleviate the problem of increased filtration of drilling fluid under harsh environment, the composite (PDDSA-MS) was prepared by free radical polymerization using N, N-dimethyl acrylamide (DMAA), Dimethyl diallyl ammonium chloride (DMDAAC), Sodium styrene sulfonate (SSS), 2-acrylamido-2-methylpropanesulfonic acid (AMPS) and KH570 modified SiO2 as raw materials. This composite contained absorption groups, hydration groups, rigid groups and nanomaterials. Through rigorous performance evaluations, it was observed that the addition of 1 wt% composite to a fresh water drilling fluid, resulting in a remarkably low filtration of 8.8 mL after aging at 260 °C. Furthermore, when 3 wt% composite was added to the 15 wt% NaCl salt water drilling fluid, the filtration was 8 mL after aging at 220 °C. This was attributed to the particle size of the composite and its ability to maintain the dispersion stability of drilling fluid, decelerate bentonite agglomeration, and make the surface of the formed filter cake dense and smooth. These findings demonstrated the thermal stability exhibited by composite, offering an effective solution for drilling operations in deep and ultra-deep wells.

A simple photocatalytic assisted strategy by MIL-100 (Fe) for fabrication of polymer based on H-bonding as filtrate reducer to resist salt and temperature in ultra-deep wells

Improving the performance of water-based drilling fluids for high temperature, salt and calcium resistance in the exploration of deep and ultra-deep wells is a matter of great urgency. In this study, MIL-100 (Fe) nanosphere catalyst with regular shape, uniform size and good monodispersity is prepared ahead of time. XRD, SEM and BET tests indicates that the MIL-100 (Fe) owning large specific surface areas, adjustable pore sizes and high porosity can display to be a photocatalyst. Based on the excellent photocatalytic activity under visible light, a new one-pot method strategy was supposed to achieve the graft modification on N atom in acrylamide using aziridine, and obtained the multi-amine allyl monomer. Finally, the poly (AM/AMPS/PSMM) (PAAP) filtrate reducer with significant hydrogen bonding effect was successfully synthesized by free radical copolymerization with acrylamide (AM), 2-acrylamide-2-methylpropanesulfonic acid (AMPS) and the pre-synthesized multi-amine allyl monomer. Due to the three dimensional hydrogen bonding interaction and resulted supramolecular association structure, the PAAP-based drilling fluids exhibit outstanding rheological and filtration properties even after aging at high temperatures and high salinity. The filtration volume after aging at 180 °C for 16 h is only 6.0 mL, meanwhile, the 20 wt% NaCl and 1.5 wt% CaCl2 copolymer base slurry aged at 180 °C both show the satisfactory filtration loss and offering performance higher than commercial filtrate reducers. Specifically, after aging at 180 °C, the filtration losses of DSP-1/BM and DSP-2/BM were 19.8 and 37.2 mL with 20 wt% NaCl contamination, respectively, while the filtration loss of PAAP was only 10.8 mL. Even under both 1.5 wt% CaCl2 contamination and 180 °C aging, the filtration loss of PAAP was only 11.0 mL, whereas the filtration loss of DSP-1 and DSP-2 reached 26.0 and 20.0 mL. Finally, the filtration control mechanism of poly (AM/AMPS/PSMM) was proposed via XPS test, hydrogen bonding analysis, filter cake morphologies observation by SEM and particle size distribution measurement.

Oily bioorganoclays in drilling fluids: Micro and macroscopic properties

The application of organoclays as an additive to improve the performance of oil-based drilling fluids has long been a subject of research. In this work, montmorillonite containing zinc cations was modified by lecithin to synthesize organic montmorillonite (ZnOMt), which was then dispersed in vegetable and mineral oils for the preparation of oil-based drilling fluids. Their viscoelastic properties were evaluated and linked to ZnOMt microstructure information obtained by X-ray diffraction (XRD) and transmission electronic microscopy (TEM). The nature of the oil used and the heating temperature are key parameters influencing the performance of oil-based drilling fluid. The favorable properties of vegetable oil-based drilling fluids containing organoclays provide great potential for their application in drilling engineering.

A temperature-sensitive polymer with thinner effect as a rheology modifier in deepwater water-based drilling fluids

The special deepwater and deep well environment in the deepwater area of the ocean puts forward higher requirements on the temperature resistance and flat rheology performance of water-based drilling fluid. In this study, the flat rheology performance of water-based drilling fluids was improved by synthesizing a temperature-sensitive polymer with thinner effect as a rheology modifier (PVNA). PVNA was characterized by infrared spectroscopy, thermogravimetric, nuclear magnetic resonance hydrogen spectroscopy, X-ray photoelectron spectroscopy and liquid gel chromatography. The results of the evaluation experiments showed that PVNA in 4 wt% bentonite mud resisted temperature up to 180°C and had good compatibility. The slope of the viscosity-temperature curve of the 4 wt% bentonite mud after aging at 180 °C/16 h was reduced from 0.84 to 0.17 after the addition of PVNA, indicating that PVNA can substantially improve the flat rheology performance of the 4 wt% bentonite mud. Turbidity analysis, particle size analysis, thixotropy analysis and transmission electron microscopy analysized the temperature-sensitive effect of PVNA. Specifically, PVNA weakens the hydration layer on the surface of bentonite through its hydrophobic properties, reducing the low-temperature aggregation effect of bentonite, and avoiding low-temperature thickening of bentonite mud to a certain extent. At the same time, the temperature-sensitive effect of PVNA after warming brings stronger intermolecular binding, which improves the internal three-dimensional network strength of the bentonite dispersion system after warming. The two effects synergistically improved the flat rheology performance of the dispersion system. PVNA has good application prospects and can be used as a good reference for developing other rheology modifiers.

Development of a Low-Molecular-Weight Filtrate Reducer with High-Temperature Resistance for Drilling Fluid Gel System.

Currently, conventional polymeric filtrate reducers with high-temperature resistance for use in drilling fluids have high molecular weights, which greatly affects the rheological properties. Therefore, to address the challenges in regulating the rheology and filtration performance of high-density drilling fluids at high temperatures, it is essential to develop low-molecular-weight filtrate reducers with high-temperature resistance. In this study, a low-molecular-weight filtrate reducer with high-temperature resistance (LMF) was prepared via free radical polymerization from acrylamide and 2-acrylamido-2-methyl-1-propanesulfonic acid as monomers, tertiary dodecyl mercaptan as a chain transfer agent, and ammonium persulfate as the initiator. LMF was then characterized by infrared spectroscopy, thermogravimetric analysis, and gel permeation chromatography. The obtained filtrate reducer exhibits a weight-average molecular weight (Mw) of 3819 and an initial thermal decomposition temperature of 300.7 °C, indicating good thermal stability. The effects of LMF dosage, temperature, and NaCl dosage on the rheology and filtration performance of mud samples were also investigated, and the mechanism of action was revealed by zeta potential, particle size distribution, scanning electron microscopy, and adsorption measurements. The results reveal that LMF increases the mud sample viscosity and reduces its filtration. For example, the filtration of the mud sample with 2 wt% LMF was 7.2 mL, a reduction of 70% compared to that of a blank mud sample. Further, after aging at 210 °C for 16 h, the filtration of the same sample was 11.6 mL, and that of a mud sample with 2 wt% LMF and 35 wt% NaCl after aging at 180 °C for 16 h was 22 mL. Overall, we have reported a scheme to prepare a low-molecular-weight filtrate reducer with high-temperature resistance and superior filtrate-reducing effects, laying the foundation for the investigation and development of low-molecular-weight filtrate reducers.

Characterization and Performance Evaluation of Modified Apatite Ore as a New Acid-Soluble Weighting Agent for Drilling Fluids

Summary Drilling in oil and gas reservoir formations requires the solid weighting agent used in drilling fluids to have good acid solubility to facilitate plugging removal in subsequent operations. Limestone is the most commonly used acid-soluble weighting agent, but its low density and significant thickening effect lead to a low weighting limit. To achieve control of drilling fluid density, rheology, sag stability, and acid solubility, the feasibility of using apatite (AP) ore as an acid-soluble weighting agent for drilling fluids has been discussed after it was modified by the nitrogen-containing organic polybasic phosphonic acid sodium salt. The basic characteristics of AP and modified AP (MAP) were analyzed. After that, the rheological, filtration, and sag stability properties of MAP-weighted water-based drilling fluids with densities of 1.2 g/cm3 and 1.6 g/cm3 were evaluated, and acid solubility, filter-cake permeability, core permeability damage, and plugging removal tests by acid solutions were performed to evaluate the formation protection effect. The results show that the density of AP is 2.98 g/cm3, and the main component is hydroxyapatite. Its negative electricity and hydrophilicity were enhanced after surface modification, so its dispersion stability in water was enhanced, thereby improving the rheology, filtration, and sag stability properties of the MAP-weighted drilling fluid. The solubility of MAP in 10% HCl solution reached 90.13%, and the core contamination experiments show that after being soaked in HCl solution, the return permeability of contaminated cores reached higher than 90%, indicating that the MAP invading the core can be efficiently dissolved and removed in the acidic working fluids used in the subsequent completion and stimulation operations, thus effectively protecting the reservoir formation. The properties of MAP are superior to those of limestone, and it can be used as a new acid-soluble weighting agent for drilling fluids, considering both drilling fluid performance regulation and reservoir formation protection.

Effect of Low Gravity Solids on Weak Gel Structure and the Performance of Oil-Based Drilling Fluids.

Drilling cuttings from the rock formation generated during the drilling process are generally smashed to fine particles through hydraulic cutting and grinding using a drilling tool, and then are mixed with the drilling fluid during circulation. However, some of these particles are too small and light to be effectively removed from the drilling fluid via solids-control equipment. These small and light solids are referred to as low gravity solids (LGSs). This work aimed to investigate the effect of LGSs on the performance of oil-based drilling fluid (OBDF), such as the rheological properties, high-temperature and high-pressure filtration loss, emulsion stability, and filter cake quality. The results show that when the content of LGSs reached or even exceeded the solid capacity limit of the OBDF, the rheological parameters including the plastic viscosity, gel strength, and thixotropy of OBDF increased significantly. Furthermore, the filtration of OBDF increases, the filter cake becomes thicker, the friction resistance becomes larger, and the stability of emulsion of OBDF also decreases significantly when the concentration of LGSs reached the solid capacity limit of OBDF (6-9 wt% commonly). It was also found that LGSs with a smaller particle size had a more pronounced negative impact on the drilling fluid performance. This work provides guidance for understanding the impact mechanism of LGSs on drilling fluid performance and regulating the performance of OBDF.

Investigation of proteinaceous algal biomass as a drilling fluid component

This study represents the first investigation into the potential of Spirulina algae proteins as drilling fluid constituents to address the problems of the environmental impacts of the petroleum industry. Algae protein is a common waste product from many bioprocessing operations including biofuel production, so this work also presents a solution to a waste utilization problem for bioprocessing industries. As such, this technology could create an important coproduct for bioprocessing industries while providing more sustainable and environmentally-benign drilling fluids for the petroleum industry. Algae biomass was hypothesized to serve as a bentonite replacement or as an additive that could improve drilling fluid performance by reducing fluid loss via permeation, and/or improvement of lubricity via reduction in coefficient of friction. Measurements were taken in accordance with API RP 13B-1 using an OFITE viscometer, OFITE 4-Unit HTHP Filter Press, and OFITE extreme pressure and lubricity tester. The rheological tests include viscosity, yield stress, and gel strength. Key findings include a friction reduction of up to 27% and a standard fluid loss as low as 13.5 mL. The biomass was able to increase the viscosity of the drilling fluids and exhibited a shear-thinning rheology with yield points exceeding 40 lbf/ft2. The rheology was fitted to the Bingham plastic model and the Herschel-Bulkley model. These findings have potential impacts in the fields of petroleum, chemical, environmental, and material engineering. It is concluded that Spirulina biomass is a good potential additive for decreasing fluid loss and improving the lubricity of drilling fluids, but it will not suffice as a bentonite replacement.

Saikosaponin improves the anti-collapse performance of water-based drilling fluids for shale gas

Shale gas formations often exhibit well-wall instability during drilling, particularly when using water-based drilling fluids, due to the high water sensitivity of the rock and the propensity for fractures to collapse. In this paper, our study delved into the impacts of saikosaponins (SS) on enhancing the anti-collapse efficacy of water-based drilling fluids for shale gas. Our experimental findings revealed that the incorporation of 3% SS into the water-based drilling fluid led to a 71.7% reduction in bentonite swelling and a significant increase in shale rolling recovery to 98.9%. Furthermore, the water-based drilling fluid enhanced with SS could maintain a shale strength at 96.8% of its original value. Moreover, the inclusion of SS elevated the dynamic shear force of the drilling fluid, bolstered its chip-carrying capacity, and reduced its filtration loss. This is attributed to SS's ability to adhere to the shale surface via hydrogen bonding, resulting in the formation of a hydrophobic film that impedes water molecules from infiltrating the shale. Simultaneously, SS's unique multi-hydroxyl structure endowed it with robust adhesion, forming a reinforcing layer on the shale surface to fortify the wall of the well. Consequently, SS effectively heightens the anti-collapse capabilities of drilling fluids. Moreover, SS as a plant-extracted ingredient is environmentally friendly and holds immense promise for the eco-conscious advancement of shale gas.