Water-based Drilling Fluid System Research Articles

Investigation of Filtration and Shale Inhibition Characteristics of Chitosan-N-(2-hydroxyl)-propyl trimethylammonium Chloride as Drilling Fluid Additives.

Hydrated shale formations often lead to severe drilling problems and may lead to wellbore instability. These instabilities can result in issues such as bit balling, borehole collapse, formation damage, stuck pipe, and low drilling rates. Keeping these fundamental issues with drilling in shale formation in mind, this study is aimed at designing a water-based drilling fluid system for effective shale inhibition, ensuring enhanced wellbore stability and drilling efficiency. The designed mud system comprises a typical base fluid along with newly synthesized chitosan derivative chitosan-N-(2-hydroxyl)-propyl trimethylammonium chloride (HACC) as an additive. This additive was found to be soluble in water and conducive for shale inhibition. The derived product was characterized by field emission scanning electron microscopy, thermogravimetric analysis, and Fourier-transform infrared spectroscopy (FTIR). Various drilling fluid tests, including filtration and rheological experiments, were conducted to evaluate its proficiency as a drilling mud additive. The results showed improvement in rheological and filtration properties after hot rolling at 100 °C in comparison to a conventional shale inhibitor, polyethylenimine. As we increase the concentration of synthesized chitosan derivative from 0.3 to 1.5 w/v%, the filtration loss is reduced from 40% to 65% as compared to the base fluids. Shale recovery tests were also conducted using shale samples from an Indian field to assess its viability for field application. The addition of 0.3 to 1.5 w/v% chitosan derivative resulted in high shale recovery above 88% to 96% at 100 °C compared to polyethylenimine, which showed a change in recovery from 62% to 73%. HACC intercalates into clay platelets, reducing the interlayer spacing between particles and preventing clay from hydrating and swelling. This mechanism of inhibition is evaluated by X-ray diffraction, FTIR, and zeta potential analysis. This bolsters the hypothesis of using the synthesized chitosan derivative as a shale inhibitor.

Development of a dual-functional inhibitor for natural gas hydrates and construction of drilling fluid system

Throughout the 21st century, natural gas hydrates have emerged as a pivotal and promising clean energy resource with immense potential for commercial development. However, during shallow-water gas hydrate drilling in deep-sea areas, heat and mass transfer between the drilling fluid and the natural gas hydrate reservoir result in hydrate dissociation. As a result, the reservoir strength is weakened, wellbore instability occurs, and there is a high risk of well collapse. Additionally, the formation of secondary hydrates can cause blockages in drilling tools or pipelines, compromising drilling safety. In this study, acrylamide and dimethyl diallyl ammonium chloride were used as raw materials to successfully develop a dual-effect hydrate inhibitor named ADP. The results showed that a 1% ADP concentration increased the inhibition efficiency of hydrate dissociation by approximately 21.13%. Furthermore, core immersion and linear expansion experiments using a 1% ADP solution showed that after 24 h, the core maintained its structural integrity without experiencing collapse, and the linear expansion rate decreased to 1.5%. Building upon the HEM system, this research employed the developed dual-effect hydrate inhibitor as the core component and further optimized density, rheology, filtration loss, hydration expansion inhibition, and hydrate inhibition properties to construct a high-performance water-based drilling fluid system for strong hydrate inhibition. Performance evaluation of the HTX system demonstrated excellent rheological filtration, lubrication, plugging, hydration expansion inhibition, and hydrate inhibition properties. Additionally, predictive models for drilling fluid rheological parameters under different temperature conditions were established. The research outcomes presented in this paper hold significant practical value in addressing the wellbore stability issues encountered during the drilling process of gas hydrate reservoirs in deep-sea areas.

Colloidal Properties of Polymer Amended Cyprus Bentonite for Water-Based Drilling Fluid Applications

In this work, we investigate the capability of a waste bentonite from the Polycanthos quarry in Cyprus, as a low-density solid additive to create colloids that are used in water-based drilling fluid systems (WBF) in drilling operations. Repurposing waste bentonite aligns with environmental sustainability and when properly processed can serve as a cost-effective solution to achieve the desired colloidal properties for WBF. Samples were obtained from waste stockpiles and were mechanically processed to a size < 63 μm. The material was activated with soda ash via three different methods investigating optimum soda ash percentage and curing time. Standard tests were performed for the rheological behavior and filtration properties and the results indicated that the quality of the activated clay dispersions improved slightly but the desired colloidal properties were not obtained. This can be attributed to the K+-rich clay and non-clay impurities that are inherent in the material so further amendment with xanthan gum polymer was conducted, at various concentrations. Results of this work show that with minor polymer addition, the material under investigation reaches the desired colloidal properties and qualifies according to API standards for WBF. Exploiting local waste clay material in WBF application leads to the development and sustainability of local resources thus contributing to the circular economy principle.

Experimental Water Activity Suppression and Numerical Simulation of Shale Pore Blocking

The nanoscale pores in shale oil and gas are often filled with external nanomaterials to enhance wellbore stability and improve energy production. And there has been considerable research on discrete element blocking models and simulations related to nanoparticles. In this paper, the pressure transmission experimental platform is used to systematically study the influence law of different water activity salt solutions on shale permeability and borehole stability. In addition, the force model of the particles in the pore space is reconstructed to study the blocking law of the particle parameters and fluid physical properties on the shale pore space based on the discrete element hydrodynamic model. However, the migration and sealing patterns of nanomaterials in shale pores are unknown, as are the effects of changes in particle parameters on nanoscale sealing. The results show that: (1) The salt solution adopts a formate system, and the salt solution is most capable of blocking the pressure transmission in the shale pores when the water activity is 0.092. The drilling fluid does not easily penetrate into the shale pore space, and it is more capable of maintaining the stability of the shale wellbore. (2) For the physical blocking numerical simulation, the nanoparticle concentration is the most critical factor affecting the shale pore blocking efficiency. Particle size has a large impact on the blocking efficiency of shale pores. The particle diameter increases by 30% and the pore-blocking efficiency increases by 13% when the maximum particle size is smaller than the pore exit. (3) Particle density has a small effect on the final sealing effect of pore space. The pore-plugging efficiency is only increased by 4% as the particle density is increased by 60%. (4) Fluid viscosity has a significant effect on shale pore plugging. The increase in viscosity at a nanoparticle concentration of 1 wt% significantly improves the sealing effectiveness, specifically, the sealing efficiency of the 5 mPa-s nanoparticle solution is 16% higher than that of the 1 mPa-s nanoparticle solution. Finally, we present a technical basis for the selection of a water-based drilling fluid system for long horizontal shale gas drilling.

Micronized calcium carbonate to enhance water-based drilling fluid properties

Advanced drilling technique requires competent drilling fluids. This study tests micronized calcium carbonate (CaCO3) as a water-based drilling fluid (WBDF) additive. CaCO3 microparticles were extracted from Aruma formation outcrop and studied for structural, colloidal stability, morphology, and particle size distribution. WBDF systems were prepared with varying quantities of CaCO3 microparticles, including 0, 15, 30, and 45 lb/bbl, respectively. The addition of CaCO3 microparticles was investigated in terms of the rheological, high pressure-high temperature (HPHT) filtration, barite sagging, density, and pH. The results showed that CaCO3 microparticles are stable at a pH greater than 8. Moreover, fluid containing CaCO3 microparticles exhibited an enhancement in rheological properties. The yield point increased by 29%, 34%, and 37% for 15, 30, and 45 lb/bbl of CaCO3 respectively. In addition, the HPHT filtration also showed that CaCO3 has a significant improvement in both filtration loss and filter cake thickness. The filter cake thickness decreased by 17%, 40%, and 65% at 15, 30, and 45 lb/bbl of CaCO3 respectively. Static and dynamic sag maintained in a safe range at 30 lb/bbl of CaCO3 microparticles. This study showed that using CaCO3 microparticles along with conventional fluid additives improved the thermal stability and rheological properties of drilling fluid.

Applicability of sawdust as a green additive to improve the rheological and filtration properties of water-based drilling fluid: an experimental investigation

Drilling fluid is essential to oil and gas drilling operations due to its diverse functionality. But the most commonly used drilling fluid additives are hazardous chemicals and are not biodegradable. As a result, the demand for environment-friendly additives has been raised to replace the hazardous chemical additives. Considering the rising interest toward green additive, this study examined the applicability of sawdust to be used as a biodegradable drilling fluid additive to improve the rheological and filtration properties of water-based mud. Sawdust was chosen for this study because of its high cellulose content, widespread availability, and low cost. Following the guidelines set by the American Petroleum Institute (API), we carried out laboratory experiments that encompassed three distinct concentrations of sawdust: sample 1 (with 0.25% sawdust), sample 2 (with 0.50% sawdust), and sample 3 (with 0.75% sawdust). The concentrations of sawdust were measured as a weight percentage of the total volume of the base water. Concentrations above 0.75% led to gelation issues. Results showed minimal impact on mud weight at 0.25% sawdust, while 0.50 and 0.75% concentrations caused slight weight reduction due to foam development. Plastic viscosity increased by 28.5, 42.8, and 71.4% for sample 1, sample 2, and sample 3, respectively, compared to the base mud. Sawdust-containing mud exhibited desirable gel strength and shear-thinning behavior. Moreover, sawdust significantly improved filtration properties by reducing fluid loss and mud cake thickness. Sample 2 (0.5% sawdust) performed well in terms of filtration properties. Mud cake permeability followed the trend: kBM>k0.75%sawdust>k0.25%sawdust>k0.50%sawdust\\documentclass[12pt]{minimal} \\usepackage{amsmath} \\usepackage{wasysym} \\usepackage{amsfonts} \\usepackage{amssymb} \\usepackage{amsbsy} \\usepackage{mathrsfs} \\usepackage{upgreek} \\setlength{\\oddsidemargin}{-69pt} \\begin{document}$${k}_{\\mathrm{BM}}>{k}_{0.75\\% \\mathrm{sawdust}}>{k}_{0.25\\% \\mathrm{sawdust}}>{k}_{0.50\\% \\mathrm{sawdust}}$$\\end{document}. Based on promising laboratory performance, lower concentrations of sawdust are recommended as a cost-effective and eco-friendly additive to enhance rheological and filtration properties of water-based drilling fluid systems.

Synthesis and performance evaluation of a micron-size silica-reinforced polymer microsphere as a fluid loss agents

A silica-reinforced polymer microsphere was prepared by reverse suspension polymerization using acrylamide (AM), 2-acrylamido-2-methylpropane sulfonic acid (AMPS), and silica nanoparticles modified with methacryloyloxypropyltrimethoxysilane as a filtrate reductant resistant to high temperature and salt contamination. The filtration volume of American Petroleum Institute (API) sodium-based bentonite fluids was reduced by 63.5% after aging with the addition of 3.0 wt% M-SiO2/ZMD at 150 °C. M-SiO2/ZMD also exhibited significant salt resistance when compared to ZMD. The test results demonstrate that M-SiO2/ZMD exhibits excellent rheological and filtration properties even at elevated temperatures. A significant filtration reduction effect was also shown in the water-based drilling fluid system. The filtrate volumes before and after aging at 150 °C were 5.2 mL and 5 mL, respectively, when the addition amount was 1.0 wt%. Finally, the possible filtration loss reduction mechanisms involved in M-SiO2/ZMD are also discussed. This study provides a new heat- and salt-resistant fluid loss reduction material for water-based drilling fluids in oilfields, and provides theoretical support for its practical application.

Evaluation of the Xanthan Gum, Gum Acacia, and Their Graft Copolymers with Acrylamide as Low-Dosage Hydrate Inhibitors for Their Application in the Drilling of Gas Hydrate Reservoirs

Hydrate formation is a significant issue while drilling into deep-water reservoirs containing gas hydrates. They may form in the drilling fluid flowlines, wellbore annulus, and ram cavities of blowout preventers. The natural gums, i.e., xanthan gum (XG) and gum acacia (GA), and their two graft copolymers with acrylamide (AAm), i.e., XG-g-PAAm and GA-g-PAAm, have been synthesized and tested as low-dosage hydrate inhibitors using THF hydrate systems via temperature-augmented visual method. XG-g-PAAm and GA-g-PAAm have shown better inhibition efficiencies and higher induction times than XG and GA. All of these inhibitors are then tested as drilling fluid additives to the formulated water-based drilling fluid systems (WBDFs). The formulated WBDFs contained 0.4 w/v % of each carboxymethyl cellulose (CMC), polyanionic cellulose (PAC), and 5 w/v % of potassium chloride (KCl). The rheology of the formulated WBDFs has been tested at an ambient temperature (293 K) and low temperature (275 K). The rheological parameters of WBDFs obtained from the experiments are within permissible limits with an inhibitor concentration of 0.5 w/v %. The rheological data are then fitted to the Bingham–Plastic (B–P) model and Herschel–Bulkley (H–B) model. The coefficient of determination’s (R2) upper and lower limits for the B–P model is 0.9715–0.9969 for 0.5 w/v % GA- and 0.5 w/v % XG-g-PAAm-containing WBDF systems. Again, for the H–B model, the range for R2 is from 0.9891 to 0.9980 for 0.5 w/v % GA- and 0.5 w/v % XG-containing WBDFs. Hence, the R2 showed a better agreement with the H–B model than with the B–P model. These observations suggest that XG, GA, XG-g-PAAm, and GA-g-PAAm may be used as hydrate inhibitors in the formulated WBDFs while drilling into gas hydrate reservoirs.

Aqueous drilling fluids systems incorporated with green nanoparticles and industrial spent caustic: Optimum rheology and filtration loss properties

Drilling fluids are one of the most significant components of drilling operations for proper functions including fluid loss reduction into the formation and outstanding rheological properties. The drilling fluids according to environmental regulations and governmental rules have to be friendly to the environment to lessen the negative effects on the environment and improve safety. In the current study, a cost-effective industrial alkali waste (spent caustic) was used as a pH controller along with the environmentally friendly uncoated and Chitosan-coated green magnetite nanoparticles (MNPs) in water-based drilling fluid systems. The study focuses on exploring the impact of the alkali waste compared to the conventional alkali (NaOH) on rheology and filtration loss properties. The flow models of the drilling fluid systems were examined. The results proved that the drilling fluid formulated with polymer-coated green MNPs and waste alkali exhibited higher rheological properties and lower mud cake thickness and filtration volume compared to the reference fluid, thus, the waste alkali could replace NaOH as a pH controller. The flow behavior of new fluids could be described precisely using the Herschel-Bulkley flow model. Whereas, the Bingham plastic flow model described the fluid systems incorporated with uncoated and polymer-coated green NPs and NaOH.

Inhibition mechanism of cationic polyacrylamide on montmorillonite surface hydration: A molecular dynamics simulation study

Cationic polyacrylamide (CPAM), a typical drilling fluid shale inhibitor can prevent the clay swelling and maintain the wellbore stable. Understanding the adsorption behavior of CPAM on montmorillonite (MMT) surfaces is of great significance in explaining the excellent performance of cationic inhibitors. In this work, molecular dynamic simulations (MD) are applied to investigate the adsorption mechanism of CPAM on the Na-MMT surface. The simulation results show that there are two main adsorption configurations of CPAM: 1) trimethylamine group adsorption; 2) the co-adsorption of trimethylamine group and amide group, the latter has stronger interaction energy, also trimethylamine group accounted for a large proportion of the interaction energy. The CPAM coating will decrease the H-bond number, neutralize the negative charge of Na-MMT surface and weaken the surface hydration ability of Na-MMT. Due to the existence of the CPAM coating, the diffusion and transport ability of water molecules on Na-MMT surface are greatly reduced. This study provides a theoretical explanation for the coating-forming mechanism and adsorption characteristics of CPAM inhibitors on Na-MMT surfaces and may shed light on the design of high-performance water-based drilling fluid systems.

Optimization of High Temperature-Resistant Modified Starch Polyamine Anti-Collapse Water-Based Drilling Fluid System for Deep Shale Reservoir.

During drilling in deep shale gas reservoirs, drilling fluid losses, hole wall collapses, and additional problems occur frequently due to the development of natural fractures in the shale formation, resulting in a high number of engineering accidents such as drilling fluid leaks, sticking, mud packings, and buried drilling tools. Moreover, the horizontal section of horizontal well is long (about 1500 m), and the problems of friction, rock carrying, and reservoir pollution are extremely prominent. The performance of drilling fluids directly affects drilling efficiency, the rate of engineering accidents, and the reservoir protection effect. In order to overcome the problems of high filtration in deep shale formations, collapse of borehole walls, sticking of pipes, mud inclusions, etc., optimization studies of water-based drilling fluid systems have been conducted with the primary purpose of controlling the rheology and water loss of drilling fluid. The experimental evaluation of the adsorption characteristics of "KCl + polyamine" anti-collapse inhibitor on the surface of clay particles and its influence on the morphology of bentonite was carried out, and the mechanism of inhibiting clay mineral hydration expansion was discussed. The idea of controlling the rheology and water loss of drilling fluid with high temperature resistant modified starch and strengthening the inhibition performance of drilling fluid with "KCl + polyamine" was put forward, and a high temperature-resistant modified starch polyamine anti-sloughing drilling fluid system with stable performance and strong plugging and strong inhibition was optimized. The temperature resistance of the optimized water-based drilling fluid system can reach 180 °C. Applied to on-site drilling of deep shale gas horizontal wells, it effectively reduces the rate of complex accidents such as sticking, mud bagging, and reaming that occur when resistance is encountered during shale formation drilling. The time for a single well to trip when encountering resistance decreases from 2-3 d in the early stages to 3-10 h. The re-use rate of the second spudded slurry is 100 percent, significantly reducing the rate of complex drilling accidents and saving drilling costs. It firmly supports the optimal and rapid construction of deep shale gas horizontal wells.

Study of a High-Temperature and High-Density Water-Based Drilling Fluid System Based on Non-sulfonated Plant Polymers.

The environment-friendly water-based drilling fluid system developed for the petroleum development industry cannot successfully withstand temperatures up to 180 °C, and most high temperature-resistant additives with sulfonic acid groups that have been successfully applied to water-based drilling fluid are not good for environmental protection. In order to solve the above technical problems, a non-sulfonated filtrate reducer and viscosity reducer with resistance to high temperature were prepared by using humic acid, lignin and a multifunctional monomer as raw materials. In laboratory experiments, the molecular weights of the FLO-H filtrate reducer and the VR-H viscosity reducer were 5.45 × 105 g/mol and 8.51 × 103 g/mol, respectively, and all of them showed good high-temperature resistance. The API filtration loss of the bentonite-base slurry with 3.0 wt% FLO-H was only 6.2 mL, which indicated that FLO-H had a prominent reduction in filtration loss after aging at high temperature. When the dosage of VR-H was 1.0 wt%, the plastic viscosity of the water-based drilling fluid after aging at 200 °C decreased from 71 mPa·s to 55 mPa·s, which provided excellent dispersion and dilution. The high-temperature and high-density water-based drilling fluid containing the FLO-H filtrate reducer and the VR-H viscosity reducer had good suspension stability and low filtration performance at the high temperature of 200 °C, which can meet the requirements of high-temperature deep well drilling.

Smart Fluids and Their Applications in Drilling Fluids to Meet Drilling Technical Challenges

This article presents extensive analysis and review on recent developments in smart fluids as well as future opportunities of smart drilling fluids utilization in oil and gas well drilling while focusing on the following smart fluids: smart nanoparticles, electrorheological, magnetorheological, and viscoelastic surfactant (VES) fluids. The distinctive properties of nanoparticles such as tiny particle sizes, high specific surface area, mechanical strength, and thermal stability make them suitable for utilization in drilling fluids. In bentonite water-based drilling fluid systems, this review suggests that charged nanoparticles are capable of displacing exchangeable ions in between bentonite clay platelets, thereby forming intercalates which can interact with clay surfaces through electrostatic attraction or repulsion. In improving wellbore stability, it is presented in this review that nanoparticles are able to invade and plug ultratiny pore spaces in shale formations, thereby further enhancing shale formations’ mechanical strength and wellbore stability. According to this review, the magnitude of changes in properties of smart electrorheological and magnetorheological fluids largely depends on the intensity of applied electric and magnetic fields. The intensity of smart fluids properties alteration due to applied field would equally depend on wt.% concentration and chemical compositions of particles susceptible to electric and magnetic fields. Based on review carried out on VES smart fluids, attractive and repulsive forces in the smart VES fluids solution result in the formation of micelles which can cause changes in viscoelastic property of the formulated smart viscoelastic fluids. The more the concentration of charged ions in the base fluid which VES fluids come in contact with, the higher the viscoelasticity of the smart VES fluids. According to this review, utilization of smart materials in drilling fluids can result in meeting oil and gas well drilling technical challenges including enhancing wellbore stability, improving hole cleaning performance, lost circulation control, fluid loss control, enhancing rate of penetration, pressure drop control, and easing cutting carrying efficiency of drilling fluids. This review equally suggests that the utilization of smart fluids such as smart magnetorheological and electrorheological fluids would facilitate drilling automation and real-time data acquisition processes, which is the future technology in oil and gas drilling.

A Temperature-Sensitive Polymeric Rheology Modifier Used in Water-Based Drilling Fluid for Deepwater Drilling.

Rheology modifiers are essential for the flat rheology of water-based drilling fluids in deepwater. The low temperature thickening of deepwater water-based drilling fluids results in dramatic rheological changes in the 20–30 °C range. To address such problems, NIPAM with a self-polymerized product LCST of 32–35 °C was selected as the main body for synthesis. While introducing the hydrophilic monomer AM to enhance the thickening properties, the hydrophobic monomer BA was selected to reduce the LCST of the product. In this paper, a temperature-sensitive polymeric rheology modifier (PNBAM) was synthesized by emulsion polymerization using N-isopropyl acrylamide, acrylamide, and butyl acrylate as monomers. The PNBAM was characterized using infrared spectroscopy (FT-IR), thermogravimetric analysis (TGA), and nuclear magnetic resonance hydrogen spectroscopy (NMR). The rheological properties, temperature resistance, and salt resistance of PNBAM in the base fluid (BF) were tested. The performance of PNBAM in the drilling fluid system was also evaluated, and a water-based drilling fluid system of flat rheology for deepwater was formulated. The rheological modification mechanism of PNBAM was analyzed by turbidity analysis, particle size analysis, and zeta analysis. Experimental results show that PNBAM has good rheological properties. PNBAM is temperature resistant to 150 °C, salt-resistant to 30 wt%, and calcium resistant to 1.0 wt%. PNBAM also has good flat rheology characteristics in drilling fluid systems: AV4°C:AV25°C = 1.27, PV4°C:PV25°C = 1.19. Mechanistic analysis showed that the LCST (Lower Critical Solution Temperature) of 0.2 wt% PNBAM in an aqueous solution was 31 °C. Through changes in hydrogen bonding forces with water, PNBAM can regulate its hydrophilic and hydrophobic properties before and after LCST, which thus assists BF to achieve a flat rheological effect. In summary, the temperature-sensitive effect of PNBAM has the property of enhancing with increasing temperature. While the tackifying effect of conventional rheology modifiers diminishes with increasing temperature, the temperature-sensitive effect of PNBAM gives it an enhanced thickening effect with increasing temperature, making it a more novel rheology modifier compared to conventional treatment additives. After LCST, compared to conventional rheology modifiers (XC), PNBAM has a more pronounced thermo-thickening effect, improving the main rheological parameters of BF by more than 100% or even up to 200% (XC less than 50%). This contributes to the flat rheology of drilling fluids. PNBAM has good application prospects and serves as a good reference for the development of other rheology modifiers.

Water-based drilling fluid for ultra-long horizontal intervals in Changqing oil and gas field

In the past two years, several horizontal wells with ultra-long horizontal intervals were completed in Changqing oil and gas field. The longest horizon interval reached 4466 m, which set a record of the longest onshore horizontal well in Asia. There were a lot of difficulties such as high friction, mudstone collapse, and sand carrying that puzzled the drilling of wells with ultra-long horizontal intervals. To solve these problems, some key treatment agents were screened to form a novel water-based drilling fluid system (CQSP-RH). The yield point and extreme pressure lubrication coefficient of the novel system were 18 Pa and 0.058, respectively. The filtrate volume of the novel system was only 1.9 mL at room temperature and was 12 mL at 120 °C. When the cuttings were rolled for 16 h at 120 °C, the primary recovery of them could reach 98.64%. Subsequently, the novel system was applied to wells with ultra-long horizontal intervals. The friction resistance between drilling tools and sidewall was controlled within 500 KN; the solid contents of drilling fluid was controlled within 10%. The results proved that the novel system have superb properties and tremendous potential to drill deeper horizontal wells.

Study on a Polyamine-Based Anti-Collapse Drilling Fluid System

In complex strata, oil-based drilling fluid is the preferred drilling fluid system, but its preparation cost is high, and there are hidden safety risks. Therefore, the new progress of high-performance anti-collapse water-based drilling fluid at home and abroad is analyzed. It is difficult to prevent and control the well collapse. Once the well wall instability problem occurs, it will often bring huge economic losses to the enterprises, and the underground safety accidents will occur. In order to ensure the stability of the well wall and improve the downhole safety, the key treatment agent of water-based collapse drilling fluid is selected, the anti-collapse drilling fluid system is formulated, the evaluation method of drilling fluid prevention performance is established, and a set of water-based drilling fluid system suitable for easy to collapse strata in China is selected to ensure the downhole safety. The development trend of high performance anti-collapse water-based drilling fluid is expected to provide a reference for the research of high performance anti-collapse water-based drilling fluid system and key treatment agent.

Research and Application of Anti-Collapse Lubricant Compound Polyalcohol for Water-Based Drilling Fluid

Polyalcohol is an environmentally friendly anti-collapse lubricant commonly used in water-based drilling fluids. It is generally composed of the single polyether or polyol, but its lubricity and anti-collapse inhibition can’t satisfy the application of current water-based drilling fluid systems well. Consequently, the laboratory has carried out research on the anti-collapse lubricant compound polyalcohol. The anti-collapse lubricant samples are mixed with lauryl polyether, nonylphenol polyether and Tween 80 according to different proportions. The cloud point, the reduction rate of lubrication coefficient and linear expansion are measured, and the change they caused should be observed. Then, the optimal ratio is optimized through orthogonal experiments. The results show that the increase in the content of the three kinds of polyethers respectively enhances the inhibition. When the content of lauryl polyether increases, the cloud point of the anti-collapse lubricant declines and the reduction rate of lubrication coefficient rises; when the content of nonylphenol polyether increases, the cloud point declines, but it has little effect on the reduction rate of the lubrication coefficient; when the content of Tween 80 increases, the cloud point rises, and the reduction rate of the lubrication coefficient first augments and then basically remains unchanged. The best mass ratio of lauryl polyether:TW-80:nonylphenol polyether is 6:3:4.

Experimental evaluation of Sarcosine as an eco-friendly green hydrate inhibitor for the drilling of gas hydrate bearing formations

The hydrate inhibitors played a significant role in preventing hydrate formation in the drilling fluid systems. However, the disposal of these inhibitors was the primary concern for the drilling industries, as Thermodynamic Hydrate Inhibitors (THIs) are not eco-friendly, and Kinetic Hydrate Inhibitors (KHIs) are troublesome to dispose of due to their long polymeric structures. Hence, an attempt had been made to evaluate the Sarcosine, an amino acid, as a biodegradable, green hydrate inhibitor for water-based drilling fluid systems. Initial screening of Sarcosine in the THF-water hydrate (structure-II) system showed that it behaved as a zwitterionic, dual-function inhibitor. It had better inhibition characteristics in delaying induction time and improving rheological and filtration properties than PVCap and PVP while used in formulated mud compositions. The water-based mud used in this work was prepared by mixing carboxymethyl cellulose (CMC), polyanionic cellulose (PAC), xanthan gum (XG), and potassium chloride (KCl) with distilled water. For Sarcosine content water-based mud systems, coefficients of determination (R2) values were dependable, while low-temperature (2 C) rheological values were fitted in Herschel-Bulkley model. These experimental investigations showed that the Sarcosine might be used for the drilling of gas hydrate-bearing formations.

Study of a Polyamine Inhibitor Used for Shale Water-Based Drilling Fluid.

Here, we report a water-soluble shale inhibitor for inhibiting shale hydrate formation. The copolymer denoted as thermogravimetric analysis (TGA) was synthesized via triethanolamine, two maleic anhydrides, and glacial acetic acid. The infrared (IR) and gas chromatography (GC) results indicated that TGA is a low molecular weight polymer inhibitor (IR) and is the most commonly used method to identify compounds and molecular structures qualitatively. It is mainly used to study the molecular structure of organic substances and conduct qualitative and quantitative analyses of organic compounds. The main function of GC is for polymer molecular weight analysis. With the aid of shale rolling recovery experiments, particle size distribution experiments, triaxial stress experiment methods, bentonite slurry rate inhibition experiments, and thermogravimetric experiments to evaluate TGA inhibition characteristics, the inhibition effect of TGA is better than that of the traditional inorganic salt inhibitor KCl, polymer amine inhibitor UHIB, and organic cationic shale inhibitor NW-1. When the mass fraction is 0.2%, the cutting recovery rate increases from 18.3 to 94.1%. The compressive strength of the shale core after adding 1% TGA inhibitor is 177.9 MPa, which is close to the original core compressive strength of 186.5. The wet sodium montmorillonite crystal layer spacing after treatment with 0.5%, 1.5%, and 3% TGA aqueous solution is 1.38, 1.35, and 1.35 nm, respectively, and the sodium montmorillonite crystal layer spacing after diesel treatment is 1.34 nm, indicating that the inhibitory effect of TGA on sodium montmorillonite is equivalent to that of diesel and that TGA can effectively inhibit the hydration and dispersion of sodium montmorillonite. At the same time, the crystal layer spacing and the weight loss rate of sodium montmorillonite modified by TGA inhibitors did not change significantly after adsorption of deionized water, which proved that TGA inhibitors could be adsorbed in the crystal layer space of sodium montmorillonite to inhibit hydration and dispersion of sodium montmorillonite. Field test results show that TGA can significantly improve the inhibition performance of the field drilling fluid, and the effect is better than the strong conventional inhibition water-based drilling fluid system, which solves the problems of wellbore instability and considerable friction in horizontal shale sections and provides a new idea and method for efficient shale gas drilling.

Development and Application of a Novel Green Water-Based Drilling Fluid

In response to the technical and environmental protection requirements of water-based drilling fluids, this study independently developed a series of green supporting treatment agents for water-based drilling fluids such as the green loss reducer HB-1, green inhibitor HB-2, and green lubricant HB-3, etc., and proposed a green water-based drilling fluid system (HBDF) with good comprehensive performance. The proposed system has a heat resistance of 150°C, a HTHP (high temperature and high pressure) filtrate loss of 12 mL, a biological toxicity EC50 value greater than 105 mg/L, and a biodegradability BOD5/CODCr value of 16.2%. Now the developed HBDF system has been applied in more than 10 wells in SL oilfield, and the field application results show that the proposed HBDF system has stable rheological and filtrate loss performance, good anti-pollution ability, and easy and simple maintenance operations; after drilling, the biological toxicity of the drilling fluids can meet the environmental protection requirements, which has provided a technical reference for the research of green drilling fluids and the green development of SL Oilfield.