Search

Filtration control is important to ensure safe and high efficient drilling. The aim of the current research is to explore the feasibility of using basil seed powders (BSPs) to reduce filtration loss in water-based drilling fluid. The effect of BSP concentration, thermal aging temperature, inorganic salts (NaCl and CaCl2) on the filtration properties of bentonite/basil suspensions was investigated. The filtration control mechanism of BSP was probed via water absorbency test, zeta potential measurement, particle size distribution measurement, and filter cake morphologies observation by scanning electron microscope. The incorporation of BSPs into the bentonite suspension generated acceptable rheology below 1.0 w/v%. The BSPs exhibited effective filtration control after thermal aging at 120 °C, but less efficiency at 150 °C. After thermal aging at 120 °C, the bentonite suspension containing 1.0 w/v% BSPs could resist NaCl and CaCl2 pollution of 5.0 w/v% and 0.3 w/v% respectively. Besides general filtration control behaviors, the exceptional water retaining capability formed by numerous nanoscale 3D networks in the basil seed gum and considerable insoluble small particles in BSPs might further contribute to the filtration control. The excellent filtration properties bring basil seed a suitable and green candidate for the establishment of high-performance drilling fluids.

Summary Pore throat blockage due to fines migration during drilling and completion is one of the leading causes of damage to unconsolidated sandstone reservoirs. Therefore, it is necessary to explore an effective control method for fines migration. Five types of nanoparticles in suspension with aqueous NaCl solutions of six different ionic strengths were chosen. Their ability to control the migration of quartz and kaolinite fines in quartz sand as the porous medium is discussed in this work. Results show that nanoparticles can effectively adsorb and fix fines, thus successfully suppressing their migration. Among these nanoparticles, Al2O3 showed the best performance, and nanoparticle suspensions with higher ionic strengths were preferable. A surface element integration method was used to establish a mathematical model for calculating the interaction energy between the formation fines and the rock pore surface with adsorbed nanoparticles. Through atomic force microscopy and zeta potential measurements, the effect of nanoparticle adsorption on the heterogeneity of the pore surface was analyzed in terms of roughness and electrical properties. The interaction energy between the formation fines and the heterogeneous pore surface was calculated; it revealed the microscopic mechanism of how nanoparticles control fines migration. The results indicated that the nanoparticles form an adsorption layer, which enhances the physical and chemical heterogeneities of the pore surface and provides favorable conditions for the adsorption and fixation of fines. As a result, the interaction energy curves of the fines and the pore surface shift downward, and their repulsive barriers decrease or even disappear, exhibiting higher attractive potential energy. These variations promote adsorption and fixation of fines at the pore surface, as confirmed by the experimental results reported in this work, thus successfully preventing formation damage.

It is difficult to define safe drilling mud density window for shale sections. To solve this problem, the general Biot effective stress principle developed by Heidug and Wong was modified. The Weibull statistical model was used to characterize the hydration strain-related strength damage. Considering drilling fluid sealing barrier on shale, a calculation method of safe drilling mud density has been established for shale formation under drilling fluid sealing-inhibition-reverse osmosis effect, combined with a flow-diffusion coupling model. The influence of drilling fluid sealing and inhibiting parameters on safe drilling mud density window was analyzed. The study shows that enhancing drilling fluid sealing performance can reduce the pore pressure transmission and solute diffusion; the inhibiting performance of drilling fluid, especially inhibition to strength damage, is crucial for the wellbore collapse pressure of shale section with significant hydration property. The improvement of drilling fluid sealing and inhibition performance can lower collapse pressure and enhance fracturing pressure, and thus making the safe drilling fluid density window wider and the collapse period of wellbore longer. If there is osmosis flow in shale, induced osmosis flow can make the gap between collapse pressure and fracturing pressure wider, and the stronger the sealing ability of drilling fluid, the wider the gap will be. The safe drilling mud density window calculation method can analyze the relationships between collapse pressure, fracturing pressure and drilling fluid anti collapse performance, and can be used to optimize drilling fluid performance. Key words: shale, drilling fluid, collapse pressure, fracturing pressure, wellbore stability, safe mud density window, shale gas development

The injection of CO2 into deep coal beds can not only improve the recovery of CH4, but also contribute to the geological sequestration of CO2. The adsorption characteristics of coal determine the amount of the greenhouse gas that deep coal seams can store in place. Using self-developed adsorption facility of supercritical fluids, this paper studied the adsorption behavior of supercritical CO2 and CH4 on three types of coal (anthracite, bituminous coal A, bituminous coal B) under different temperatures of 35 °C, 45 °C and 55 °C. The influence of temperature, pressure, and coal rank on the Gibbs excess and absolute/real adsorption amount of supercritical CO2/CH4 on coal samples has been analyzed. Several traditional isotherm models are applied to interpret the experimental data and Langmuir related models are verified to provide good performances. However, these models are limited to isothermal conditions and are highly depended on extensive experiments. To overcome these deficiencies, one innovative adsorption model is proposed based on machine learning methods. This model is applied to the adsorption data of both this paper and four early publications. It was proved to be highly effective in predicting adsorption behavior of a certain type of coal. To further break the limit of coal type, the second optimization model is provided based on published data. Using the second model, one can predict the adsorption behavior of coal based on the fundamental physicochemical parameters of coal. Overall, working directly with the real data, the machine learning technique makes the unified adsorption model become possible, avoiding tedious theoretical assumptions, derivations and strong limitations of the traditional model.

As one of the most widely used preventive treatment of lost circulation, wellbore strengthening techniques need to be further investigated to improve its efficiency. It is crucial to accurately pre...

In recent years, developing high-performance shale inhibitors with excellent shale swelling and dispersion inhibition properties has attracted great interests in the drilling industry. 1-Octyl-3-methylimidazolium bromide (OMB), a common imidazolium-based ionic liquid, was introduced as a promising shale inhibitor. Shale hydration inhibition capacity was investigated via sodium bentonite (Na-BT) plate soaking test, linear swelling experiment and hot-rolling dispersion experiment. The inhibition mechanism was analyzed by Fourier transforms infrared spectroscopy (FT-IR) analysis, X-ray diffraction (XRD) analysis, thermogravimetric (TGA) analysis, contact angle test, zeta potential test and surface tension measurement. The results demonstrated the shale hydration inhibition property of OMB was obviously superior to other widely used shale inhibitors. OMB could be easily adsorbed onto sodium montmorillonite (MMT) through electrostatic interaction, and some interlayer water molecules were expelled due to its intercalation. Meanwhile, the surface of MMT became more hydrophobic after adsorbed by OMB, and an effective shield against water intrusion was formed. In addition, OMB could effectively reduce the surface tension even at low concentrations, and a lower capillary suction pressure could be beneficial for reducing fluid invasion. The results obtained from the work indicated that OMB had the potential to become a high-performance shale inhibitor for drilling shale formations.

Hydrate dissociation poses a significant problem during drilling operations in hydrate-bearing sediments. The drilling fluid is in direct contact with hydrates, and understanding its inhibitory effect on hydrate dissociation is important for stabilizing hydrates during drilling operations. In this work, an apparatus was designed for investigating hydrate dissociation in drilling fluids, and the effects of thermodynamic hydrate inhibitors (THIs), polyvinyl pyrrolidone (PVP), and soybean lecithin on hydrate dissociation were studied. The inhibitory effect of a water-based drilling fluid in the presence of the potential hydrate dissociation inhibitors was also studied. An unexpected inhibitory effect occurred with ethylene glycol (EG) at concentrations below 10 wt%, resulting from a range of factors including the dissociation driving force, and mass and heat transfers in the EG solution. PVP and lecithin reduced the hydrate dissociation rate and increased the time required for complete dissociation of hydrates. These can, therefore, be used in water-based drilling fluids to inhibit hydrate dissociation. A combination of 0.1 wt% PVP and 0.5 wt% lecithin was selected as an optimal hydrate dissociation inhibitor, considering its inhibitory effect and compatibility with the drilling fluid. Using EG at a concentration below 10 wt% as a THI instead of NaCl can also help inhibit hydrate dissociation. The findings of this work provide a basis for the development and design of drilling fluids for drilling in hydrate-bearing sediments.

Immense oil and gas reserves exist in the deepwater of the South China Sea, and the first priority for implementing successful drilling and completion operations without reservoir damage is to understand the damaging mechanisms to the reservoir formation. With the use of deepwater reservoir cores from the western South China Sea, the mineral composition, microstructure, porosity, and permeability characteristics of the reservoir formation were analyzed. With the use of core flow tests, potential fluid sensitivity was analyzed to determine how and which fluids can damage the reservoir formation during drilling and completion. The results show that the reservoir formation is composed of unconsolidated siltstone with a clay mineral content of 6–19%, and has high porosity and permeability with large pore throats. Sensitivity damage due to the increasing flow rate is strong, and an unusual salinity sensitivity exists with a critical salinity at 40,000–45,000 mg/L. Moderate alkali fluids sensitivity damage exists, with water sensitivity being weak. The main mechanisms of formation damage by drilling and completion fluids were analyzed as following: plugging of pore throats by solid invasion occurs because the sizes of the solid materials in the drilling fluids are just ideal for the formation of an external filter. Rock-fluid incompatibilities occur due to the increasing flow rate and salinity of the fluids because the formation rock is unconsolidated and the fines will easily detach and migrate, plugging the pore throats. Therefore, effective temporary plugging of the pore throats with a large diameter is important for protecting the reservoir. This study provides basic data for the design and implementation of reservoir protection measures in deepwater oil and gas exploration.

Formation damage is an inevitable problem during drilling in the sandstone gas reservoir. The invasion of drilling fluid could cause the decreasing of permeability of the formation and induce the reduction of gas production. In this paper, one kind of microemulsion is designed to improve the performance of drilling fluid in Sulige gas field, China. The fundamental chemical/physical properties and damage mechanism of targeted tight sandstone formation is analyzed using a combination of several experimental methods, including X-ray diffraction, scanning electron microscopy, core inhibition test, and etc. It shows that the formation rock is composed of medium to coarse particles and massive sensitive minerals, distributed with tiny connected pore throats. The rock has a high potential for water blocking damage and shows a medium to a strong performance of water sensitivity and stress sensitivity. Aiming to avoid these damages, one protective additive (microemulsion) is specifically designed. Through adsorption morphology test and core inhibition test, it shows that the newly developed microemulsion (0.5% concentration) could effectively weaken the inhibition effects induced by capillary pressure and decrease the flow back resistance of drilling fluid. Finally, a new drilling fluid using this new additive is designed and evaluated. The new drilling fluid works effectively in preventing water blocking by decreasing surface tension and transforming the wettability of tight sandstone from hydrophilic to intermediate wet. This contributes to the significant recovery of formation permeability (more than 92.1%) and the increasing of gas production.

Filtration control of drilling fluid plays an important role in the process of wellbore construction and ensures the success of drilling operation. A swellable polymer microsphere (SPM) of methylmethacrylate (MMA), butyl acrylate (BA), and lauryl methacrylate (LMA) was synthesized with suspension polymerization. Its swelling property was characterized by oil adsorption capacity measurement. First, the effect of SPM on the filtration and rheological properties of virgin organic clay dispersion was investigated. Then the filtration and rheological properties of mineral oil-based drilling fluid in the presence of SPM were elucidated under the respective conditions of hot aging temperature, oil to water ratio and density. Furthermore, the filtration control properties between SPM and two traditional filtration loss additives including modified lignite and asphaltic additive was compared. Addition of SPM exhibited obvious influence on the viscosity of oil-based drilling fluid especially at high concentration of 3 w/v%, therefore, a concentration of lower than 1.5 w/v% was recommended. After hot aging at 200 °C, the oil-based drilling fluid containing 1 w/v% SPM exhibited an API filtration loss decrease of 85%, and HTHP filtration loss decrease of 79% in comparison with the base fluid. After hot rolling at 180 °C, the API filtration loss decreased by 2%, 24% and 53%, and the HTHP filtration loss decreased by 42%, 54% and 65% respectively when 1 w/v% asphaltic additive, modified lignite and SPM are in the presence of the base fluid. Besides decreasing the filtration loss volume under high temperatures, incorporation of SPM also improves the filter cake quality of oil-based drilling fluid. SPM is capable of adsorbing considerable base oil and become swellable. The swellable polymer microspheres with favorably deformable and compressible properties can effectively fill the voids of filter cake and reduce the permeability, which leads to low filtration loss and minimization of solids invasion.

Owing to superior temperature stability in comparison with water-based drilling fluids, oil or synthetic-based drilling fluids are generally preferred for high temperature and high pressure (HTHP) formations. However, the thermal degradation of emulsifiers and polymeric components under HTHP conditions that results in loss of rheological and filtration control, barite sag or even fluid phase separation also occurs. It is a challenge to sustain these properties stable under such harsh condition. Since nanoparticles have potential to provide better thermal stability, improved filtration loss as well as emulsion stability, the aim of this study is to investigate the effect of nano carbon spheres on the properties of oil-based drilling fluids under high temperature conditions. The nano carbon spheres were synthesized with the hydrothermal reaction of glucose. The influence of nano carbon spheres on the rheological, filtration, emulsion stability, settlement stability, as well as lubricity of a typical mineral oil-based drilling fluid with oil to water ratio of 80:20 was investigated before and after thermal aging at 180 and 200°C, respectively. The structure characterization showed that the uniform hard nano carbon spheres exhibited intermediate wettability. Laboratory performance test indicated that, for the oil-based drilling fluid, the addition of nano carbon spheres improved the rheological properties in terms of yield point and the ratio of yield point to plastic viscosity, which is beneficial for transporting of drilling cuttings. After thermal aging at 200 °C, the filtration loss volume was reduced as high as 70%, and desirable filter cake quality was obtained by incorporation of 1.0 wt% spheres, meanwhile the electrical stability was improved both before and after thermal aging. Furthermore, the fluid formulated with the nano carbon spheres generated better barite sag control. The polarizing microscope observation showed that the nano carbon spheres accumulated at the water-oil interface and formed a steric barrier which probably explained the reason of the above enhanced performance. The green synthetic routes and environmental friendly characteristics of the nano carbon spheres, in combination with the excellent properties suggested that the nano carbon spheres hold potential as multi-functional additives for formulating oil-based drilling fluids for HTHP drilling operations.

The application of wellbore strengthening treatment has less effect on shale formations. Several numerical studies were developed to describe the mechanism, which promoted the development of wellbore strengthening theory. Previous studies explored the mechanism mainly by considering the seepage flow. Therefore, multi-field coupled models were established to analyze the solute transmission, thermal convection, and heat conduction on wellbore strengthening by introducing the theory of multi-field coupling into physical model. First, the fracture width distribution and wellbore tangential stress were investigated to research the interaction of thermal and chemical effects with different gradients. Then, the concrete mechanism of temperature and solute concentration gradient was analyzed based on the distribution of pore pressure and stress field. Results show that the prediction of hoop stress and fracture aperture may not be accurate without considering the influence of solute transfer, thermal convection, and heat conduction, because stress state is mainly affected by temperature field and the pore pressure varies greatly under different chemical gradients. Additionally, the lower temperature and larger solute concentration improve the wellbore strengthening effect of drilling fluid.

This paper is concerned with the formation of bitumen during the drilling of the H oilfield in Iraq. The high viscosity and strong adhesion properties of bitumen can influence the drilling operations. Some complex problems include paste screening, and drill pipe sticking, which cause huge economic losses. Therefore, it is necessary to effectively reduce the bitumen viscosity. The contribution of a single subcomponent of bitumen to the viscosity can vary, and the combined effect of different components of bitumen on the viscosity remains unclear. Furthermore, the mechanism of viscosity reduction remains unclear. In this study, the effects of organic solvents on the viscosity of bitumen were studied, and toluene was selected as the best organic solvent. The results showed that aromatics/resins, aromatics/asphaltenes, and resin/asphaltenes can help increase the bitumen viscosity. Novel methods, including the use of nanoparticles, ethyl cellulose, and the quaternary ammonium salt of heptadecenyl hydroxyethyl imidazoline (QASHI), were proposed to decrease the viscosity. TiO2 and CuO nanoparticles were chosen, and the main factors influencing the viscosity, such as the particle type, concentration, particle size, temperature, and shear rate, were analysed. The results show that the bitumen viscosity decreases with the increase in the concentrations of ethyl cellulose and QASHI. A synergistic effect between ethyl cellulose and QASHI was found with an optimal concentrations of ethyl cellulose and QASHI (1000 and 1600 mg L−1). A synergistic effect was also observed when nanoparticles, ethyl cellulose, and QASHI were used in combination. This paper reports the micro-mechanism whereby the viscosity of bitumen is decreased.

The injection of CO2 into deep coal seams can not only increase the recovery of CH4 but also contribute to the geological sequestration of CO2. In deep coal seams, CO2 can easily become the supercritical state when the pressure is over 7.38 MPa, and the temperature is over 31.04 °C. It can influence both the physical and chemical properties of coals, especially weakening the mechanical strength, which could compromise the long-term integrity and stability of the deep coal seams. Through acoustic emission experiment and triaxial compression experiment, the results show that after the treatment of supercritical CO2, the mechanical parameters of coals, including dynamic Young’s modulus, static Young’s modulus, rock cohesion, and peak strength, decrease significantly. It demonstrates that supercritical CO2 can reduce the mechanical strength of coals. This macroscopic phenomenon can be explained by the mechanism of the enlargement of microscopic pore spaces of coals, and this mechanism has not been studied thoroughly yet. Therefore, several microscopic quantitative experiments are comprehensively conducted, including scanning electron microscope (SEM), mercury injection porosimetry (MIP) and nuclear magnetic resonance (NMR). The results of these three tests are relatively consistent, and they show that after treatment of supercritical CO2, not only the diffusion space consisting of micropore and transitional pore but also the percolation space involving large pores and even cracks has been enlarged and expanded. This can be a significant underlying microscopic mechanism to effectively explain the weakening of the mechanical strength of coals. The pore space enlargement, together with the swelling of coal matrix, and the theoretical explanation of fracture mechanics and thermodynamic theory are all underlying mechanisms to explain the weakening behavior of coals influenced by the supercritical CO2.

In order to solve wellbore instability problems in the drilling process, high-performance shale stabilizers in water-based drilling fluids are essential. In this paper, a novel shale stabilizer based on polyethylene glycol grafted nano-silica composite (PEG-NS) was successfully synthesized. Conventional techniques were used to characterize PEG-NS including Flourier transform infrared spectroscopy (FT-IR), scanning electron microscope (SEM), transmission electron microscopy (TEM), particle size distribution (PSD) and thermogravimetric analysis (TGA). The results showed that the structure of PEG-NS was in agreement with the design objective. The particle size of PEG-NS ranged from 110 to 434 nm, and PEG-NS had good thermal stability. Pressure transmission test, pore structure characterization of shale, rolling recovery test were applied to evaluate the comprehensive performance of PEG-NS as a novel shale stabilizer. The experimental data indicated that PEG-NS could effectively retard the pore pressure transmission and reduce the permeability of shale sample. PEG-NS could adsorb onto the shale surface and a dense plugging film could finally coat on it. Moreover, PEG-NS also exhibited better inhibition performance compared with that of potassium chloride (KCl) and polymeric alcohol (JHC) at the same concentration. Hence, PEG-NS could be a good shale stabilizer in water-based drilling fluids for drilling reactive shale formations.

To convert the hazardous and waste oil sludge into shale stabilizer using in drilling fluid, a novel preparing method has been proposed in the current study. According to the characteristics of oil sludge, the preparation procedure was designed learning from conventional asphaltic-type shale stabilizer preparation method. Several additives such as gilsonite, calcium carbonate, surfactants (hexadecyltrimethylammonium chloride (CTAC) and polyoxyethylene octylphenol ether (OP-10)), polymers (polyethylene glycol (PEG-2000) and cationic polyacrylamide (CPAM)), and fluid loss reducers (sulfonated lignite and potassium humate) were incorporated into oil sludge with the assistance of melting, stirring, kneading, and drying. After the sequential steps of asphaltization, emulsification, and stabilization, a powdered shale stabilizer product (SS-OS) was obtained. The effect of SS-OS on rheology, filtration, and lubricity of drilling fluid bentonite dispersions was tested. Furthermore, the properties of stabilizing shale were evaluated. The results indicated that SS-OS could effectively inhibit shale swelling, dispersion, and exhibit excellent sealing performance. Moreover, it helped to reduce the fluid loss and significantly improve the lubricity of the drilling fluid. From the preliminary study, it was concluded that the strategy of preparing shale stabilizer with oil sludge could be employed to overcome waste, energy and environmental problems simultaneously and show promising application.

Interest in using nanomaterials to improve shale stability during drilling operations has been increasing. Herein, a polymer microsphere emulsion (PME) as a high-performance shale stabilizer for water-based drilling fluids (WDFs) was prepared via emulsion polymerization. The particle sizes in PME in aqueous solution ranged from 90 to 320 nm. PME was found to exhibit excellent salt tolerance and temperature resistance. The plugging performance of PME was tested through pressure transmission tests. The results indicated that the polymer microspheres in PME could effectively plug shale pores and reduce shale permeability. In addition, rolling recovery tests were used to evaluate the shale hydration inhibition performance of PME. It was found that PME showed great performance for decreasing shale hydration potential. These factors make PME a promising shale stabilizer for WDFs used to drill shale formations.

The surface hydration of shale has severe effect on the wellbore stability during drilling through the shale formation. In this paper, a novel method was developed to measure wettability of shale power by determining real contact angle. A variety of methods including measurements of Zeta potential, uniaxial compressive strength, shale stability indexes, surface hydration water, linear swelling, and cuttings hot-rolling dispersion experiment were used to evaluate the inhibition of surfactants. Meanwhile, Fourier transform infrared spectroscopy (FT-IR), and X-ray diffraction analysis (XRD) were used to investigate the interaction between surfactants and shale particles. Results revealed that the surface hydration of shale could be inhibited by using suitable surfactants. The surfactants compound of PA and THAO possessed stronger surface hydrating inhibition and capacity of restraining osmotic hydration. This is because the compound can enhance the surface hydrophobicity after adsorption onto the surface of shale particles, restrained osmotic hydration through swapping out inorganic cations in the clay interlayer, thus reducing the zeta potential and bounding clay gall together.

The principle of damage mechanics was adopted in order to solve the lost circulation problem when drilled low bearing capacity formation. According to quadratic nominal stress criterion and B-K criterion, cohesive element with zero thickness was inserted into fracture to simulate fracture initiation and propagation. A 3D fluid-solid coupling finite element model was established to analyze circumferential stress distribution of wellbore, hoop stress distribution of crack and geometry of fracture. Results show that closed fracture surface is still in the stage of complete fracture under the action of crustal stress and crack tip reopens after plugging particle failed. The fracture is difficult to widen for filling more plugging materials in a short time while the lost circulation rate and permeability are low. The wellbore strengthening treatment will makes the fracture become short and narrow under a larger filtration coefficient, but mud cake quality has an insignificant influence on fracture geometry when filtration coefficient increases to a certain value. The simulation results were supported by providing some cases of real wellbore condition.

In deepwater oil and gas drilling, water-based drilling fluids (WBDFs) apparently thicken at a low temperature (usually 4 °C), causing lost circulation, high flow resistance, and leakage of drilling fluid from the shaking screen. In this study, the rheological properties of aqueous suspensions containing different components were tested from 4 to 75 °C. Furthermore, the influencing mechanism of a low temperature on the rheology of WBDFs was comprehensively analyzed, and a basic method for controlling low-temperature rheology was proposed. The results showed that all the aqueous suspensions exhibited thickening at a low temperature. The thickening of WBDF at a low temperature could be attributed to the intrinsic feature of water, edge-to-edge and edge-to-face attraction bond structures formed by clay particles, and remarkable polymer molecular entanglement. The development of a rheology modifier that increases the rheology at a high temperature while does not work at a low temperature, optimization of the solid components including bentonites and weight materials, rational design of the molecular structure of polymers, and selection of the additives that do not cause remarkable thickening can help to control the low-temperature rheology of WBDF. Based on this method, a thermosensitive copolymer rheological modifier and a low-molecular-weight coating agent were developed, and two high performance WBDFs were optimized. Their rheological properties were found to be more stable than those of the three typical WBDFs over a wide temperature range from 4 to 75 °C. Therefore, the rheology control method proposed in this study can help to design a WBDF with good low-temperature rheology.

In this paper, a novel hydrophobic modified polymer based silica nanocomposite (NFC) was successfully prepared by emulsion polymerization and it was characterized by FTIR, PSD, TEM and TGA analysis. The results indicated that NFC possessed uni-modal distribution from 38 nm to 164 nm with the D50 value of about 72 nm and had good thermal stability. A variety of methods including the contact angle measurement, pressure transmission test, hot-rolling cuttings dispersion test and compatible test were adopted to evaluate the comprehensive effect of NFC on shale stability. And the shale cores before and after interacting with NFC were also characterized by scanning electron microscope (SEM) analysis. The experimental investigations revealed that NFC could effectively retard the pore pressure transmission and internally bridge and seal the pore-throats of shale. And it also exhibited preferable shale inhibition performance compared with KCl and JHC at the same concentration. After adsorption, the shale surface was more hydrophobic, which was more advantageous to shale stability. Furthermore, the compatibility test results confirmed that NFC had no negative effect on rheological performance and possessed a positive influence on filtration control performance of water-based drilling fluids.

In this paper, a novel poly(styrene/n-butyl acrylate/acrylic acid) latex (SDNL) for water-based drilling fluids was successfully prepared and characterized. Emulsion polymerization was used to prepare the polymer latex (SDNL), which was characterized by transmission electron microscopy (TEM), particle size distribution (PSD) and thermal gravimetric analysis (TGA). Firstly, its effect on the rheological and filtration control performance of drilling fluids was analyzed through the compatible test. Secondly, its inhibition performance was observed with the linear swelling test, and the shale cuttings hot-rolling dispersion test. Then, its sealing performance was investigated through the pressure transmission test. Finally, its effect on the lubrication performance was revealed by measuring lubrication coefficients of the drilling fluids. The results indicated that the particle size distribution of the spherical polymer latex nanoparticles ranged from 50 nm to 190 nm with the D50 value of around 88 nm. SDNL could significantly improve the rheological performance and enhance the shear thinning property of the drilling fluids. SDNL had favorable filtration control performance and good temperature resistance at 120 °C. The inhibition performance test demonstrated that SDNL had excellent ability to inhibit shale hydration swelling and dispersion. At the concentration of 2%, the linear expansion rate of the shale sample was only 4.9%, and the recovery rate was 93.7%. The pressure transmission test revealed that SDNL had outstanding sealing performance. A dense plugging film could form on the shale surface, the permeability of which was almost zero, and the pore pressure was difficult to continually transmit. Furthermore, the lubrication performance results confirmed that SDNL had good lubrication performance. After adding 2.0 w/v% of SDNL into the drilling fluids, the lubrication coefficient was reduced as high as 64.4%. The newly developed polymer latex SDNL is expected to be a superior additive in water-based drilling fluids for drilling troublesome shale formations.

Since 2007, heterogeneous, high-viscosity active bituminous formations have often occurred during the drilling process in Yadavaran oilfield (Iran), Halfaya oilfield (Iraq), and tar sands (Canada). The formation of bitumen exhibits plastic and creep properties, and its adhesion is strong, so drilling accidents are easily caused, such as adhering vibrating screen, drill pipe sticking, lost circulation, and even well abandonment. These complex problems cause huge economic losses. Solvents used to dissolve bitumen are a feasible technology to remove bitumen effectively. In order to solve this problem, we used crude bitumen samples from Halfaya oilfield to study the relation between the bitumen component and different solvents. In this study, the temperature, crude bitumen sample to solvent ratio, stirring rate, stirring time, and ultrasound time on bitumen recovery by toluene were investigated by a single factor experiment. The optimum process parameter for bitumen recovery was obtained. Toluene, n-heptane, tetrahydrofuran, cyclohexane, cyclopentane, ethyl acetate, and n-pentane were chosen as the solvents for single solvent extraction and composite solvent extraction. The bitumen recovery increased significantly with the use of a composite solvent compared to a single solvent. The composite solvent ratio was 1:1. The highest bitumen recovery was 98.9 wt% by toluene/cyclohexane composite solvent. The SARA (saturates, aromatics, resins, and asphaltenes) components of the bitumen were analyzed. The toluene showed the highest asphaltene content, while the n-alkanes showed the lowest asphaltene content. The higher the asphaltene content, the higher the bitumen recovery. The composite solvent obtained the highest asphaltene content and bitumen recovery. The viscosity of bitumen extraction by different solvents was measured. The lower the bitumen viscosity, the higher the bitumen recovery. The element analysis indicated the solvent&rsquo, s ability to extract bitumen colloids with the C/H ratio. This study provides a reliable theoretical basis for the subsequent adoption of effective anti-bitumen polluted drilling fluid additives.

With the promotion of oil and gas development around the world, the exploration scope has been gradually extended to complicated geological reservoirs, such as deep or ultra-deep, unconventional, deep-water reservoirs, and lost circulation and wellbore instability have been becoming the most serious problems, which puts forward higher requirements on the drilling fluid technology. In order to solve these technical problems, the wellbore strengthening mechanism, tight fracture plugging methods and simulation experimental method for drilling fluids were studied respectively in this paper. Firstly, the wellbore strengthening mechanism of the stress cage method that improves wellbore pressure containment was firstly investigated based on ABAQUS finite element modeling analysis. It was found that wellbore pressure containment could be improved by enhancing plugging performance of drilling fluids to plug and prop natural or induced fractures to eliminate fracture propagation and increase hoop stress. The key performance of loss prevention materials has been proved to play a prominent role to achieve wellbore strengthening effect and strengthen the wellbore. According to the basic principle of "force-chain" in granular matter mechanics, the key fine technical indices were proposed to evaluate the particle strength, particle resiliency and surface friction of loss prevention materials. Meanwhile, the corresponding physical model of tight fracture plugging zones was established to reveal the tight fracture plugging mechanism at micro scale and the optimization method of tight plugging drilling fluids was also put forward, and it was concluded that using reasonable particle type, particle size distribution and concentration control, rigid particles, resilient particles and fibers were synergized to plug fractures, so as to form tight pressure containment plugging zones with a strong force chain network and greatly improve the wellbore pressure containment. The novel experimental apparatus for evaluation and dynamic simulation on the plugging characteristics of drilling fluids was developed, which could simulate the loss and plugging process of fractures with different openings under different formation pressures and temperatures. Using this novel experimental apparatus, the strengthened tight plugging formulas were also optimized for drilling fluid at the wedge fractures with different widths, which exhibited tight plugging characteristic self-adapting to different openings with pressure resistance up to 8MPa, thus improving loss-prevention ability of drilling fluid and significantly enhancing wellbore pressure containment of subsurface formation.

Lubricants used in the Water based mud (WBM) can solve the high torque and drag problems encountered in extended reach drilling operations. The fast development in the deep & ultra-deep drilling technology puts forward higher requirements for the anti-temperature performance of WBM lubricants which beyond the ability of the commercial lubricants. How to fulfill the gradually restrictive environmental regulations and lower the total cost has already been a tough task for the drilling fluid designers. In this paper, a novel lubricant SDL-1 as synergistic application of optimized waste by-product vegetable oil MVO-3 and expandable graphite GIC was described. The physicochemical properties of MVO-3 and GIC were analyzed separately. In order to form a stable synergetic system, the type and amounts of the dispersants and emulsifiers were optimized. Then technological development process of lubricant SDL-1 was introduced in details. And comprehensive evaluations of SDL-1 were conducted according to corresponding technical standards and the synergistic mechanism of it was revealed. Development of the novel lubricant as synergistic application of waste by-product vegetable oil and expandable graphite affords a hopeful solution to solve the high torque and drag problems during drilling process. The substantial reduction in drilling costs with valuable application prospect makes the new developed lubricant more attractive. Furthermore, further benefits could appear in the economic development of relevant industries as the locally waste by-product vegetable oil was used in developing the novel lubricant.

The increase in the pressure bearing capacity is critical for mitigation of lost circulation, and to do so the strength of the plugging zone should be increased via picking an effective evaluation method and choosing the proper particle size distribution (PSD). Therefore, in order to successfully investigate this process, the traditional evaluation device of lost circulation should be improved for dynamic variation of fracture width to find the optimized plugging materials. This means, a new testing apparatus device capable of testing dynamic fracture width should be developed. Additionally, commonly used selection criteria of PSD are incapable of providing us with a continuous PSD curve since they only fulfill discrete PSDs. To overcome these two obstacles, a variety of continuous PSD models based on a new testing device and method are examined. Likewise, the impact of governing parameters and an optimized PSD selection criterion were studied with a specific lost circulation material (calcium carbonate) and concentration in a water-based drilling fluid. The experimental results demonstrate that the normal distribution model provides the best selection result while the sensitive analysis indicate that the factors influencing pressure bearing capacity in a sequential order are: minimum particle size, standard deviation, maximum particle size and average value. Besides, the optimized experiments illustrated that the maximum particle size should be 1.3 times of the maximum fracture width and the minimum particle size should be 0.8 times of the average fracture width. Moreover, the average value should be equal to the optimal particle average size and the standard deviation should be 0.3 times of the particle average size. It was found that the optimized selection method results in the highest plugging efficiency compared to conventional selection criteria. Collectively, the new device and optimal assessing approach would improve the prediction accuracy of pressure bearing capacity to select an appropriate PSD with varying of fracture width in field operations.

With increasingly stringent environmental regulations, an environmentally friendly and high performance filtration loss reducer for water-based drilling fluid is essential. This study aims to investigate the potential of utilizing starch nanospheres (SNSs) in this capacity. SNSs were fabricated by a crosslinking reaction between soluble starch and methylene-bis-acrylamide (MBA) using an inverse emulsion polymerization. The structure of SNSs was characterized with Fourier transform infrared (FT-IR), X-ray diffraction (XRD), scanning electron microscopy (SEM), particle size distribution measurement and thermogravimetric analysis (TGA). The effect of SNSs on the rheological and filtration properties of bentonite-based drilling fluid was investigated according to American Petroleum Institute (API) standards. Three-dimensional nearly spherical particles about 100–300 nm with smooth surface were formed after the inverse emulsion polymerization. SNSs had little influence on the rheological properties of bentonite-based drilling fluids. After subjected to thermal aging at 150 °C, SNSs still exhibited stable and effective filtration control. Viscosity and filtration loss were lower as well, and the performance after aging was better than currently used modified starch filtration reducers that were tested. The nano particles readily plugging micropores of filter cake and water absorbency ability as well as deformability and elasticity resulted in the effective filtration control. SNS has the potential to be used as biodegradable filtration loss reducer in elevated temperature formations replacing commercially available starch derivatives.

API bentonite, a key ingredient of drilling muds, displayed a negative zeta potential across the whole pH range of 2.5–12.3. It contained two very rheological active ingredients, sodium montmorillonite or Na+Mt (40.4%) and needle-shape sepiolite (16%). Due to the interplay of these two ingredients, the rheological behaviour displayed by the API bentonite suspensions is quite different to other bentonite suspensions. The gel displayed a very low or no yield stress at low acidic pH and a maximum yield stress at pH 8–12. Magnesium leaching from sepiolite at low pH and its hydrolysis plays a role in affecting the rheological properties at high pH. Yield stress and ageing behaviour was observed in suspensions with at least 3 wt% solids. The Herschel-Bulkley (HB) model described the flow behaviour of these gels. Both the HB yield stress and viscosity at a fixed shear rate of the 7 wt% gel peaked at pH 8.5 and were smallest at pH 5.2. The ageing or structural recovery behaviour is most pronounced at high pH for the most concentrated gels. Both the Leong and Nguyen-Boger ageing models described the structural recovery behaviour well. The recovery of the recently discovered very open honeycomb structure formed by Na+MT gel, after breakdown by shear was invoked to explain the ageing behaviour.

Wellbore instability due to shale hydration and dispersion is always a challenge in oil and gas drilling engineering. Hydroxyl-terminated polyamidoamine (PAMAM-OH) dendrimers were probed as potential shale inhibitors for the first time. The inhibitive potential of candidate PAMAM-OH dendrimers was screened with particle size distribution test, bentonite inhibition test, and cuttings dispersion test. In order to reveal the underlying inhibitive mechanism, the interaction between the dendrimers and sodium bentonite (Na-Bent) was characterized using X-ray diffraction analysis, zeta potential measurement, and thermal gravimetric analysis. The results indicated that PAMAM-OH dendrimers could intercalate into bentonite particles. The intercalation can form in mono or bilayer arrangement. The deformation of bentonite increased with the intercalated number of layers and affected by the phase variety and the change in adsorbed concentration. When adopting monolayer adsorption in the interlayer, the dendrimers exhibited effective inhibition performance, while the bilayer adsorption corresponded to decreased inhibitive performance. Marked improvement in shale inhibition was realized when a routinely used shale inhibitor KCl and PAMAM-OH were combined. A stable monolayer intercalation of dendrimers was observed in the presence of KCl, suggesting a synergetic effect between PAMAM-OH dendrimers and KCl.

Polyamine (PA) is a novel inhibitor applied to water-based drilling fluid in order to reduce clay hydration. In this paper, water adsorption behavior on kaolinite and illite after PA adsorption (PA-kaolinite, PA-illite) was characterized by X-ray diffraction (XRD), diffuse reflectance infrared Fourier transform spectroscopy (DRIFT), and adsorption isotherms tests using water, benzene, and heptane. After PA adsorption, water adsorption on kaolinite was enhanced while water adsorption on illite was reduced. Water vapor adsorption affinity on kaolinite in an entire range was significantly increased due to H-bonds between the ammonium groups of PA and water molecules. As a result, kaolinite surface tension was increased. Water adsorption affinity on illite in the low relative humidity (RH) regimes was decreased after PA adsorption and illite surface tension decreased because fewer water molecules could adsorb on tetrahedral (SiO 4 ) of illite. Therefore, PA can be used as inhibitor while drilling shale formations mainly composed of illite, not kaolinite.

In order to develop high-performance water-based drilling fluid with the aim of meeting the increasing requirement of drilling industry, highly inhibitive and high-temperature-resistant shale inhibitors are essential. In this study, 4, 4′-methylenebis-cyclohexanamine was introduced as a potential shale inhibitor. The inhibitive properties of the amine compound in comparison with currently available polyether diamine inhibitor were evaluated using bentonite inhibition test, shale cuttings hot-rolling dispersion test, linear swelling test, and pressure transmission test. The inhibitive mechanism was investigated with zeta potential measurement, X-ray diffraction analysis, and contact angle measurement. The results indicated that 4, 4′-methylenebis-cyclohexanamine can inhibit shale hydration and dispersion effectively, and prevent pressure transmission to a certain extent, performing better than that of polyether diamine. Furthermore, the new diamine provides reliable thermal stability as high as 220 °C, preserving the benefits of high-temperature wells application. This novel diamine inhibits shale hydration and dispersion with the combination of chemical inhibition and physical plugging. The intercalation into the interlayer of clay with monolayer collapses the hydrated clay structure and expels the water molecules. After adsorption, clay surface became more hydrophobic, which prevents the imbibition of water. The variation of solubility separates the compound from the solution, which can plug the micro-pores of shale and prevent fluid invasion.

To meet the requirements of leakage stopping and reservoir protection at the same time in fractured formation, the removable plugging slurries with high temperature tolerance were designed, evaluated and applied in the field successfully. Analysis shows that the fibre materials can deposit onto crack surface, bridge and seal fractures quickly and the selected particles can bridge in throat near wellbore. The comprehensive grading of filling particles was determined from the point of view of gradient filling. The designed plugging slurries KJD155 and KJD200 with higher total dissolution rates sealed 1 mm, 2 mm, 3 mm, and 4 mm crack blocks effectively at room temperature and high temperature (KJD155 at 155 °C; KJD200 at 200 °C) respectively. Their pressure bearing ability of them was up to 5 MPa under bottom hole conditions, which was beneficial to the next operation. Field application of the designed plugging slurries was carried out successfully and showed that they were removable and did smaller damage to reservoir.

Dendrimers have been paid increasing attention in the area of drilling fluid recently due to their unique structure and properties. The inhibitive properties of amine terminated polyamidoamine (PAMAM) dendrimers ranging from G0 to G5 were evaluated by relative inhibition rate, shale cuttings hot-rolling dispersion test and particle size distribution measurement respectively. Meanwhile the inhibitive capacity of the polymers under various pH value conditions was studied. The interaction between sodium bentonite and PAMAM dendrimers was characterized by zeta potential measurement and X-ray diffraction (XRD). The results indicated that, G0 and G5 are superior to polyether diamine, while G1, G2, G3 and G4 perform better than KCl. PAMAM dendrimers from G0 to G5 can decrease the zeta potential of clay particles from −39 mV to about −22.6 mV at natural pH values and reverse the charge when the pH value is adjusted to 9. When intercalated into the clay interlayer in aqueous solution, the candidate PAMAM dendrimers can form monolayer arrangement at lower concentrations and reduce the interlayer spacing of hydrated clay from 1.95 nm to 1.38–1.63 nm, which is the direct evidence of inhibiting shale hydration. With the increase of concentration, mixed phase and bilayer orientation are formed in the interlayer. The multi-terminal amine groups of dendrimers can effectively bind the adjacent layers together with electrostatic attraction and hydrogen bonding, and expel the water molecules out of the interlayer, contributing to the suppression of clay swelling and dispersion. The pH value reduction of aqueous solution improves the protonation of terminal-amine group, which can intensify the interaction between the polymers and clay, inducing the decrease of hydrated interlayer spacing and the zeta potential of clay particles, thus enhancing the inhibitive properties.

A bentonite-free water-based drilling fluid (BFDF) with high-temperature tolerance (up to 200°C) was developed for protecting reservoirs in deep wells. The fluid is composed of heatresistant polymeric thickener and starch, sodium sulfite, etc. A series of methods including environmental scanning electron microscopy (ESEM), linear expansion and hot-rolling dispersion test, and core-flow experiments and measurements of the rheological parameter, filtrate, and biotoxicity were used to evaluate the performance of the BFDF formulation. Laboratory results indicate that the fluid has excellent high-temperature tolerance. Its yield point and plastic viscosity ratio is up to 0.38 even after aging at 200°C for 16 h with API filtrate of 9.8 mL. Its apparent viscosity, plastic viscosity, and yield point at 180°C are 30 mPa·s, 17 mPa·s, and 14.5 Pa, respectively, which show its good well-cutting carrying performance and wellbore purification capacity. The BFDF formulation exhibits a strong ability to restrain the linear expansion rate of bentonite and shale powder, to improve cutting recovery, to protect the well reservoir by cutting down water blocking and lowering permeability damage, and to minimize biotoxicity with a high EC50 value and is suitable for drilling deep wells in environmentally sensitive areas.

Controlling the filtration of water-based drilling fluid effectively in high temperature environment is a great challenge in drilling engineering. In this study, β-cyclodextrin polymer microspheres (β-CDPMs) were synthesized by crosslinking between β-cyclodextrin and epichlorohydrin via inverse emulsion polymerization and employed as filtration reducers. The standard American Petroleum Institute filtration test showed that the β-CDPMs can only perform the enhanced filtration control ability at temperatures above 160 °C, and can tolerate the temperature resistance up to 240 °C without significant influence of rheology. As the thermal aging temperature is above 160 °C, numerous nano carbon spheres and nanostructured composites generated due to the occurrence of hydrothermal reaction. These high temperature stable nanoparticles bridged across the nano sized gaps and participated into forming dense filter cake, contributing to excellent filtration control. The filtration control mechanism proposed in this study opened a novel avenue for high temperature filtration control in water-based drilling fluids.

Shale hydration and dispersion leading to wellbore instability is always a challenge in oil and gas drilling engineering. In this study, specifically designed nano-particles by grafting hyperbranched polyethyleneimine (Mw = 600) onto the surface of nano-silica particles were synthesized. The modified nano-particles were characterized with Fourier transform infrared spectrum (FT-IR), particles size distribution measurement, thermal gravimetric analysis (TGA), transmission electron microscope (TEM) and zeta potential measurement. The results indicated that after modification, the nano-particles became positively charged and showed better dispersion in water compared to pristine nano-silica particles. Shale cuttings hot-rolling dispersion test and linear swelling test as chemical inhibitive tests in combination with pressure transmission test and shale sample spontaneous imbibition test as physical plugging tests were used to evaluate the shale stabilizing performance of the modified nano-particles. The results showed that the modified nano-particles exhibited both effective chemical inhibition and physical plugging, whereas nano-silica only showed limited physical plugging. The interaction between modified nano-silica particles and shale demonstrated that the grafted hyperbranched polymer strongly adsorbed onto the clay surface via electrostatic interaction and hydrogen bonding, which resulted in effective inhibition of shale hydration and swelling. After adsorption, the modified nano-silica particles were trapped on the micropores of shale formation and prevented the fluid invasion. The dual functions of the modified nano-silica particles demonstrated a remarkable improvement of shale stability.

As one of the most common drilling problems, lost circulation causes severe economic losses. However, the commonly used experimental testing apparatuses and methods are inadequate to evaluate the dynamic sealing capacity of lost circulation process, which neglect the dynamic variation of fracture width. Thus, a lost circulation testing device containing dynamic fracture aperture was developed, which could be used to investigate the influence of lost circulation material (LCM) features, fracture geometry and fluid properties on sealing capacity by evaluating the maximum sealing pressure difference and equivalent plugging position. The wellbore pressure, fracture closure pressure and fracture tip pressure can be controlled and measured independently. The sensitive analysis results show that the sealing pressure has an opposite relationship with the equivalent radius of plugging zone. The particle blends selected by D50 Rule has the best sealing performance by bridging near the fracture mouth with the dynamic variation of fracture width. Properly narrowing the range of particle size distribution (PSD) increases the effective sealing concentration. The increase of LCM concentration improves the extensive adaptability of plugging zone with the same sized particles. The increase of LCM resiliency improves the adaptation of plugging zone to dynamic fracture width. The increase of fracture mouth aperture decreases the sealing capacity by extending the required plugging zone. The fluid viscosity increases the sealing capacity by increasing the carrying capacity of fluid and the flow resistance of lost circulation. The increase of injection rate decreases the plugging capacity by increasing the hydrodynamic disturbance.

β-cyclodextrin polymer (β-CDP) microspheres were investigated as high temperature resistant filtration reducers for water-based drilling fluid in this study. The microspheres were synthesized by crosslinking reaction between β-CD and epichlorohydrin with inverse emulsion polymerization. The structural and morphological characteristics of the prepared microspheres were examined by Fourier transform infrared spectroscopy (FT-IR), scanning electron microscopy (SEM), particle size distribution measurement, and thermogravimetry analysis (TGA). The filtration control properties of the microsphere were evaluated via American Petroleum Institute (API) filtration test and high temperature and high pressure (HTHP) filtration test. The results indicated that β-CDP microspheres could effectively reduce the filtration of bentonite suspension both before and after thermal aging at 200 °C without significant influence on drilling fluid's rheology. A substantially enhanced filtration control behavior was observed after thermal aging, which was contrary with conventional filtration reducers. The β-CDP microspheres could absorb a large number of water and became swellable and deformable, which enhanced the compressibility of filter cake. What is more, hydrothermal reaction occurred for part of β-CDP microspheres under high temperature environment, resulting in the formation of numerous carbon spheres ranging from hundreds of nanometers to several micrometers. The β-CDP microspheres, bentonite particles and small carbon spheres in combination contributed to form a dense and compact filter cake with low permeability. β-CDP microspheres were potential candidates as environmental friendly and high temperature filtration reducers in deep well drilling.

The interaction between shale and water is the key factor of wellbore instability in shale gas reservoirs. In this work, the influence of water on shale is studied from the perspective of water activity. Two kinds of shale samples from Sichuan Basin, Southwest China, were characterized using X-ray diffraction (XRD), total organic carbon (TOC) content tests, swelling ratio tests, field emission scanning electron microscope (FE-SEM), uniaxial compressive strength (UCS) and Nitrogen adsorption experiments. The relationships between mineralogical composition, TOC content, swelling ratio and water activity were studied respectively, and then the effect of water activity on microfractures was discussed. Based on the Frenkel–Halsey–Hill equation, fractal dimensions of shales were obtained by the Nitrogen adsorption experiments. And the relationship between water activity and various factors was analyzed. The results show that the water activity of shale is positively correlated with the total content of clay minerals (TCCM), especially the montmorillonite content. When the water activity of external solution was higher than that of shale, shale samples expanded due to chemical potential difference. The swelling ratio increased with increasing water activity of external solutions and shales. Shale swelling led to the development of microfractures, which in turn caused the decrease of strength. Therefore, under higher water activity conditions, shales were more prone to develop microfractures, and thus had lower strength. The adsorption data indicated that the fractal dimensions of shale samples ranged from 2.75 to 2.82, what was heterogeneous and irregular. And fractal dimension showed a good positive correlation with the water activity of shale. What is more, the study also shows that the use of low water activity working fluid in shale gas formation (especially in the formation with high water activity) can inhibit hydration and maintain formation stability.

Hydrate formation and blockage in deepwater oil and gas operations can be prevented by using thermodynamic hydrate inhibitors (THIs). The presence of THIs changes the hydrate suppression temperature; therefore, predicting the change in the hydrate suppression temperature is critically important. In this study, the water activity of eight THI solutions at different concentrations was measured, and the relationships between the hydrate suppression temperature and water activity were analyzed. The analysis results show that the linear, quadratic and cubic polynomials precisely describe the relationship between the hydrate suppression temperature and water activity of the THI solution, as confirmed by the coefficient of determination (R2) value higher than 0.99. Interestingly, the hydrate inhibitory effect increases linearly with decreasing water activity of the THI solution. Based on the existing hydrate suppression temperature correlation, the linear and quadratic polynomials for expressing the relationship between the hydrate suppression temperature and water activity for eight THIs at different pressures were obtained. The data for all eight THIs investigated in this study were collectively analyzed, indicating that at a certain pressure, the hydrate suppression temperature mainly depends on the water activity of their aqueous solution, and these parameters have a linear relationship, irrespective of the THI used. Furthermore, the general correlations for expressing the relationship between the hydrate suppression temperature and water activity for THIs are proposed. This study can provide a simple method for estimating the hydrate suppression temperature of the fluid system using water activity under deepwater conditions.

The success rate of wellbore strengthening is relatively low in shales. Thus, a multi-field coupling wellbore strengthening model was developed by introducing the fully coupled thermo-chemo-poroelastic theory into wellbore strengthening physical model and the fracture element was added to study the closure process of isolated fracture in shales. The thermal and chemical effects were researched by observing the change of hoop stress and fracture aperture. Results show that thermal factor is crucial to wellbore strengthening. The preliminary treatment of wellbore strengthening is mainly controlled by adjusting thermal gradient, combined with a reasonable chemical gradient to inhibit hydration and swelling of clay. The anisotropic Young's modulus and Poisson's ratio are sensitive to hoop stress, the solute diffusion coefficient and permeability anisotropy have a minor effect on wellbore strengthening in low permeability formation. Compared with short fracture, the relatively longer fracture is beneficial for wellbore strengthening with bridging location near the fracture mouth.

As an important preventive and remedial application of lost circulation, the optimization of lost circulation materials (LCMs) has become a crucial problem. In order to optimize the design of LCMs, the mechanism of bridging was studied. Based on the theory of solid-liquid flow, a coupled Computational Fluid Dynamics (CFD) - Discrete Element Method (DEM) model was introduced to accurately simulate the dynamic bridging process of plugging particles. The criterion of critical bridging concentration was developed to quantitatively evaluate the effects of Young's modulus, particle density, particle size distribution (PSD), friction coefficient, fracture geometry, lost circulation velocity and fluid yield stress on bridging capacity. The results show that the plugging zone will become more stable with the increase of particle angularity, Young's modulus, density of LCMs, lost circulation velocity and the decrease of fluid yield stress. The friction failure is easier to occur, because the stability of plugging zone is more sensitive to the friction between particle and fracture surface. The critical bridging concentration is more sensitive to the ratio of inlet size to outlet size (Rio) with a higher ratio of outlet size to particle size (Ro). For a small outlet size (Ro ≤ 2.5), the bridging state can be observed obviously because the large particles are dominant. When the outlet size is larger (Ro > 3), the stable plugging zone is hard to form because the dense state increases the risk of friction failure. The hindering effect of gravity on the trajectory of particles will be more significant when the fracture extension direction is perpendicular to the gravity direction.

Research on using nanotechnology to solve shale instability problems in drilling engineering has been increasing. The combination of amphiphilic polymer and silica nanoparticles may be a new way to improve shale stability. Herein, an amphiphilic polymer/nano-silica composite (poly(styrene-methyl methacrylate-acrylamide)/nano-SiO2) was introduced as a novel shale stabilizer SMA/SiO2 for water-based muds, which possessed the advantages of both physical plugging and chemical inhibition during the drilling operations. The SMA/SiO2 was prepared and characterized by Fourier transform infrared spectra (FT-IR), nuclear magnetic resonance (1H-NMR), transmission electron microscope (TEM), particle size distribution (PSD) and thermogravimetric analysis (TGA) experiments, which confirmed that SMA/SiO2 was regularly spherical with nano-scale and showed good high-temperature resistance. To evaluate the plugging capacity of SMA/SiO2, the pressure transmission test and BET analysis were applied. The results indicated SMA/SiO2 was capable of effectively plugging the pores and fractures in shale. To evaluate the hydration inhibition capacity of SMA/SiO2, the rolling dispersion experiment and contact angle test were adopted. The results demonstrated that SMA/SiO2 could reduce the tendency of shale hydration, which was better than potassium chloride (KCl) and polymeric alcohol (JHC). In addition, SMA/SiO2 only created slight variations on the rheological parameters of the water-based muds (WBMs) and showed a significant filtration control performance. Due to the outstanding performance of physical plugging and chemical inhibition, SMA/SiO2 was expected to be a novel shale stabilizer to solve shale instability problems.

To investigate the interaction mechanism, clay inhibition and compatibility of sodium silicates as shale inhibitor in water based drilling fluid, a variety of properties were characterized. Zeta potential, activity, colloidal stability and particle size were employed to characterize the colloidal properties. Adsorption, cuttings hot-rolling dispersion, linear swelling, pressure and osmosis transmission tests were used to determine the inhibition properties. Results showed that the zeta potential of sodium silicate solution ranging from −45 mV to 0 mV, increased in magnitude with increasing the sodium silicate modulus and pH of solution in the initial stage and decreased with the concentration of monovalent inorganic salts. With the increase of modulus and concentration of sodium silicate, the solution activity generally decreased or colloidal polysilicic acid began to form at a solution concentration above 70 g/L of Na2O⋅2.8SiO2 (2.8SS). The diameter of polysilicic acid increased with 2.8SS concentration, modulus, pH and salt concentration. Adsorption of 2.8SS onto montmorillonite through chemical bonding was boosted with increasing 2.8SS concentration regardless of cuttings addition. The adsorption also rose exponentially with temperature. The activity of the montmorillonite suspension was reduced by the addition of 2.8SS and further decreased by salt addition. 2.8SS was found to exhibit superior inhibition performance compared to KCl, organosilicon, sulfonate asphalt and polyglycol. The pressure transmission was retarded effectively, resulting in the improvement of membrane efficiency of shale clays.

Polyamine is a novel inhibitor applied to water-based drilling fluids in order to reduce hydration of clays, especiallymontmorillonite (MT). In the present study, thewater-adsorption properties of montmorillonite intercalated with polyamine were characterized by X-ray diffraction (XRD), diffuse reflectance infrared Fourier transform spectroscopy (DRIFT) and adsorption isotherm tests using water, benzene and heptane. According to the XRD, DRIFT and water-adsorption test results, polyamine (PA)- intercalated montmorillonite (PA-MT) adsorbs less water than either K+- or NH+4-intercalated montmorillonite (K-MT, NH4-MT). The surface energy of MT was analysed using the van Oss- Chaudhury-Good (VCG) approach based on thewater, benzene and heptane adsorption results. The surface energy between PA-MTand water was less than that of NH4-MT and K-MT. Compared with K-MT and NH4-MT, the surface energy of the Lewis acid portion of PA-MT underwent a more significant decrease, suggesting that the hydration of unexchanged Na+ did not make a discernible contribution. The experimental water-adsorption data were fitted using Langmuir, Brunauer-Emmett-Teller (BET), and Freundlich adsorption models. The Langmuir adsorption models can be used to fit the data for water adsorption on PA-MTacross the entire p/p0 range. After plotting the experimental data in the linear format of the Freundlichmodel, only one linear region for PA-MTwas observed, indicating a singlewater-adsorption mechanism for PA-MT. When compared with PA in the absence of clay, DRIFT spectroscopy showed that the NH2 bending mode for PA-MT shifted from 1571 cm–1 to 1619.7 cm–1. This suggested an increase in hydrogen bonding (H bonding) between the ammonium group and the interlayer water. Across the entire p/p0 range, water is suggested to have adsorbed onto PA-MT through H-bonding interactions between the ammonium group and the interlayer water.

Drilling fluid with proper rheology, strong shale, and hydrate inhibition performance is essential for drilling ultralow temperature (as low as −5 °C) wells in deepwater and permafrost. In this study, the performance of drilling fluids together with additives for ultralow temperature wells has been evaluated by conducting the hydrate inhibition tests, shale inhibition tests, ultralow temperature rheology, and filtration tests. Thereafter, the formulation for a highly inhibitive water-based drilling fluid has been developed. The results show that 20 wt % NaCl can give at least a 16-h safe period for drilling operations at −5 °C and 15 MPa. Polyalcohol can effectively retard pore pressure transmission and filtrate invasion by sealing the wellbore above the cloud point, while polyetheramine can strongly inhibit shale hydration. Therefore, a combination of polyalcohol and polyetheramine can be used as an excellent shale stabilizer. The drilling fluid can prevent hydrate formation under both stirring and static conditions. Further, it can inhibit the swelling, dispersion, and collapse of shale samples, thereby enhancing wellbore stability. It has better rheological properties than the typical water-based drilling fluids used in onshore and offshore drilling at −5 °C to 75 °C. In addition, it can maintain stable rheology after being contaminated by 10 wt % NaCl, 1 wt % CaCl2, and 5 wt % shale cuttings. The drilling fluid developed in this study is therefore expected to perform well in drilling ultralow temperature wells.

Lost circulation in fractured formations is a major challenge. The addition of conventional lost circulation materials (LCMs) to drilling fluids is the main method to control loss. The seal integrity is affected by different properties of LCMs. Plugging apparatus with slot is extensively used to evaluate sealing performance of the selected LCMs. In general, the fracture in the formation has depths, and the drilling fluids loss far into the formation. A LCM test apparatus with long fracture slot was introduced in this paper. The main objective of this work is to study the effect of LCM type, concentration and particle size distribution on the seal integrity with long fracture slot. The breaking pressure, fluid loss values, position and thickness of plugging zone are the parameters for evaluating LCM performance. Optical microscopy and scanning electron microscopy were used to observe the arrangement and microstructure of the seal. We can better understand the sealing mechanisms in long fracture by analyzing the cell pressure and fluid loss vs. time plot and the seal structure. Results showed that increasing the LCMs stiffness resulted in higher breaking pressure. There is a critical maximum concentration at which LCM will bridging and filling set at the fracture entrance and no tight seal barrier inside the fracture. Loss effect was beneficial to form thicker plugging zone inside the fracture. Suitable wide particle size distribution of LCM formed thick plugging zone inside the fracture. Multi-layer seal barrier can withstand the external load together, resulted in high seal integrities. The addition of fibrous materials in particles resulted in higher breaking pressure and lower fluid loss.

The protection of high porosity and high permeability reservoirs has not got enough attentions because the excellent hydrocarbon storage capacity would provide high oil and gas productivity even being damaged to some extent. Deepwater oil and gas reservoirs are mainly high porosity and permeability reservoirs, and the reservoir protection is important because severe reservoir damage will cause an enormous economic loss due to high investment and risk of deepwater operation. A new deepwater gas field in the western part of the South China Sea must be developed soon, and the reservoir protection strategy needs to be studied. The characteristics of the reservoir were studied by X-ray diffraction, scanning electron microscope, mercury intrusion porosimetry, hot rolling dispersion test and liner swelling test. Furthermore, the water and salinity sensitivities of the reservoir were studied. The results show that the reservoir has high porosity and high permeability with an average porosity larger than 30% and an average permeability higher than 500×10-3 μm. The large pore throats will be easily invaded and plugged by solids in drilling and completion fluid. Therefore, effective temporary-plugging of the pore throats with a wide size range is extremely important. The content of clay mineral is 9% to 19% with approximately 50% mixed-layer illite-smectite, presenting potential borehole instability and reservoir damage risk due to its strong hydration ability. In addition, the reservoir has strong salinity sensitivity and medium-weak water sensitivity. The reservoir protection strategy of drilling and completion fluid related to the properties of the reservoir was proposed. A multi-stage bridge temporary-plugging method was used to prevent the invasion of solids into the pore throats with a wide size range. A highly inhibitive polyamine was selected to inhibit the hydration of clays to maintain wellbore stability and reduce reservoir damage. Because of the requirement of gas hydrate inhibition and density adjustment, a high performance water-based drill-in fluid with formate brines was developed. It has excellent reservoir protection performance with the permeability recovery rate approximately 90%. Meanwhile, it performs well in inhibiting clay hydration, hydrate formation, and has good rheological as well as filtration properties over a wide temperature range from 4 °C to 75 °C. This work provides theoretical guidance of reservoir protection and a high performance drill-in fluid for the target deepwater gas filed. We hope it will also be useful for the protection of high porosity and high permeability reservoir in other deepwater oil and gas fields.

It is known that ultra-high temperature drilling fluids are still quite a challenge to drilling engineering. When bottomhole temperatures exceed 200°C, the design and formulation of drilling fluids can present a host of problems. Drilling fluids destabilize under such extreme conditions, possibly causing wellbore instability, well control problems, and ultimately loss of the well. Drilling buried hill hydrocarbon reservoir in offshore oilfield around Bohai Sea Bay Basin in China has often resulted in failure to reach desired objectives. Bottomhole temperatures up to 220°C, however, the pressures requiring drilling fluid weights just to 1.04 to 1.10 g/cm3 equivalent place severe limitations on the performance of drilling fluids and often contribute in failure to reach the desired drilling objectives. Polymers as viscosifying agent that control rheological properties and fluid loss create major challenges for drilling fluid performance and stability when temperatures over 200°C are reached. Additionally, the gelation of drilling fluids containing low solids content and high fluid loss can become difficult to control under ultra-high temperature conditions. Both of these issues are compounded when the ultra-high temperature is coupled with a requirement for low drilling fluids density. The wildcat well NP3-81 and NP3-82 were drilled in this offshore oilfield around Bohai Sea Bay Basin on January 2014. TD of 6066 meters and 6037 meters were attained, respectively. Both of the bottomhole static temperatures were exceed 220°C and the pore pressure was 1.04 to 1.10 g/cm3 equivalent. Logs were run to bottom without incident and drilling fluids related problems and the primary drilling objectives achieved. The success is attributed to the new technology, fit-for-purpose drilling fluids and rigorous pre-well planning. The paper describes the laboratory development and field application of a new technology of environmentally acceptable and seawater discharged drilling fluids designed for ultra-high temperature environments, highlighting the viscosifying agent which has excellent ultra-high temperature resistance and salt resistance viscosifying property, thermal stability and thermo sensitive characteristics. The apparent viscosity retention rate of novel viscosifier after aging at 220°C after 16 h were 90.81% and 95.95% respectively and the EC50 value was 15.529×104 mg/L in both fresh water based drilling fluid and salt-water based drilling fluid. Field application data shows that this new polymer viscosifying agent could play a critical role even though at harsh conditions such as ultra-high temperature and low density drilling fluids system which decreasing daily performance maintenance problems at the expense of the large consumption of fluid additive including conventional sulfonate copolymer.