High Pressure And High Temperature Research Articles

Effect of Hematite Dosage on Water-Based Drilling Fluid and Filter Cake Properties

Abstract Drilling deep wells became common in the oil and gas sector as a result of the high demand for energy in the world. This type of wells is not trivial to drill as a result several challenges that they encounter, such as harsh conditions represented by high-pressure and high-temperature (HPHT), and the high hydrostatic column required to prevent the kick. Therefore, advanced materials are desired and accordingly higher concentration of weighting material is required to drill such resources. In this work, a systematic investigation of the hematite concentration effect on the water-based drilling fluid properties is performed. Three doses were overloaded to a constant drill fluid recipe. Then, the drilling fluid properties including density, viscosities, filtration, and filter cake properties were evaluated. The viscosities were assessed at the temperature of 120 °F, before and after aging in a hot rolling oven for 16 h at 250 °F and 500 psi. The American Petroleum Institute filtration test was performed at ambient temperature and 100 psi. The results showed that the hematite concentration has proportional relation to the apparent viscosity, plastic viscosity, and yield point before and after the hot rolling. The YP/PV ratio was decreased as the hematite dose increased in the drilling fluid. Similarly, the gel strengths at 10 s and 10 min were increased as the concentration of hematite increased. The filter cake thinness, filtration volume, and filter cake permeability were also amplified as the hematite concentration increased, where the filter cake porosity was almost kept constant. In addition, several correlations were drawn as a function of the hematite dosage for the examined drilling properties.

Graphene nanoplatelets reinforced cement as a solution to leaky wellbores reinforcing weak points in hydrated Portland cement with graphene nanoparticles improves mechanical and chemical durability of wellbore cements

To improve the performance of wellbore cement under subsurface environments, graphene nanoplatelets (GNPs) were added in various percentages to Class-H cement slurry. Microstructural characterization of cement slurries cured at 90 °C and 95% RH indicates that GNP modifies the microstructure of hydrated cement by reinforcing pore spaces. As a result, the mechanical properties, such as Young's modulus and axial peak stress, obtained from high temperature triaxial compression tests are significantly improved based on different percentages of added GNPs. Furthermore, the hydrated 1 × 2inch GNP- Portland cement cores tested under simulated deep wellbore conditions of high-temperature and high pressure (HTHP), appear to have a ductile-like behavior, when compared to a typical brittle nature of Portland cement pastes. From our observations and published data on graphene resistance to fracture, GNP addition to cement is evidently enhancing the flexibility of cement. These improvements would reduce the risks associated with wellbore cement deterioration and a consequent leakage in fossil fuel production, geothermal energy production, CO2 storage as well as long-term sealing materials in plugging and abandonment of all wellbores at the end of their service life.

Polysaccharide derivative as an additive in Olefin-Based drilling fluid

The search for drilling fluids of low environmental impact and high performance has increased and became of utmost importance over the years. In this study, a hydrophobically modified polysaccharide was obtained from the reaction of carboxymethylcellulose (CMC) with dodecylamine (DDA) in water and evaluated as a new green additive in an olefin-based fluid. FTIR and 1H NMR spectra revealed the presence of amide groups on the CMA-DDA derivative, demonstrating that the reaction was successful. Unlike the polysaccharide precursor, the product showed turbidity in water, due to association between hydrophobic groups inserted onto CMC chains. The formation of polymer aggregates in water was confirmed by DLS. The rheological measurements in water and saline medium also corroborated to DLS data, as the viscosity of the derivative was higher than that of CMC. Confocal microscopy indicated that the hydrophobically modified CMC contributes to the inverse emulsion stability. CMC-DDA behaved as an efficient rheological modifier on olefin-based drilling fluids, besides of contributing to reduce filtrate loss under high temperature and high pressure (HTHP) conditions.

Effects of carbon nanotubes and sintering parameters on microstructure and properties of PCD

Polycrystalline diamond (PCD) was sintered from onion-like carbon (OLC) mixed with multi-walled carbon nanotube (MWCNT) at 5.5 GPa/1100–1300 °C/5–20 min holding time, in which OLC was generated by vacuum annealing of nano-diamond. Structures, morphologies, and properties of composites were characterized by X-ray diffraction, field emission scanning electron microscope, high-resolution transmission electron microscopy, and hardness measurement. The purposes of this paper were to lower the temperature of OLC conversion into PCD and optimize the performance of the PCD. The influence of sintering parameters on the microstructure and properties of PCD and the change of MWCNT and OLC structure in high-pressure and high-temperature (HPHT) were studied. Finally, when the mass fraction of carbon nanotubes is 10 %, the optimal process conditions were as follows: sintering pressure 5.5 GPa, temperature 1150 °C, holding time 20 min, sintering hardness was 18.84 GPa, and conversion rate of OLC to diamond was 25.96 %. Under the influence of HPHT and surrounding OLC, the MWCNT tends to be transformed into spheroids, while the structure of the OLC/MWCNT binding zone is graphite. This work not only provided a theoretical basis for the study of carbon nanotubes but also provided reasonable parameters for the synthesis of PCD.

Progresses in Fluid Inclusion Synthesis in Quartz

High-temperature and high-pressure (HTHP) fluids are one of the most extensive participants in geological events. The representative in situ sampling of the HTHP fluids, which is an essential prerequisite for precisely characterizing the HTHP fluids (including compositional and volumetric properties), has been a vital challenge. The technique of fluid inclusion synthesis (FIS) in quartz is one of the only options. It has experienced an almost 40-year development since the standard fracture healing method was invented. Considerable advances in our understanding of physicochemical properties of geological fluids and their roles in many geological processes have been achieved by the use of the FIS techniques. A set of methodologies for fluid inclusion synthesis have been established. Great progresses have also been made, which includes the various pretreatment FIS techniques, the in situ fracturing FIS technique closely associated with the HTHP apparatus, the in situ fracturing refilled FIS technique for large fluid inclusion synthesis at controlled time under unfavorable conditions, and the novel fluid inclusion synthesis by fused silica capillary. Such great many progresses of the quartz FIS techniques have been scattered in the geochemists’ individual research work, and systematic collection and objective evaluation are missing. Consequently, we synthesize existing research, describe and identify the basic operations, discuss the methodological issues like pros and cons, and highlight the problems and prospects of the quartz FIS techniques. Furthermore, it is suggested that in situ and (or) large volume fluid inclusion synthesis will be an important future direction in view of the growing applications of the FIS techniques in combination with microanalytical techniques, especially the Laser Ablation-Inductively Coupled Plasma-Mass Spectrometry (LA-ICP-MS). Our review would provide technical guidance to those who wish to investigate HTHP fluids and be beneficial to the future development and applications of the FIS techniques.

Simulation and application analysis of gravel packing in deepwater HT/HP wells

AbstractGravel packing is one of the main sand control methods for deep‐water high‐temperature and high‐pressure (HT/HP) reservoirs. According to the specific characteristics of deep‐water HT/HP and multichannel, considering the influence of slurry flowing through long‐distance multichannel and the slurry temperature alternation along the flow path, based on α–β wave packing theory, a coupling model of gravel packing in deep‐water HT/HP horizontal wells is established. The packing simulation algorithm and calculation process are designed to realize the gravel packing temperature pressure simulation and multistage refined friction calculation of deep‐water HT/HP horizontal wells. The influence of each packing parameter on the packing process is fully studied. Furthermore, the application simulation of the A10H well of the South China Sea deepwater HP well is carried out. The simulation results show that in the slurry injection stage and α wave packing stage, the packing pressure is low and the residual pressure window is large. In the β wave packing stage, the packing pressure increases rapidly, the residual pressure window shrinks rapidly, and finally, at the end of β wave packing, the residual pressure window becomes narrow. The viscosity of carrier fluid has a significant impact on the pressure window of packing operation. For the design pump rate of 5.6 bpm, the packing cannot be completed with 5.0 cp viscosity carrier fluid. For the carrier fluid with high viscosity, the multi‐β wave packing technique of pump reduction control pressure at the end of the β wave packing stage is used, and this process is simulated in this paper. Considering three constraints: not sand packed in the drilling string, without premature bridging in the α wave packing stage, and α and β wave packing pressure control conditions, the safe range of pump rate is determined under different operation safety margin conditions, which can provide technical support for on‐site operation.

Thermochemical Mechanism of Optimized Lanthanum Chromite Heaters for High-Pressure and High-Temperature Experiments

High-pressure heaters in large volume presses must reconcile potentially contradictory properties, and the whole high-pressure and high-temperature (HPHT) community has been engaged for years to seek a better heater. LaCrO3 (LCO)-based ceramic heaters have been widely applied in multianvil apparatus; however, their performance is far from satisfactory, motivating further research on the chemical optimization strategy and corresponding thermochemical mechanism. Here, we adopted a chemical-screening strategy and manufactured tubular heaters using the electrically, chemically, and mechanically optimized Sr-Cu codoped La0.9Sr0.1Cr0.8Cu0.2O3-δ (LSCCuO-9182). HPHT examinations of cylindrical LSCCuO-9182 heaters on Walker-type multianvil apparatuses demonstrated a small temperature gradient, robust thermochemical stability, and excellent compatibility with high-pressure assemblies below 2273 K and 10 GPa. Thermochemical mechanism analysis revealed that the temperature limitation of the LSCCuO-9182 heater was related to the autoredox process of the Cu dopant and Cr and the exchanging ionic migration of Cu and Mg between the LSCCuO-9182 heater and the MgO sleeve. Our combinatorial strategy coupled with thermochemical mechanism analysis makes the prioritization of contradictory objectives more rational, yields reliable LCO heaters, and sheds light on further improvement of the temperature limitation and thermochemical stability.

Case Study of Successfully Staged Acid Fracturing on the Ultra-Deep Horizontal Well for the Qixia Fm HTHP Tight Carbonate Gas Reservoir in China

The lower Permian Qixia formation gas reservoir is characterized by ultra-deep buried, high temperature and high pressure (HTHP), low porosity and permeability, ultra-high closure pressure, and thin thickness in the western Sichuan Basin, China. Acid fracturing has been adopted as the main well stimulation technology. The average test production of the acid-fractured vertical well was 46 × 104 m3/d. The horizontal well with staged acid fracturing is considered a reliable measure to enhance gas production. However, the staged acid fracturing on the ultra-deep horizontal well has been challenged. The reaction rates of conventional, self-diverting, and gelled acid and the acid-etched fracture conductivity experiments under HTHP are measured to optimize the acid fracturing technique. The reaction rate of gelled acid with Qixia Fm limy dolomite at 150°C is 3.4–6.7 times faster than that with dolomite and similar to that with limestone. The gelled acid with better retardation and friction reduction performance is selected as the main acid to increase the effective acid-etched fracture length. The acid-etched fracture conductivity can be greatly enhanced by using gelled acid, increasing acid volume, and closed fracture acidizing (CFA) under a closure stress of 50 MPa. Moreover, the feasibility of staged acid fracturing for ultra-deep horizontal wells is discussed. The first stage is assembled by fracturing sleeve, spared ball drop sleeve, and circulating valve to ensure activation of the fracturing channel. The tested production is significantly enhanced with temporary plugging and open-hole packer and sliding sleeve staged acid fracturing.

Experimental study on chemical-assisted methane flooding for foamy oil reservoirs after primary production

As the foamy oil phenomenon disappears gradually, the produced gas-oil ratio of foamy oil reservoirs increases rapidly and the well productivity declines fast. This paper presents a new EOR method for foamy oil reservoirs after cold production, called chemical-assisted methane flooding (CAMF), which works with the viscosity reducer slug (naphtha) to improve the mobility of heavy oil in the porous media and then the methane gas and foaming liquid slug to form a secondary foamy oil phenomenon under the action of formation shear and foaming liquid. Experimental studies were carried out to understand the mechanisms of CAMF. First, a high temperature and high pressure (HTHP) rheometer was used to evaluate the viscosity reduction performance of naphtha under different temperatures and naphtha contents. Then, a visual HTHP experimental unit was adopted to identify whether secondary foamy oil would be effectively generated. Finally, a specially designed HTHP microscopic flow experimental unit was adopted to reveal the microscopic flow behaviors and EOR mechanisms of CAMF. The study results show that the CAMF process can form an obvious secondary foamy oil phenomenon, proving CAMF as an effective method to enhance the oil recovery for foamy oil reservoirs after primary production. In the process of CAMF, naphtha can improve the mobility of heavy oil, reduce the resistance to the subsequently injected foaming liquid and methane gas when entering deep reservoir, and create conditions for the subsequent formation of secondary foamy oil. The formation of the secondary foamy oil can reduce the injected gas channeling velocity, improve the elastic energy, reduce the viscosity and interfacial tension of heavy oil, and have certain emulsification effects. For this method, the optimal injection timing occurs when the reservoir pressure drops between the bubble point pressure and the pseudo-bubble point pressure. Simultaneous injection of methane gas and foaming liquid is obviously better than alternating injection. if economic conditions permit, a higher surfactant concentration should be used for CAMF, and the optimum gas-liquid ratio for CAMF is 1:1 under the experimental conditions.

Effect of excess viscosifier and fluid loss control additive on the rheological characteristics of water-based drilling fluid

Water-soluble polymers are used to improve drilling operations to ensure that oil and gas wells are drilled in less time and completed with minimized formation damage. However, excessive utilization of these polymers additives may have implication on the drilling outcomes. In this work, drilling fluids comprising of different compositions of polyanionic cellulose (PAC), and starch; and a constant amount of bentonite were formulated to examine the effects of excessive use of each additive or their combinations in a water-based drilling fluid (WBDF). The fluid properties were further investigated at low pressure and low temperature (LPLT) as well as high pressure and high temperature (HPHT). The results suggest that the viscosities of the fluid are not only dependent on the shear rate, shear stress, and composition but also on the temperature and pressure. Model plots of shear stress (Pa) against shear rate (s−1) using the Power law, Bingham plastic and Herschel-Bulley shows that all composition have low viscosity and low yield point. Increasing the amount of additive increases, the equivalent circulating density (ECD) which may increase differential sticking and consequent formation damage.

New HTHP fluid loss control agent for oil-based drilling fluid from pharmaceutical waste

In Oil-Based drilling fluid systems (OBM, for Oil-Based Mud) the oil phase is the major source of contamination and hydrocarbon pollution is, by far, the main concern. However, the release and accumulation of mud additives in the environment may be deleterious on grounds of volume and/or concentration. This paper describes a waste valorisation study from an antibiotic large-scale manufacturing for the preparation of a new drilling fluid additive (Fluid-Loss-Control agent: FLC) for OBM. This additive is environment-friendly, biomaterial in nature, and totally biodegradable and thus expected to have no detrimental effects on the surrounding environment and ecosystems. After product washing, heating, grinding, and screening, a cationic surfactant was used to improve fluid stability and filtration properties. Our results show that: According to drilling fluid requirements, the treatment of this pharmaceutical reject yields a product with good properties, i.e. satisfactory as far as thermal stability, filtration characteristics, and rheology property are concerned, - The pre-treatment of those products (according to their original state and particle size, as well as the type and concentration of added surfactant) enhances additive quality and shows good compatibility in drilling fluid systems, - The substitution of this new product for conventional additives affords good drilling fluid stability and performance under high temperature and high pressure (HTHP) conditions, economic, and environmental solutions to improve the environmental standing of OBMs further. • Providing effective environmentally acceptable fluid loss control. • New additive without damaging formation permeability. • Presentation of new fluid-loss-control agent from the pharmaceutical industry. • It is a by-product of an industrial antibiotic fermentation process.

Preparation of novel titanium-niobium-oxygen composite ceramic with excellent thermoelectric properties using the high-pressure and high-temperature method

Titanium oxide is a promising thermoelectric material because of its high stability and low cost. We synthesize novel titanium-niobium-oxygen composite ceramics directly from elementary substance Nb and TiO2 under high-pressure and high-temperature (HPHT) in this work. Elemental substance Nb will reduce TiO2 to Magnèli phase titanium oxide at high pressure and high temperature. In this process, elemental substance Nb is oxidized to various niobium oxides. The experimental results show that the composite ceramics have a special 'pore' microstructure, and their thermoelectric and mechanical properties are very prominent among metal oxide thermoelectric materials. After repeated tests, the optimum concentration sample zT value is 0.313 at 973 k, with a Vickers hardness of 7.06. This work provides a novel concept for improving the performance of TiO2 by reducing it with metal elementary substances other than Ti.

Influence of high-temperature, high-pressure, and acidic conditions on the structure and properties of high-performance organic fibers

Abstract Aramid and poly(p-phenylene benzobisoxazole) (PBO) fibers are two of the most represented organic fibers possessing high strength, high modulus, excellent thermal stability, and chemical resistance, with great potential in oil and gas applications. The reliability of organic fibers for oil and gas applications were systematically evaluated by studying the corrosion behavior and mechanisms in high-temperature and high-pressure (HTHP) hydrogen sulfide (H2S) and carbon dioxide (CO2) corrosive environments. Scanning electron microscope (SEM), Fourier transform infrared spectroscopy (FT-IR), thermogravimetric analysis (TGA), X-ray diffraction (XRD), elemental analysis, density measurements, and single fiber tensile testing were conducted to study the surface morphology, chemical structure, crystal structure, thermal, and mechanical properties of aramid and PBO fibers, before and after corrosion. After corrosion, the crystallinities of aramid and PBO fibers decreased by 19.4 and 4.4%, respectively, whereas their tensile fracture strengths decreased by 50.34 and 28.18%, respectively. Hence, the corrosion resistance of PBO fiber is better than aramid fiber. The decrease in tensile properties of aramid and PBO fibers can be attributed to the higher internal porosity, more number of surface defects, and lower crystallinity after HTHP H2S/CO2 corrosion. This work provides some fundamental information regarding the selection of high-performance organic fibers for oil and gas applications.

Effect of high‐temperature, high‐pressure, and acidic conditions on the structure and properties of high‐performance fibers

AbstractHigh‐performance fibers such as carbon, aramid, and glass fiber generally have excellent mechanical, thermal, and chemical resistance and they have potential applications in oil and gas exploitation where high‐temperature and high‐pressure (HTHP) H2S/CO2 corrosive environments usually exist. To investigate the corrosion behavior of these fibers under such environments, two corrosion environments (HTHP water, HTHP H2S/CO2) were simulated in a high‐temperature high‐pressure reactor. Scanning electron microscope, X‐ray diffraction, density measurements, and single fiber tensile test were performed to study the surface morphology, crystal structure, and mechanical properties before and after corrosion. After exposure to the second corrosion environment, the carbon aramid fibers had no obvious mass loss and tensile strength retention of 70.28% and 49.66%, respectively. The surface of the aramid fiber and carbon fibers was significantly damaged which led to an increase in surface defects and a decrease in crystallinity. The glass fiber had clear weight loss due to a large number of defects being formed in the structure and the retention of tensile fracture strength was 48.18%. Corrosion under HTHP H2S/CO2 conditions caused more serious damage to the high‐performance fiber structures.

Synthesis and characterization of cubic boron nitride (Al)-Al2O3 composites under high pressure and high temperature conditions

Cubic boron nitride (cBN) (Al)-Al2O3 composites were synthesized by Chinese multi-anvil high pressure apparatus (CHPA) sintering at 5.0 GPa and 1200–1500 °C using Al-coated cBN (cBN (Al)) and Al2O3 powders. The effects of Al coating, phase composition, densification, Vickers hardness and thermogravimetry of the composites were investigated. Al coating on cBN powder activated the surface of cBN in the composites and reacted with cBN to produce AlN under high pressure and high temperature (HPHT) environment, which helped to promote the bonding strength of cBN and Al2O3. The hardness of cBN (Al) + 15 vol% Al2O3 is 29.7 GPa when sintered at 5.0 GPa and 1350 °C. Compared to cBN-Al2O3 composites, the hardness of cBN (Al)-Al2O3 composites increased by 37.5%. AlN, the reaction product of cBN with Al under HPHT environments, acts as a bridge phase and joins the two phases of cBN and Al2O3 in the form of chemical bonds. This is the intrinsic mechanism of hardness improvement of cBN (Al)-Al2O3 composites.

Foam Based Fracturing Fluid Characterization for an Optimized Application in HPHT Reservoir Conditions

Water-based fracturing fluids are among the most common fluid types used in hydraulic fracturing operations. However, these fluids tend to cause damage in water-sensitive formations. Foam comprises a small amount of base fluid, and compressible gas such as carbon dioxide and nitrogen has emerged as a more ecologically friendly option to fracture such formations. Foam is an attractive option since it has a low density and high viscosity. The applicability of foamed frac fluid is characterized by foam stability and rheology, encompassing the viscosity and proppant carrying ability. The foam quality, pressure and temperature affect the foam rheology. Generally, foam viscosity and stability increase with pressure but decrease when the temperature increases. Hence, it is essential to preserve foam stability in high pressure and high temperature (HPHT) reservoir conditions. The addition of nanoparticles could increase the thermal stability of the foam. This article provides the basis of foam-based fracturing fluid characterization for an optimal application in HPHT reservoir conditions. Then, focusing on improving thermal stability, it reviews the research progress on the use of nanoparticles as foam stabilizing agent. This paper also sheds light on the literature gaps that should be addressed by future research.

Analysis and Mitigation of High-Pressure and High-Temperature Well Completion Design of Elkin/Franklin Fields in the North Sea

The development of High-Pressure and High-Temperature (HP/HT) wells is accompanied by high risk, and still represents one of the greatest technological challenges for the oil and gas industry related to the equipments used and their ability to sustain these conditions. The results analysis of data is key to investigating reasons for bad performances and failures of well completion design and detecting at an early stage potential downhole events.This paper applies machine learning to the results of real data analysis of deep and deviated well in the HP/HT environment. It presents techniques used to analyze design limits for the tubing string of the well with different rates of production and water injection, and predict pressure and temperature when multiple operations are applied to the tubular string during the well's lifetime. It also analyzes the most important parameters that impact the tubular string, such as temperature effect, safety factors, and tubing length change. A simulation model for a well has been developed to accomplish the objective of this work by using WellcatTM software modules (Prod & Tube) based on real data from the Elgin/Franklin fields in the North Sea. Two designs of tubular string were used to analyze design limits; the first included a tubing size of 4 ½ in and a latched permanent packer, and the second was identical to the first one but included an expansion joint tool to allow free movement of the tubing, and it was used to mitigate the first well completion design failure. Based on the results of this paper, three load cases (produce-6 months, tubing leak, and water injection) failed in the first design when the rates of oil production and water injection were increased to 12000 bbl/d and 5000 bbl/d respectively, whilst all load cases fell into the triaxial envelope and met the axial criteria in the second design. Furthermore, the predicted results of pressure and temperature for the tubing and surroundings indicate the tubular string could be exposed to buckling problems and serious thermal expansion in the annulus. As well, tubing length can be changed (elongated or shortage) owing to thermal effects during multiple load cases.

Are photo-induced crystalline sulfur and S-II equivalent under high pressure?

Sulfur is known to be a photo-sensitive material. Photo-induced crystalline sulfur (p-S) was found in high-pressure Raman studies more than two decades ago. However, its structureremains not well understood. In this work, a thin α-S8 crystal was pressurized to 8 GPa in a diamond anvil cell (DAC) and its surface was repeatedly scanned by a 532 nm laser to produce the largest possible amount of p-S. A high-quality XRD pattern of p-S was obtained for the first time. The refinement of experimental data indicated the structural consistency between p-S and high-pressure and high-temperature (HPHT) S-II phases. Moreover, HPHT experiments were conducted to study the effect of temperature on p-S formation. The current work provides a strategy for producing the high-purity photo-induced product. The combination of synchrotron XRD, Raman spectroscopy, and microscopical imaging technology shows an effective way for photochemical research.

Inversion-based model for quantitative interpretation by a dual-measurement points in managed pressure drilling

Deep wells control safety problems have always been the focus of attention due to the influence of complicated geological conditions, such as high-temperature and high-pressure (HTHP). Considering the mathematical model is only approximation of reality, thus the continuous transmission of real-time measurements is more popular, which can be used to identify the undetermined downhole parameters and improve accuracy of the model predictions. In the current study, we use two pressure while drilling tools to monitor downhole parameters in real time. Firstly, combined with the unscented-Kalman-filter (UKF) algorithm, a well hydraulics forward model with density factor and friction factor based managed-pressure-drilling (MPD) system is developed to quantitatively analyze the actual transient annular pressure. Secondly, a new multi-phase flow inversion model is established by determining the inversion parameters as gas kick rate and the position of the gas kick, which is used to track the values of pressure and outlet flow rate in real-time. The results of the case indicate that the inversion accuracy of the inversion parameters increases with the distance between dual-measurement points, and the reasonable value is selected as 30 m. Additionally, the proposed model is successfully validated using synthetic data and experimental data, where the maximum errors in predicting the position of the gas kick are only 3.1% and 5.3% when tuning the model stably tends towards the true value, respectively. The proposed model achieves accurate quantitative interpretation and analysis of downhole gas kick conditions, further clarifies the previously unknown key parameters of downhole gas kick, and has important significance for the realization of safe and efficient drilling.

Rheological Properties of the Water-Based Muds Composed of Silica Nanoparticle Under High Pressure and High Temperature

Summary Research currently has shown two contradicting conclusions about silica nanoparticle (SNP) application in mud fluid. While different studies have concluded that adding SNPs reduces the rheological properties, others have found that this is not the case. Therefore, this work was carried out to add to the literature and research that has already been done by different scholars on the performance of SNPs in water-based muds (WBMs). The synthesis of SNPs was performed by the sol-gel process based on the Stöber method in a mixture of a catalyst ammonium hydroxide containing tetraethyl orthosilicate (TEOS), ethanol, and water. The distribution of particle dispersion, size, and zeta potential of SNP analysis was obtained using the dynamic light scattering analysis. Rheological analysis indicated good rheology at different temperatures with 0.5 wt% and 1.0 wt% silica concentration. Furthermore, viscosity and yield point (YP) were stabilized with nanoparticles (NPs at elevated temperatures (up to 176°C) as well as the reference mud maintained rheology (up to 121°C) and above that temperature, there was a drastic change indicating failure. Aging at temperatures above 121°C for 16 hours showed that NP WBMs remained stable with minor changes in rheology. Using bigger sized SNPs than previously used resulted to enhancement in the rheology of WBMs. Previous studies had used SNPs in sizes of 20–40 nm which negatively affected mud rheology. In this study, SNP of a bigger size resulted in rheological property enhancement. It is believed that particle size with other dynamics and mechanisms that still need to be investigated, for example, zeta potential, repulsive and attractive forces are some of the factors in play that affect nanoparticle performance in mud fluids. The obtained rheological data for different NP muds were matched to the traditional drilling mud rheological models to ascertain the best fit model that would be applied to an efficient design and the data fitted the Herschel-Bulkley model. Filtration tests at high pressure and high temperature (HPHT) conditions also indicated that synthesized SNPs used in the mud fluid resulted in a slightly low permeable thin mudcake and a low API gravity filtration loss which have great advantages when drilling through highly permeable formations. Filtrate loss was reduced by 7.5, 9.1, 15.4, and 6.7% when temperature increased to 100, 121, 149, and 176 °C at 1 wt% silica concentration, respectively. The mudcake was also improved and thickness reduced by 30 and 25% at 0.5 wt% silica concentration when temperatures increased from 149 and 176°C, respectively, compared to the reference mud (R) under HPHT conditions. The research results provide a comprehensive evaluation of an enhanced WBM using SNPs for HPHT applications. The investigated NP has the potential to improve drilling mud properties which may led to less formation damage and efficient drilling operations.