Thermoresponsive Bentonite for Water-Based Drilling Fluids

As an important industrial material, bentonite has been widely applied in water-based drilling fluids to create mud cakes to protect boreholes. However, the common mud cake is porous, and it is difficult to reduce the filtration of a drilling fluid at high temperature. Therefore, this paper endowed bentonite with a thermo response via the insertion of N-isopropylacrylamide (NIPAM) monomers. The interaction between NIPAM monomers and bentonite was investigated via Fourier infrared spectroscopy (FTIR), isothermal adsorption, and X-ray diffraction (XRD) at various temperatures. The results demonstrate that chemical adsorption is involved in the adsorption process of NIPAM monomers on bentonite, and the adsorption of NIPAM monomers accords with the D–R model. With increasing temperature, more adsorption water was squeezed out of the composite when the temperature of the composite exceeded 70 °C. Based on the composite of NIPAM and bentonite, a mud cake was prepared using low-viscosity polyanionic cellulose (Lv-PAC) and initiator potassium peroxydisulfate (KPS). The change in the plugging of the mud cake was investigated via environmental scanning electron microscopy (ESEM), contact angle testing, filtration experiments, and linear expansion of the shale at various temperatures. In the plugging of the mud cake, a self-recovery behavior was observed with increasing temperature, and resistance was observed at 110 °C. The rheology of the drilling fluid was stable in the alterative temperature zone (70–110 °C). Based on the high resistance of the basic drilling fluid, a high-density drilling fluid (ρ = 2.0 g/cm3) was prepared with weighting materials with the objective of drilling high-temperature formations. By using a high-density drilling fluid, the hydration expansion of shale was reduced by half at 110 °C in comparison with common bentonite drilling fluid. In addition, the rheology of the high-density drilling fluid tended to be stable, and a self-recovery behavior was observed.

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An Investigation on the Function of Mud Cakes on the Inhibition of Low Molecular Inhibitor for Water-Based Drilling Fluids

Energies ◽

10.3390/en12193726 ◽

2019 ◽

Vol 12 (19) ◽

pp. 3726 ◽

Cited By ~ 1

Author(s):

Wenxin Dong ◽

Xiaolin Pu ◽

Biao Ma

Keyword(s):

High Performance ◽

Drilling Fluid ◽

Environmental Scanning Electron Microscopy ◽

Homogeneous Layer ◽

Environmental Scanning ◽

Drilling Fluids ◽

Mud Cake ◽

Water Based ◽

Oil And Natural Gas ◽

Pass Through

The major low molecular inhibitors showed inhibition in the hydration of clay in the laboratory for water-based drilling fluids, according to the principle of intercalation adsorption. However, inhibitors have failed and caused serious engineering accidents in drilling oil and natural gas. This paper investigated the transmission of several of drilling fluids to indicate whether low molecular inhibitor for drilling can effectively inhibit the wellbore hydration. The inhibition of drilling fluid with the plugging of mud cakes, was significantly weakened based on the hydration expansion of cores and cutting recoveries. The residual contents of inhibitors were determined with the precolumn derivation of high-performance liquid chromatography (HPLC) analysis and were chartered with Fourier transform infrared spectroscopy (FTIR) and nuclear magnetic resonance (NMR) analysis in the structure of the derivative. The clogging behavior of the mud cake was described by environmental scanning electron microscopy (ESEM). Experiments show that 40 wt% to 90 wt% by weight of the corrosion inhibitor cannot pass through the mud cake in the dynamic filtration of the drilling fluid. The mud cake can be further divided into a nanostructure layer, a homogeneous layer and an anisotropic layer with different permeability. Most inhibitors should be limited to the nanostructure layer and the homogeneous layer.

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Effect of Cycloaliphatic Amine on the Shale Inhibitive Properties of Water-Based Drilling Fluid

The Open Fuels & Energy Science Journal ◽

10.2174/1876973x01508010019 ◽

2015 ◽

Vol 8 (1) ◽

pp. 19-27 ◽

Cited By ~ 5

Author(s):

Hanyi Zhong ◽

Dong Sun ◽

Weian Huang ◽

Yunfeng Liu ◽

Zhengsong Qiu

Keyword(s):

High Temperature ◽

Drilling Fluid ◽

Hardness Test ◽

Drilling Fluids ◽

The Novel ◽

Potential Measurement ◽

Clay Particles ◽

Water Based ◽

Bulk Hardness ◽

Dispersion Test

In order to improve the inhibitive properties and high temperature resistance of shale inhibitor, cycloaliphatic amines were introduced as shale hydration inhibitors in water-based drilling fluids. Bulk hardness test, shale cuttings dispersion test, bentonite inhibition test and water adsorption test were carried out to characterize the inhibitive properties of the novel amines. Surface tension measurement, zeta potential measurement, XRD, contact angle test, SEM and TGA were performed to investigate the interaction between the cycloaliphatic amines and clay particles. The results indicated that cycloaliphatic amines exhibited superior inhibitive properties to the state of the art inhibitors. Moreover, the amines were high temperature resistant. The hydrophobic amine could intercalate into the clay gallery with monolayer orientation. The protonated ammonium ions neutralized the negatively charged surface. After adsorption, the hydrophobic segment covered the clay surface and provided a shell preventing the ingress of water.

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High temperature and high pressure rheological properties of high-density water-based drilling fluids for deep wells

Petroleum Science ◽

10.1007/s12182-012-0219-4 ◽

2012 ◽

Vol 9 (3) ◽

pp. 354-362 ◽

Cited By ~ 22

Author(s):

Fuhua Wang ◽

Xuechao Tan ◽

Ruihe Wang ◽

Mingbo Sun ◽

Li Wang ◽

...

Keyword(s):

High Pressure ◽

High Temperature ◽

Rheological Properties ◽

High Density ◽

Drilling Fluids ◽

Deep Wells ◽

Water Based

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Reduction of the Probability of Occurrence of Differential Pressure Sticking Through the Use of Diesel on Water Based Drilling Fluids

Enfoque UTE ◽

10.29019/enfoqueute.v10n1.366 ◽

2019 ◽

Vol 10 (1) ◽

pp. 77-88

Author(s):

David Esteban Almeida Campana ◽

Marco Loaiza ◽

Raul Valencia

Keyword(s):

Drilling Fluid ◽

Differential Pressure ◽

Drilling Fluids ◽

Reservoir Pressure ◽

Predictive Tool ◽

Mud Cake ◽

Pressure Tests ◽

Water Based ◽

Additional Barrier ◽

Bow Tie

The drilling campaign on Pad C of the Tiputini Field, located on the Oriente Basin, Ecuador, started with the first exploratory well TPTC-002. Pressure tests performed on the M1 sandstone of the Napo Formation determined that the average reservoir pressure (Pr) was 1921 psi. Ten months later, Pr averaged 846 psi. This increased the risk of differential pressure sticking, event that indeed occurred while drilling the well TPTC-016. By using the “Bow-Tie” methodology as a predictive tool to analyze risks, and taking into account the preliminary studies that describe this phenomena, a solution was found for stablishing an additional barrier with the use of diesel on the water-based drilling fluid. Diesel was used in order to extend the ‘half value time’ and to decrease the friction coefficient between the mud cake and pipe.

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Improving the Performance of Drilling Fluid Using Lignite Nano Particles

Association of Arab Universities Journal of Engineering Sciences ◽

10.33261/jaaru.2019.26.1.013 ◽

2019 ◽

Vol 26 (1) ◽

pp. 100-105

Author(s):

Ghufran Falih ◽

Nada S. Al-Zubaidi ◽

Asawer A. Al-Wasiti

Keyword(s):

High Temperature ◽

Salt Water ◽

Drilling Fluid ◽

Nano Particles ◽

Drilling Fluids ◽

Mud Cake ◽

Different Temperatures ◽

Good Filtration ◽

Water Base ◽

Nanoparticle Additives

The effect of lignite on the filtration characteristics of water base mud was studied at low and high temperature. Recently, the nanoparticle additives are studied and investigated as alternative additives due to its stability during drilling even at high-temperature and high-pressure (HTHP) conditions. In this study the effect of nano particles size of Lignite on filtrate volume and mud cake thickness was investigated , at different weights (0.01, 0.05, 0.07, 0.1, and 0.2) gm, in (API WBM, Polymer mud, DURA THERM mud, and Saturated Salt Water mud) and different temperatures (35, 75, and 100) oC. The results show that most tests provided a very good filtration control for the used drilling fluids at 100 oC. Better performances were observed in polymer and Saturated Salt Water mud at 100 oC with Lignite concentration of 0.01 gm and 0.1 gm, and filtrate volume reduction 52.5 % and 60 % respectively.

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Synthesis of a Novel Filtrate Reducer and Its Application in Water-Based Drilling Fluid for Ultra-High-Temperature Reservoirs

Geofluids ◽

10.1155/2021/7643826 ◽

2021 ◽

Vol 2021 ◽

pp. 1-11

Author(s):

Dongyu Qiao ◽

Zhongbin Ye ◽

Lei Tang ◽

Yiping Zheng ◽

Xindong Wang ◽

...

Keyword(s):

Particle Size ◽

High Temperature ◽

Adsorption Capacity ◽

Fresh Water ◽

Drilling Fluid ◽

Salt Resistance ◽

Fluid Loss ◽

Drilling Fluids ◽

Water Based ◽

Water Base

The high-temperature stability and filtration property controlling of ultra-high-temperature water-based drilling fluids is a worldwide problem. To resolve this problem, a high-temperature-resistant quaternary copolymer (HTRTP) was synthesized based on molecular structure optimization design and monomer optimization. The physical and chemical properties were characterized by infrared spectroscopy, thermal weight, and spectrophotometry, and their temperature and salt resistance was evaluated in different drilling fluids, combined with adsorption, particle size analysis, and stability test. The results show that the thermal stability of HTRTP is very strong, and the initial temperature of thermal decomposition is above 320°C. The salt resistance of HTRTP is more than 162 g/L, and the calcium resistance is more than 5000 mg/L, which is equivalent to the foreign temperature-resistant polymer DCL-a, and is superior to the domestic metal ion viscosity increasing fluid loss agent PMHA-II for drilling fluids. It has excellent high-temperature resistance (245°C) and fluid loss reduction effect in fresh water base mud, fresh water weighted base mud, saturated brine base mud, and composite salt water base mud, which is better than foreign DCL-a (245°C) and domestic PMHA (220°C). The adsorption capacity of HTRTP on clay particles is large and firm, and the adsorption capacity changes little under the change of chemical environment and temperature. Both before and after HTRTP aging (245°C/16 h), the permeability of filter cake can be significantly reduced and its compressibility can be improved. By optimizing the particle size gradation of the drilling fluid and enhancing the colloid stability of the system, HTRTP can improve the filtration building capacity of the drilling fluid and reduce the filtration volume. The development of antithermal polymer provides a key treatment agent for the study of anti-high-temperature-resistant saline-based drilling fluid.

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Improvement of Rheological and Filtration Properties of Water-Based Drilling Fluids Using Bentonite-Hydrothermal Carbon Nanocomposites Under the Ultra-High Temperature and High Pressure Conditions

10.2118/205539-ms ◽

2021 ◽

Author(s):

Hanyi Zhong ◽

Ying Guan ◽

Zhengsong Qiu ◽

Jie Feng ◽

Wenlei Liu ◽

...

Keyword(s):

High Pressure ◽

High Temperature ◽

Hydrothermal Reaction ◽

Drilling Fluid ◽

Drilling Fluids ◽

Deep Drilling ◽

Carbon Nanocomposites ◽

Water Based ◽

Filtration Properties ◽

Oil Gas

Abstract With the depletion of the conventional shallow oil/gas reservoirs and the increasing demand for oil and gas, deep drilling become more and more essential to extract the oil/gas from deep formations. However, deep drilling faces many complex challenges. One of the complexities is the degradation of polymers and flocculation of bentonite particles, leading to hardly control the rheological and filtration properties of water-based drilling fluids, especially under ultra-high temperature and high pressure (HTHP) conditions. Therefore, an experimental investigation is performed to study how bentonite-hydrothermal carbon nanocomposites will influence the rheological and filtration properties of water-based drilling fluids under ultra-HTHP conditions. Bentonite-hydrothermal carbon nanocomposites are proposed as non-polymer additives to solve the ultra-HTHP challenge in water-based drilling fluid. The nanocomposites are synthesized by facile hydrothermal reaction, in which biomass starch and sodium bentonite are used as the precursor and template, respectively. In this study, the effect of the nanocomposites on the rheology and filtration properties of water-based drilling fluid are investigated before and after hot rolling at 220 °C and 240 °C. The structure characterization indicates that carbon nanospheres can successfully deposit on the bentonite surface after hydrothermal reaction and finally form as nanocomposites. The elemental carbon content, zeta potential and particle size distribution of the nanocomposites could be adjusted according to the reaction conditions. After thermal aging at 220 °C and 240 °C, addition of nanocomposites can improve the rheological properties significantly where a stable and minor change of rheological properties is observed, which is desirable for ultra-HTHP drilling. Regarding filtration control, after adding 1.0 wt% nanocomposite materials, the filtration loss is reduced by 41% and 44% respectively after aging at 220 °C and 240 °C, which is better than the conventional natural materials that lose their function in this case. The identification of microstructure shows that the hydrothermal reaction endows nanocomposites with a unique surface morphology and an improved surface charge density. The interaction between nanocomposites and bentonite particles forms a rigid connection network, which is the main mechanism to facilitate effective rheology and filtration control under ultra-HTHP conditions. The green and facile synthetic routes and environmentally friendly features of the nanocomposites, coupled with the excellent performance in ultra-HTHP rheology and filtration control, indicate that the nanocomposites have a high promise for water-based drilling fluid in ultra-HTHP drilling. Moreover, it provides a new way to design high performance additives with high temperature stability.

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Rheological Properties of Water-Based Drilling Fluids in Deep Offshore Conditions

Volume 8: Polar and Arctic Sciences and Technology; Petroleum Technology ◽

10.1115/omae2019-96719 ◽

2019 ◽

Author(s):

Qian Ding ◽

Baojiang Sun ◽

Zhiyuan Wang ◽

Yonghai Gao ◽

Yu Gao ◽

...

Keyword(s):

High Pressure ◽

High Temperature ◽

Low Temperature ◽

Rheological Properties ◽

Apparent Viscosity ◽

Drilling Fluid ◽

Plastic Viscosity ◽

Drilling Fluids ◽

Water Based ◽

Temperature And Pressure

Abstract In deep-water drilling, the drilling fluid is affected by the alternating temperature field derived from the low temperature of the seawater and the high temperature of the formation. The complicated wellbore temperature and pressure environments make the prediction of rheological properties of the drilling fluid difficult. In this study, the rheological properties of water-based drilling fluid in full temperature and pressure range of deep-water conditions were tested from 2 to 150 °C (35.6 to 302 °F) and 0.1 to 70 MPa (14.5 to 10000psi). The experiment was carried out by the OFI130-77 high temperature and high pressure rheometer. The experimental data were processed by multiple regression analysis method, and the mathematical model for predicting the apparent viscosity, plastic viscosity and yield point of water-based drilling fluid under high temperature and high pressure conditions was established. The experimental results show that when the temperature is lower than 65 °C (149 °F), the apparent viscosity and plastic viscosity of the water-based drilling fluid decrease significantly with increasing temperature. When the temperature is higher than 65 °C (149 °F), the apparent viscosity and plastic viscosity decrease slowly. Under low temperature conditions, the effect of pressure on the apparent viscosity and plastic viscosity of water-based drilling fluids is relatively significant. The calculated values of the prediction model have a good agreement with the experimental measurements. Compared with the traditional model, this prediction model has a significant improvement in the prediction accuracy in the low temperature section, which can provide a calculation basis for on-site application of deepwater drilling fluid.

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