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

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.

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

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.

scholarly journals Lubricating Properties of Water-Based Drilling Fluid Improvement Using Lignite NPs as well as Their Effect on Rheological and Filtration Properties

2019 ◽  
Vol 26 (1) ◽  
pp. 81-88
Author(s):  
Massara Salam ◽  
Nada S. Al-Zubaidi ◽  
Asawer A. Al-Wasiti
Keyword(s):  
Oil And Gas ◽  
Drilling Fluid ◽  
Drill String ◽  
Filter Press ◽  
Drilling Fluids ◽  
Well Drilling ◽  
Water Based ◽  
Frictional Forces ◽  
Filtration Properties ◽  
Lubricating Properties

In the process of drilling directional, extended-reach, and horizontal wells, the frictional forces between the drill string and the wellbore or casing can cause severe problems including excessive torque which is one of the most important problems during drilling oil and gas well. Drilling fluid plays an important role by reducing these frictional forces. In this research, an enhancement of lubricating properties of drilling fluids was fundamentally examined by adding Lignite NPs into the water-based drilling fluid. Lubricity, Rheology and filtration properties of water-based drilling fluid were measured at room temperature using OFITE EP and Lubricity Tester, OFITE Model 900 Viscometer, and OFITE Low-Pressure Filter Press, respectively. Lignite NPs were added at different concentrations (0.05 %, 0.1 %, 0.2 %, 0.5 %, and 1 %) by weight into water-based drilling fluid. Lignite NPs showed good reduction in COF of water-based drilling fluid. The enhancement was increased with increasing Lignite NPs concentrations; 23.68%, 35.52%, and 45.3 % reduction in COF were obtained by adding 0.2%, 0.5%, and 1% by weight Lignite NPs concentration, respectively.

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

2015 ◽  
Vol 8 (1) ◽  
pp. 19-27 ◽  
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.

scholarly journals Enhancing the Stability of Invert Emulsion Drilling Fluid for Drilling in High-Pressure High-Temperature Conditions

Energies ◽  
2018 ◽  
Vol 11 (9) ◽  
pp. 2393 ◽  
Author(s):  
Salaheldin Elkatatny
Keyword(s):  
High Pressure ◽  
High Temperature ◽  
Rheological Properties ◽  
Drilling Fluid ◽  
Electrical Stability ◽  
Dynamic Conditions ◽  
High Pressure High Temperature ◽  
Invert Emulsion ◽  
The Stability ◽  
Filtration Properties

Drilling in high-pressure high-temperature (HPHT) conditions is a challenging task. The drilling fluid should be designed to provide high density and stable rheological properties. Barite is the most common weighting material used to adjust the required fluid density. Barite settling, or sag, is a common issue in drilling HPHT wells. Barite sagging may cause many problems such as density variations, well-control problems, stuck pipe, downhole drilling fluid losses, or induced wellbore instability. This study assesses the effect of using a new copolymer (based on styrene and acrylic monomers) on the rheological properties and the stability of an invert emulsion drilling fluid, which can be used to drill HPHT wells. The main goal is to prevent the barite sagging issue, which is common in drilling HPHT wells. A sag test was performed under static (vertical and 45° incline) and dynamic conditions in order to evaluate the copolymer’s ability to enhance the suspension properties of the drilling fluid. In addition, the effect of this copolymer on the filtration properties was performed. The obtained results showed that adding the new copolymer with 1 lb/bbl concentration has no effect on the density and electrical stability. The sag issue was eliminated by adding 1 lb/bbl of the copolymer to the invert emulsion drilling fluid at a temperature >300 °F under static and dynamic conditions. Adding the copolymer enhanced the storage modulus by 290% and the gel strength by 50%, which demonstrated the power of the new copolymer to prevent the settling of the barite particles at a higher temperature. The 1 lb/bbl copolymer’s concentration reduced the filter cake thickness by 40% at 400 °F, which indicates the prevention of barite settling at high temperature.

Prediction of High-Pressure/High-Temperature Rheological Properties of Drilling Fluids from the Viscosity Data Measured on a Coaxial Cylinder Viscometer

SPE Journal ◽  
2021 ◽  
pp. 1-22
Author(s):  
Sidharth Gautam ◽  
Chandan Guria ◽  
Laldeep Gope
Keyword(s):  
High Pressure ◽  
High Temperature ◽  
Shear Viscosity ◽  
Drilling Fluid ◽  
Viscosity Model ◽  
Drilling Fluids ◽  
Viscosity Data ◽  
Monitoring And Control ◽  
High Pressure High Temperature ◽  
Proposed Model

Summary Determining the rheology of drilling fluid under subsurface conditions—that is, pressure > 103.4 MPa (15,000 psi) and temperature > 450 K (350°F)—is very important for safe and trouble-free drilling operations of high-pressure/high-temperature (HP/HT) wells. As the severity of HP/HT wells increases, it is challenging to measure downhole rheology accurately. In the absence of rheology measurement tools under HP/HT conditions, it is essential to develop an accurate rheological model under extreme conditions. In this study, temperature- and pressure-dependence rheology of drilling fluids [i.e., shear viscosity, apparent viscosity (AV), and plastic viscosity (PV)] are predicted at HP/HT conditions using the fundamental momentum transport mechanism (i.e., kinetic theory) of liquids. Drilling fluid properties (e.g., density, thermal decomposition temperature, and isothermal compressibility), and Fann® 35 Viscometer (Fann Instrument Corporation, Houston, USA) readings at surface conditions, are the only input parameters for the proposed HP/HT shear viscosity model. The proposed model has been tested using 26 different types of HP/HT drilling fluids, including water, formate, oil, and synthetic oil as base fluids. The detailed error and the sensitivity analysis have been performed to demonstrate the accuracy of the proposed model and yield comparative results. The proposed model is quite simple and may be applied to accurately predict the rheology of numerous drilling fluids. In the absence of subsurface rheology under HP/HT conditions, the proposed viscosity model may be used as a reliable soft-sensor tool for the online monitoring and control of rheology under downhole conditions while drilling HP/HT wells.

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

2012 ◽  
Vol 9 (3) ◽  
pp. 354-362 ◽  
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

scholarly journals Study on the Rheological Properties of Ultra-High Temperature CGA Drilling Fluids

2021 ◽  
Author(s):  
Wenxi Zhu ◽  
Xiuhua Zheng
Keyword(s):  
High Temperature ◽  
Rheological Properties ◽  
High Temperatures ◽  
Drilling Fluid ◽  
Drilling Fluids ◽  
Underbalanced Drilling ◽  
Deep Wells ◽  
Colloidal Gas Aphron ◽  
Oil Gas ◽  
Ultra High Temperature

Colloidal gas aphron (CGA) drilling fluids are a kind of environmentally-friendly underbalanced drilling technique, which has attracted more attention in depleted reservoirs and other low-pressure areas. With the shortage of global oil/gas resources, drilling has gradually shifted to high-temperature and deep wells. Hence, a study on the ultra-high temperature rheology properties of CGA fluids is lacking and urgently needed. In this study, a novel CGA drilling fluid system was prepared by modified starch and amino acid surfactant, and rheological properties after 120-300°C aged was investigate. Results show that: (1) Herschel-Bulkley model is the preferred model to predict CGA drilling fluid at ultra-high temperatures; (2) It was proved that CGA drilling fluid is a high-quality drilling fluid with extremely high value of LSRV and shear thinning property within 280°C. Compared to the traditional XG-based CGA drilling fluid, the improvement of LSRV at ultra-high temperatures is a significant advantage of EST-based CGA drilling fluid which is conducive to carrying cuttings and sealing formation pores.

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

Geofluids ◽  
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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