scholarly journals Organic-Sulfonate Functionalized Graphene as a High Temperature Lubricant for Efficient Antifriction and Antiwear in Water-Based Drilling Fluid

2021 ◽  
Author(s):  
Xiao Tian ◽  
Ningning Song ◽  
Guangbin Yang ◽  
Changhua Zhou ◽  
Shengmao Zhang ◽  
...  
Keyword(s):  
High Temperature ◽  
Performance Test ◽  
Drilling Fluid ◽  
Sodium Dodecylbenzene Sulfonate ◽  
Drilling Fluids ◽  
Sulfonate Group ◽  
Test Results ◽  
Wear Properties ◽  
Dodecylbenzene Sulfonate ◽  
Deposited Film

Abstract The lubricity of drilling fluid resistant to high-temperature over 200℃ is still one of the technological breakthroughs. In this study, the graphene modified with sodium dodecylbenzene sulfonate (SDBS) was selected as a resistant to high-temperature lubricant. Our results show that the drilling fluids have high stability after aging at 240°C with the assistance of the SDBS/graphene. Excitingly, the tribological performance test results revealed that the SDBS/graphene exert excellent anti-friction and anti-wear properties. Compared with the base slurry, the friction coefficient and wear rate of the SDBS/graphene slurry are reduced by 76% and 59%, respectively. The deposited film composed of graphene, Al2O3, SiO2, Fe2O3, FeSO4 actualized the protection of the sliding contact zone, proving that the sulfonate group on the SDBS/graphene contributed to prompt the deposition of the graphene and bentonite and then enhanced tribological properties of the drilling fluids. Overall, the graphene modified with SDBS is expected to solve the difficulty to form effective deposited film and poor lubricity of the drilling fluid under high-temperature.

scholarly journals Experimental Investigation of the Rheological Behavior of an Oil-Based Drilling Fluid with Rheology Modifier and Oil Wetter Additives

Molecules ◽  
2021 ◽  
Vol 26 (16) ◽  
pp. 4877
Author(s):  
Mobeen Murtaza ◽  
Sulaiman A. Alarifi ◽  
Muhammad Shahzad Kamal ◽  
Sagheer A. Onaizi ◽  
Mohammed Al-Ajmi ◽  
...  
Keyword(s):  
High Temperature ◽  
Zeta Potential ◽  
Hot Rolling ◽  
Emulsion Stability ◽  
Drilling Fluid ◽  
Temperature Tolerance ◽  
Fluid Loss ◽  
Drilling Fluids ◽  
Before And After ◽  
Rheology Modifier

Drilling issues such as shale hydration, high-temperature tolerance, torque and drag are often resolved by applying an appropriate drilling fluid formulation. Oil-based drilling fluid (OBDF) formulations are usually composed of emulsifiers, lime, brine, viscosifier, fluid loss controller and weighting agent. These additives sometimes outperform in extended exposure to high pressure high temperature (HPHT) conditions encountered in deep wells, resulting in weighting material segregation, high fluid loss, poor rheology and poor emulsion stability. In this study, two additives, oil wetter and rheology modifier were incorporated into the OBDF and their performance was investigated by conducting rheology, fluid loss, zeta potential and emulsion stability tests before and after hot rolling at 16 h and 32 h. Extending the hot rolling period beyond what is commonly used in this type of experiment is necessary to ensure the fluid’s stability. It was found that HPHT hot rolling affected the properties of drilling fluids by decreasing the rheology parameters and emulsion stability with the increase in the hot rolling time to 32 h. Also, the fluid loss additive’s performance degraded as rolling temperature and time increased. Adding oil wetter and rheology modifier additives resulted in a slight loss of rheological profile after 32 h and maintained flat rheology profile. The emulsion stability was slightly decreased and stayed close to the recommended value (400 V). The fluid loss was controlled by optimizing the concentration of fluid loss additive and oil wetter. The presence of oil wetter improved the carrying capacity of drilling fluids and prevented the barite sag problem. The zeta potential test confirmed that the oil wetter converted the surface of barite from water to oil and improved its dispersion in the oil.

Automated Approaches Determine Solids Content in Drilling and Completions Fluids

2021 ◽  
Vol 73 (11) ◽  
pp. 51-52
Author(s):  
Chris Carpenter
Keyword(s):  
Elevated Temperatures ◽  
Drilling Fluid ◽  
Technical Conference ◽  
Drilling Fluids ◽  
Test Results ◽  
University Of Texas ◽  
Safety Issues ◽  
Recommended Practices ◽  
Solids Content ◽  
The University

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 201368, “Automated Solids-Content Determination in Drilling and Completions Fluids,” by Sercan Gul, SPE, Ali Karimi Vajargah, and Eric van Oort, SPE, The University of Texas at Austin, et al., prepared for the 2020 SPE Annual Technical Conference and Exhibition, originally scheduled to be held in Denver, 5–7 October. The paper has not been peer reviewed. Monitoring of low- and high-gravity-solids (LGS and HGS) content and maintaining these at ideal levels is essential for optimal drilling fluid performance, efficient hole cleaning and equivalent-circulating-density management, and prevention of failures of surface and downhole equipment during drilling. LGS and HGS monitoring in the field is currently accomplished using the API retort-kit measurement, which has certain drawbacks and is difficult to automate. In the complete paper, two new approaches are investigated to automate the LGS and HGS content measurements of drilling fluids, which potentially can replace the retort test. Introduction The conventional way to characterize LGS and HGS in the field is by using a retort-kit measurement specified in API Recommended Practices 13B-1 and 13B-2. The longevity of these tests is testament to the effectiveness of the API standards and the tests themselves in providing useful and practical field guidance. Despite their evident success, however, various downsides exist in current solids-content-testing methods. Retort-kit measurements present the following issues: - Difficulty in obtaining accurate and repeatable test results - Safety issues associated with laboratory testing at elevated temperatures (over 930°F) - Interpretive bias issues associated with test results, including the potential for deliberate manipulation of these results - Difficulty in automating the retort test for improved efficiency and safety The authors’ opinion is that automating antiquated API test protocols is not a useful practice. They write that a clean-slate approach would be better, in which a determination is made whether solids-content information can be provided in a novel and meaningful way using methods that deviate from standard API recommended practices. In the complete paper, the authors investigate a machine-learning (ML) and data-analytics method for this purpose in combination with a novel inline X-ray fluorescence (XRF) measurement method.

Improving the rheological properties of water-based calcium bentonite drilling fluids using water-soluble polymers in high temperature applications

2021 ◽  
Vol 0 (0) ◽  
Author(s):  
Jinliang Liu ◽  
Fengshan Zhou ◽  
Fengyi Deng ◽  
Hongxing Zhao ◽  
Zhongjin Wei ◽  
...  
Keyword(s):  
High Temperature ◽  
Rheological Properties ◽  
Apparent Viscosity ◽  
Drilling Fluid ◽  
Shear Thickening ◽  
Water Soluble ◽  
Drilling Fluids ◽  
Drilling Depth ◽  
Filtration Loss ◽  
Calcium Bentonite

Abstract Most of bentonite used in modern drilling engineering is physically and chemically modified calcium bentonite. However, with the increase of drilling depth, the bottom hole temperature may reach 180 °C, thus a large amount of calcium bentonite used in the drilling fluid will be unstable. This paper covers three kinds of calcium bentonite with poor rheological properties at high temperature, such as apparent viscosity is greater than 45 mPa·s or less than 10 mPa·s, API filtration loss is greater than 25 mL/30 min, which are diluted type, shear thickening type and low-shear type, these defects will make the rheological properties of drilling fluid worse. The difference is attributed to bentonite mineral composition, such as montmorillonite with good hydration expansion performance. By adding three kinds of heat-resistant water-soluble copolymers Na-HPAN (hydrolyzed polyacrylonitrile sodium), PAS (polycarboxylate salt) and SMP (sulfomethyl phenolic resin), the rheological properties of calcium bentonite drilling fluids can be significantly improved. For example, the addition of 0.1 wt% Na-HPAN and 0.1 wt% PAS increased the apparent viscosity of the XZJ calcium bentonite suspension from 4.5 to 19.5 mPa·s at 180 °C, and the filtration loss also decreased from 20.2 to 17.8 mL.

Well Clean-Up Using a Combined Thermochemical/Chelating Agent Fluids

2019 ◽  
Vol 141 (10) ◽  
Author(s):  
Mohamed Mahmoud
Keyword(s):  
High Temperature ◽  
Filter Cake ◽  
Oil And Gas ◽  
Drilling Fluid ◽  
Chelating Agent ◽  
Drilling Fluids ◽  
Gas Wells ◽  
Oil And Gas Wells ◽  
Different Types ◽  
Cake Removal

The well clean-up process involves the removal of impermeable filter cake from the formation face. This process is essential to allow the formation fluids to flow from the reservoir to the wellbore. Different types of drilling fluids such as oil- and water-based drilling fluids are used to drill oil and gas wells. These drilling fluids are weighted with different weighting materials such as bentonite, calcium carbonate, and barite. The filter cake that forms on the formation face consists mainly of the drilling fluid weighting materials (around 90%), and the rest is other additives such as polymers or oil in the case of oil-base drilling fluids. The process of filter cake removal is very complicated because it involves more than one stage due to the compatibility issues of the fluids used to remove the filter cake. Different formulations were used to remove different types of filter cake, but the problem with these methods is the removal efficiency or the compatibility. In this paper, a new method was developed to remove different types of filter cakes and to clean-up oil and gas wells after drilling operations. Thermochemical fluids that consist of two inert salts when mixed together will generate very high pressure and high temperature in addition to hot water and hot nitrogen. These fluids are sodium nitrate and ammonium chloride. The filter cake was formed using barite and calcite water- and oil-based drilling fluids at high pressure and high temperature. The removal process started by injecting 500 ml of the two salts and left for different time periods from 6 to 24 h. The results of this study showed that the newly developed method of thermochemical removed the filter cake after 6 h with a removal efficiency of 89 wt% for the barite filter cake in the water-based drilling fluid. The mechanisms of removal using the combined solution of thermochemical fluid and ethylenediamine tetra-acetic acid (EDTA) chelating agent were explained by the generation of a strong pressure pulse that disturbed the filter cake and the generation of the high temperature that enhanced the barite dissolution and polymer degradation. This solution for filter cake removal works for reservoir temperatures greater than 100 °C.

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.

Effect of Hydrophobic Iron Oxide Nanoparticles on the Properties of Oil-Based Drilling Fluid

2020 ◽  
Vol 143 (4) ◽  
Author(s):  
Muhammad Awais Ashfaq Alvi ◽  
Mesfin Belayneh ◽  
Kjell Kåre Fjelde ◽  
Arild Saasen ◽  
Sulalit Bandyopadhyay
Keyword(s):  
High Temperature ◽  
Iron Oxide ◽  
Base Fluid ◽  
Drilling Fluid ◽  
Iron Pentacarbonyl ◽  
Inert Atmosphere ◽  
Drilling Fluids ◽  
Oil Well ◽  
The Coefficient Of Friction ◽  
Filtrate Loss

Abstract Lately, nanoparticles (NPs) have shown the potential to improve the performance of oil well fluids significantly. Several studies have reported the ability of NPs to produce improved properties of both water and oil-based drilling fluids. In this study, hydrophobic iron oxide NPs were synthesized by thermal decomposition of iron pentacarbonyl in an inert atmosphere, and its performance was tested in the oil-based drilling fluid with 90/10 oil-to-water ratio (base fluid). Oil-based drilling fluids treated with nanofluids were formulated by adding 0.5 wt% and 1.0 wt% iron oxide NPs in hexane solution to the base drilling fluid. The base fluid and the nanofluid-treated drilling fluids were evaluated by characterizing their rheological properties at different temperatures, viscoelastic properties, lubricity, filtrate loss, static and dynamic settling, and separation properties. Results showed that 0.5 wt% iron oxide dispersed in hexane reduced the high pressure high temperature (HPHT) filtrate loss by 70%, filter cake thickness by 55%, and the coefficient of friction by 39%. Moreover, the nanofluid based drilling fluid reduced the free oil layer caused by syneresis during aging at high temperature by 16.3% compared to the base fluid. This study has shown that hydrophobic iron oxide NPs have the potential to improve the properties of oil-based drilling fluid.

Borehole Temperature Modelling in High Temperature Drilling Environment Based on Heat Transfer Laws

2019 ◽  
Author(s):  
Abhijeet D. Chodankar ◽  
Cheng-Xian Lin
Keyword(s):  
Heat Transfer ◽  
High Temperature ◽  
Drilling Fluid ◽  
Drill String ◽  
Wellbore Stability ◽  
Heat Transfer Analysis ◽  
Drilling Fluids ◽  
Concentric Cylinder ◽  
Composite Wall ◽  
Borehole Temperature

Abstract High temperature drilling environment has a drastic effect on drilling fluids, wellbore stability, and drilling system components. It has been observed that drilling fluids displace conventional halide based fluids in High Pressure and High Temperature (HPHT) wells leading to corrosion and environmental hazards, while wellbore strengthens further as a result of an increase in fracture initiation pressure in high temperature environment. However, it seriously damages the downhole tools like sensors, elastomer dynamic seals, lithium batteries, electronic component and boards leading to increases in cost and non-productive time. The main objective of this paper is to present an analytical borehole temperature model based on classical heat transfer laws in a high temperature drilling environment. The borehole is modelled using two approaches: composite wall and concentric cylinders. The composite wall and concentric cylinder approaches consist layers of geological formations, drilling fluids outside the drill string, drill string, and drilling fluid inside the drill string. Temperature, heat transfer coefficient, and heat transfer variations along the borehole layers are determined using the derived analytical solutions and tested for different drilling fluid types, air drilling environment, and different drill string materials. The results of composite wall and concentric cylinder models are obtained by using the input field temperatures data in the geological formation and inner annulus of drill pipe to determine the borehole temperature profile in HPHT wells. Therefore, a thorough borehole heat transfer analysis will help in wellbore stability, drilling fluid selection, corrosion control, and optimal placement and material selection of drilling components in HPHT drilling environments.

Performance Test Results of a Precision Data Acquisition and Control Platform for 200°C+ High Temperature Environments

2018 ◽  
Vol 2018 (HiTEC) ◽  
pp. 000103-000111
Author(s):  
Jeff Watson ◽  
Maithil Pachchigar ◽  
Ross Bannatyne ◽  
Clay Merritt ◽  
Christopher Conrad ◽  
...  
Keyword(s):  
High Temperature ◽  
Low Power ◽  
Data Acquisition ◽  
Performance Test ◽  
Rapid Development ◽  
Sensor Data ◽  
Harsh Environment ◽  
Test Results ◽  
Precision Data ◽  
And Control

Abstract In recent years there has been an increasing selection of commercially available electronic components specified for very high temperature (200C+) operation, driven by the needs of harsh-environment applications such as oil and gas exploration/production, aerospace, heavy industrial, and automotive. However, there remains a significant technical challenge to integrate these components into reliable, high performance systems. We previously presented a complete reference design of a precision multichannel sensor data acquisition and control system rated to 200C, including characterized hardware, firmware, and software. The design is based around low power 16 bit SAR ADCs and an ARM® Cortex®-M0 processor and is optimized for high resolution and high throughput measurements while maintaining low power and a small footprint. In this paper we present the test results of this system over temperature. The reference platform is available off the shelf, including hardware design files, processor firmware source code, and PC software for data logging and display, providing engineers a rapid development tool for prototyping and a faster path to production for complex harsh-environment applications.

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.

Application of modified starch in high-temperature-resistant colloidal gas aphron (CGA) drilling fluids

2021 ◽  
Vol 0 (0) ◽  
Author(s):  
Wenxi Zhu ◽  
Xiuhua Zheng
Keyword(s):  
High Temperature ◽  
High Temperatures ◽  
High Performance ◽  
Oil And Gas ◽  
Elevated Temperatures ◽  
Drilling Fluid ◽  
Drilling Fluids ◽  
Modified Starch ◽  
Gas Reservoirs ◽  
Building Capability

Abstract Colloidal gas aphrons (CGA) are finding increasing application in depleted oil and gas reservoirs because of their distinctive characteristics. To overcome the limitations of its application in high-temperature drilling, a modified starch foams stabilizer WST with a temperature resistance of 160 °C was synthesized via radical polymerization. The chemical structure of WST was characterized by Fourier infrared spectroscopy and results showed that all three monomers acrylamide, 2-acrylamido-2-methyl-1-propane sulfonic acid, and N-vinylpyrrolidone have been grafted onto starch efficiently. Based on the microscopic observations, highly stable aphrons have been successfully generated in the WST-based CGA drilling fluids within 160 °C, and most aphrons lie in the range of 10–150 μm. WST can provide higher viscosity at high temperatures compared to xanthan gum, which helps to extend foam life and stability by enhancing the film strength and slowing down the gravity drainage. Results show that WST-CGA aged at elevated temperatures (120–160 °C) is a high-performance drilling fluid with excellent shear-thinning behavior, cutting carrying capacity, and filtration control ability. The significant improvement of filtration control and well-building capability at high temperatures is an important advantage of WST-CGA, which can be attributed to the enhancement of mud cake quality by WST.

Sign in / Sign up

Export Citation Format

Share Document