The Effect of Various Polymers and Salts on Borehole and Cutting Stability in Water-Base Shale Drilling Fluids

In this paper, several ultrafine particles were prepared and characterized, then the performance of drilling fluids were evaluated after ultrafine particles were added in water base drilling fluids. The viscosity property of drilling fluids were increased, however, filtration reduction could not be strictly controlled. All filtration volume was difficult to control just like common ultrafine calcium carbonate unless some polymers could be used. Titanium dioxide and zinc dioxide could be used as substitutes of calcium carbonate in drilling fluids.

Download Full-text

A New Technique to Determine the Equivalent Viscosity of Drilling Fluids Under High Temperatures and Pressures

Society of Petroleum Engineers Journal ◽

10.2118/2384-pa ◽

1970 ◽

Vol 10 (01) ◽

pp. 33-40 ◽

Cited By ~ 10

Author(s):

B.K. Sinha

Keyword(s):

High Temperatures ◽

Low Temperatures ◽

Relative Viscosity ◽

Test Fluid ◽

Drilling Fluids ◽

Sample Container ◽

Invert Emulsion ◽

Temperature And Pressure ◽

Water Base ◽

Time Required

Abstract Knowledge concerning the behavior of drilling fluids under wellbore conditions is very desirable, and experimental results have shown that the extent to which the flow properties of drilling fluids are affected by high temperatures and pressures cannot be predicted by standard API pressures cannot be predicted by standard API tests. A Fann consistometer (Model 5S-TDL) is modified to obtain the experimental data reported in this study. Data obtained from the Fann viscometer Model 50 at elevated temperatures have been included to supplement the information derived from the modified Fann consistometer. Newtonian fluids of known viscosities are used in calibrating the modified consistometer. The technique followed here keeps the sample temperature constant and allows the pressure to vary at each desired temperature level. The equivalent viscosities of both laboratory-prepared and field muds of different densities have been obtained at temperatures up to 500 deg F and pressures up to 20,000 psi. The objective of this study is to show that the modified consistometer can give much more information concerning the flow behavior of muds under wellbore conditions than that derived in the past. It can show the pressure and temperature conditions under which the tendency to thicken begins, the gradual thickening, and also the conditions at which the mud completely gels and loses its fluidity. The study shows that both temperature and pressure affect the equivalent viscosity of invert pressure affect the equivalent viscosity of invert emulsion muds. The effect of pressure is very pronounced at low temperatures. Compared to the pronounced at low temperatures. Compared to the invert emulsion muds, the equivalent viscosity of water base muds is not affected to the same extent by temperature and pressure. Temperature is the dominating variable tin case of water base muds. However, the effect of pressure on the equivalent viscosity of water base muds seems to depend on composition and temperature of the system. Introduction Kennedy and Crawford designed and patented the consistometer to test the setting time of cement slurries. This consistometer as manufactured and later improved by Fann. Chisholm et al. adapted the first Fann consistometer for evaluating drilling fluids under wellbore conditions in 1961; their study was later continued by Cox and Pfleger. Weintritt and Hughes used a similar consistometer with a different recording device. They measured the relative viscosity of drilling fluids in seconds and pointed out the usefulness of this data when used with viscometric and fluid loss data. They applied the term "relative viscosity" to the time required for the bob to complete movement in one direction: it is not a ratio of two viscosities. In spite of its wide usage, no standard testing procedure has been established by the industry to procedure has been established by the industry to obtain correlative data. A consistometer similar to the ones mentioned above, has been further modified and used in this study along the Fann viscometer Model 50. EQUIPMENT AND CALIBRATION Fig.1 is a section diagram of the consistometer. The consistency or equivalent viscosity of a test fluid is measured by electrically timing the movement of a soft iron bob that is magnetically pulled up and down in the sample container. Sound pulled up and down in the sample container. Sound signals created by the impingement of the bob inside the container are picked up by a microphone and transmitted to a recorder. The time required to pull the bob through a test fluid is a function of its pull the bob through a test fluid is a function of its consistency. The test fluid can be subjected to pressures up to 20,000 psi and temperatures up pressures up to 20,000 psi and temperatures up to 500 deg F. SPEJ p. 33

Download Full-text

High-Temperature Flow Properties of Water-Base Drilling Fluids

Journal of Petroleum Technology ◽

10.2118/1698-pa ◽

1967 ◽

Vol 19 (08) ◽

pp. 1074-1080 ◽

Cited By ~ 30

Author(s):

Max R. Annis

Keyword(s):

High Temperature ◽

Drilling Fluids ◽

Flow Properties ◽

Water Base

Download Full-text

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.

Download Full-text

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.

Download Full-text