Application of Okra Mucilage for the Prevention of Shale Swelling

2021 ◽  
Author(s):  
Mobeen Murtaza ◽  
Zeeshan Tariq ◽  
Muhammad Shahzad Kamal ◽  
Muhammad Mahmoud ◽  
Dhafer Al Sheri
Keyword(s):  
Zeta Potential ◽  
Wellbore Stability ◽  
Experimental Investigations ◽  
Fluid Loss ◽  
Drilling Fluids ◽  
Atmospheric Conditions ◽  
Capillary Suction ◽  
Food Industries ◽  
Shale Formation ◽  
Loss Control

Abstract Maintain wellbore stability is a very critical aspect of the drilling operation. The unstable wellbore provides severe loss to the drilling operators in terms of time and money. One of the significant reasons for unstable wellbore occurs due to the expansion of shale formation. Several solutions are utilized to tackle the expansion of shales, such as salts, PHPA, silicates, and oil-based drilling fluids. There are limitations associated with these solutions, such as thermal instability, limited supply, unfriendly to the environment and marine life, etc. In this study, Okra mucilage has been introduced as a shale swelling inhibitor in drilling fluids. Okra is widely used in the medical and food industries as a viscosifier as it is abundantly available in tropical and subtropical regions. Okra powder has been used as a fluid loss control additive in the literature. The application of the Okra solution as a shale swelling inhibitor in drilling fluids was not investigated in the past. In this study, Okra mucilage was extracted from the Okra plant and used as shale swelling inhibitor. Three different concentrations (5, 10 & 20) vol% of Okra mucilage mixed solutions were used for linear swell test. The test was performed using a linear swell tester at atmospheric conditions for 24 hours on bentonite wafers. Further zeta potential, particles size and capillary suction timer test (CST) were conducted. The experimental study revealed that Okra mucilage reduced the swelling of bentonite. For instance, 10 and 20% of Okra mucilage solutions reduced the swelling by 36.8% and 50.5%, respectively. The Okra mucilage decreased the zeta potential of clay and increased its particle size. CST time decreased initial at low concentration and increased with concentration. Overall, experimental investigations suggested that Okra mucilage could be an alternate green shale inhibitor in drilling fluids without compromising other drilling fluids' properties.

First Use of Novel High Temperature Water-Based Reservoir Drilling Fluid to Access Depleted Deepwater Reserves

2021 ◽  
Author(s):  
Alexandra Clare Morrison ◽  
Conan King ◽  
Kevin Rodrigue
Keyword(s):  
High Temperature ◽  
Elevated Temperatures ◽  
Drilling Fluid ◽  
Synthetic Polymer ◽  
Wellbore Stability ◽  
Soluble Solids ◽  
Fluid Loss ◽  
Drilling Fluids ◽  
Flow Loop ◽  
Loss Control

Abstract A combination of divalent base brine and high wellbore temperature presents significant challenges for high density aqueous reservoir drilling fluids. Such systems traditionally use biopolymers as viscosifiers; however, they are subject to degradation at elevated temperatures. Non-aqueous drilling fluids are thermally stable but complete removal of the filtercake is challenging and this can lead to formation damage. This paper describes the qualification and first deepwater drilling application of a unique aqueous reservoir drilling fluid at temperatures above 320°F. A high-temperature divalent brine-based reservoir drilling fluid (HT-RDF) and a solids-free screen running fluid (SF-SRF) were designed, both utilizing the same novel synthetic polymer technology. Calcium bromide brine was selected for use to minimize the total amount of acid-soluble solids in the drilling fluid. A comprehensive qualification was undertaken examining parameters such as rheology performance across a range of temperatures, long-term stability, fluid loss under expected and stress conditions (16 hours at 356°F), production screen test (PST), and various fluid-fluid compatibility tests. Return permeability tests were conducted on the final formulations to validate their suitability for use. The synthetic polymer technology provided excellent rheology, suspension, and fluid loss control in the fluid systems designed in the laboratory. To prepare for field execution multiple yard mixes were performed to verify the laboratory results on a larger scale. Additionally, a flow loop system was utilized to evaluate fluid performance under simulated downhole temperature and pressure conditions before field deployment. The final high temperature drilling fluid as designed provided rheological properties that met the necessary equivalent circulating density (ECD) requirements while drilling the reservoir. The fluid loss remained extremely stable and there were no downhole losses despite the depleted nature of the wellbore. Production screens were run straight to total depth (TD) with no wellbore stability issues after a three-day logging campaign. High temperature aqueous reservoir drilling fluids have historically been limited by the lack of suitable viscosifiers and fluid loss control additives. This paper outlines the design, mixing and logistical considerations and field execution of a novel polymer-based reservoir drilling fluid.

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.

scholarly journals Laponite: a promising nanomaterial to formulate high-performance water-based drilling fluids

2020 ◽  
Author(s):  
Xian-Bin Huang ◽  
Jin-Sheng Sun ◽  
Yi Huang ◽  
Bang-Chuan Yan ◽  
Xiao-Dong Dong ◽  
...  
Keyword(s):  
High Performance ◽  
Drilling Fluid ◽  
Nitrogen Adsorption ◽  
Drill String ◽  
Wellbore Stability ◽  
Fluid Loss ◽  
Drilling Fluids ◽  
Mechanism Analysis ◽  
Water Based ◽  
Inhibition Performance

Abstract High-performance water-based drilling fluids (HPWBFs) are essential to wellbore stability in shale gas exploration and development. Laponite is a synthetic hectorite clay composed of disk-shaped nanoparticles. This paper analyzed the application potential of laponite in HPWBFs by evaluating its shale inhibition, plugging and lubrication performances. Shale inhibition performance was studied by linear swelling test and shale recovery test. Plugging performance was analyzed by nitrogen adsorption experiment and scanning electron microscope (SEM) observation. Extreme pressure lubricity test was used to evaluate the lubrication property. Experimental results show that laponite has good shale inhibition property, which is better than commonly used shale inhibitors, such as polyamine and KCl. Laponite can effectively plug shale pores. It considerably decreases the surface area and pore volume of shale, and SEM results show that it can reduce the porosity of shale and form a seamless nanofilm. Laponite is beneficial to increase lubricating property of drilling fluid by enhancing the drill pipes/wellbore interface smoothness and isolating the direct contact between wellbore and drill string. Besides, laponite can reduce the fluid loss volume. According to mechanism analysis, the good performance of laponite nanoparticles is mainly attributed to the disk-like nanostructure and the charged surfaces.

Thermal Stability of Starch- and Carboxymethyl Cellulose-Based Polymers Used in Drilling Fluids

1982 ◽  
Vol 22 (02) ◽  
pp. 171-180 ◽  
Author(s):  
David C. Thomas
Keyword(s):  
Thermal Stability ◽  
Thermal Degradation ◽  
Carboxymethyl Cellulose ◽  
Polymer Chains ◽  
Maximum Temperature ◽  
Fluid Loss ◽  
Drilling Fluids ◽  
Low Viscosity ◽  
The Stability ◽  
Loss Control

Abstract Starch- and cellulose-based polymers have been used to control water loss for many years. Thermal degradation of the polymers is the most important problem with their use. Representative starch and cellulose fluid loss reducers were tested for their thermal stability in mud systems. The thermal decomposition was found to be dependent on both exposure time and temperature. The rate of decomposition can be predicted using first-order reaction rate kinetics and the decomposition activation energy estimated for both polymer types. This technique allows the calculation of a polymer's usable lifetime at a given temperature. A table of half-lives (time for fluid loss to double) vs. exposure temperature is presented for both starch- and cellulose-based polymers. This paper discusses the results of the calculations and the method used to obtain the data. The method is generally applicable to any material used in drilling fluids that is subject to thermal degradation. Introduction Starch, carboxymethyl cellulose (CMC), and their derivatives frequently are used in drilling fluids as viscosifiers and fluid-loss reducers. Their general properties are well known because they have been used for properties are well known because they have been used for many years. One important area that has been neglected somewhat is the effect of exposure to various temperatures for varying lengths of time on fluid-loss reduction. Vendor literature quotes maximum temperature limits for starch from 200 to 250 degrees F (93 to 121 degrees C). This information is useful but is not sufficient for precise work. The length of exposure to a certain temperature bears strongly on a polymer's stability. For example, a standard pregelatinized starch might have an API fluid loss of 20 cm3 after exposure at 250 degrees F (121 degrees C) for 4 hours, while after 24 hours its fluid loss is greater than 80 cm3 and after 48 hours is 240 cm3. Some data may show that starch gave an acceptable high-temperature high-pressure (HTHP) fluid loss at 275 or 300 degrees F (135 or 149 degrees C). These data can be misleading because a HTHP fluid-loss test can be completed in an hour, while long-term aging at the same temperature will destroy the polymer. Similar comments can be made about cellulosic polymers except that the temperatures stated are about 50 degrees F (28 degrees C) higher.Starch- and cellulose-based polymers degrade thermally by the same mechanism. The polymer chains are broken, and the glucopyranose units are converted to other compounds. The decomposition rate can be determined by use of chemical kinetics methods. This paper describes experiments that determined the stability of these polymers at various temperatures using kinetic methods. Starch Chemistry Starch, as used in drilling fluids, is a powder that disperses readily in water to give a low-viscosity fluid that can be used to seal microfractures and prevent fluid loss. This starch has been processed after separation from corn, wheat, rice, or potatoes. "Pregelatinization" is a cooking process that ruptures the starch granules to release the constituent starch polymer molecules. Cooking at 140 to 212 degrees F (60 to 100 degrees C) destroys the outer structure of the granule, yielding a thick slurry, much like thickened gravy. This slurry is dried and milled, giving the product used in drilling fluids. This gelatinization process was done at the rig in early applications of starch to drilling fluids. Cooking of starch at the rig ended in the late 1930's to early 1940's with the availability of pregelatinized starches. There has been some recent interest in ungelatinized starches to provide a "time-release" source of starch for fluid-loss control. Such materials would be limited to relatively hot wells [about 200 degrees F (93 degrees C)] because the march granules must be broken down to release the starch molecule for fluid-loss control. SPEJ P. 171

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