Investigation of High-Temperature Fluid Loss Control Agents in Geothermal Drilling Fluids

1982 ◽  
Author(s):  
Leroy L. Carney ◽  
Necip Guven
Keyword(s):  
High Temperature ◽  
Fluid Loss ◽  
Drilling Fluids ◽  
Geothermal Drilling ◽  
Loss Control

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.

High Temperature Cementing: Fluid Loss Control Polymers Performance and Limitations

2016 ◽  
Author(s):  
A. Cadix ◽  
J. Wilson ◽  
W. Bzducha ◽  
J.-R. Gomez ◽  
A. Feuillette ◽  
...  
Keyword(s):  
High Temperature ◽  
Fluid Loss ◽  
Loss Control

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

scholarly journals Analyzing Cement Rheological Properties Using Different Additive Schemes at High Pressure and High Temperature Conditions

2020 ◽  
Vol 39 (3) ◽  
pp. 466-474
Author(s):  
Khalil Rehman Memon ◽  
Aftab Ahmed Mahesar ◽  
Shahzad Ali Baladi ◽  
Muhannad Talib Sukar
Keyword(s):  
High Pressure ◽  
High Temperature ◽  
Rheological Properties ◽  
Silica Fume ◽  
Gel Strength ◽  
Water Quantity ◽  
Fluid Loss ◽  
Cement Slurry ◽  
Three Samples ◽  
Loss Control

The experimental study was conducted on rheological properties in laboratory to measure the integrity of cement slurry. Three samples were used and analyzed at different parameters to check the elasticity of cement slurry. Additives with various concentrations, i.e. silica fume % BWOC (Present by Weight on Cement) (15, 17, 19 and 21), dispersant % Wt (Percent Weight) (0.21, 0.26 and 0.31) and additional 1; % Wt of fluid losscontrol were used to improve the performance of the cement slurry at the temperature of 123oC. The results have shown that increase in the concentration of dispersants that have caused to decrease in the Plastic Viscosity (PV), Yield Point (YP) and GS (Gel Strength). The rheological properties of cement were improved with the addition of fluid loss control additive in 21 % BWOC (Present by Weight on Cement) silica fume increase the water quantity in cement slurry that improve its durability and to reduce the strength retrogression in High Temperature High Pressure (HTHP) environment. Results were achieved through HTHP OFITE Viscometer (Model 1100).

Research of Nanosilica Particles Grafted with Functional Polymer Used as Fluid Loss Additive for Cementing under Ultra-High Temperature

2016 ◽  
Vol 847 ◽  
pp. 497-504
Author(s):  
Xiu Jian Xia ◽  
Jin Tang Guo ◽  
Shuo Qiong Liu ◽  
Jian Zhou Jin ◽  
Yong Jin Yu ◽  
...  
Keyword(s):  
High Temperature ◽  
Salt Tolerance ◽  
Thermal Resistance ◽  
Fluid Loss ◽  
Cement Slurry ◽  
Silica Nanocomposite ◽  
Nanosilica Particles ◽  
Loss Control ◽  
Fluid Loss Additive ◽  
Ultra High Temperature

On account of that the domestic polymer fluid loss additive exists some severe problems, such as, inferior thermal resistance, poor salt tolerance, strong shear-and thermal thinning behavior, a novel polymer/silica nanocomposite PADMO-V@NS is used as ultra-high temperature fluid loss control additive for cementing. In the present study PADMO-V@NS was prepared through an in situ free radical copolymerization of 2-acrylamico-2-methylpropane sulfonic acid (AMPS), N,N-dimethylacryl amide (DMAM), maleic anhydride (MA), octadecyl dimethylallyl ammonium chloride (ODAAC) and triethoxyvinylsilane (VTS) modified nanosilica. The linear hydrophobic associated copolymer was regarded as the shell and the modified nanosilica as the core. The microstructure, compositions and thermal resistance of PADMO-V@NS were investigated through FTIR and TGA techniques. The results showed that the copolymer modified with nanosilica particles possessed more excellent thermal stability than that of PADMO, and the most rapid decomposing temperature of PADMO-V@NS was highly up to 396.9°C. The application performance of PADMO-V@NS in cement slurry exhibited that it had excellent fluid loss control capacity, good high temperature resistance, strong salt tolerance and mild shear-/ thermal thinning performance, and could be used in 220°C and saturated brine circumstances. Moreover, comparing to PADMO, the compressive strength of set cement containing the copolymer increased over 20 % at 80°C, atmosphere pressure and curing time of 1 day due to the reaction of residual silanol groups with Ca (OH)2. The laboratory research results indicated that the multi-functional fluid loss additive composed of hydrophobic associated polymer/silica nanocomposite had bestowed on the cement slurry systems good comprehensive properties, and may have extensive applications in deep & ultra-deep oil/gas wells cementing.

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