Development of a Highly Elastic Composite Gel through Novel Intercalated Crosslinking Method for Wellbore Temporary Plugging in High-Temperature Reservoirs

Summary Effective mitigation of fluid loss and prevention of formation damage are substantial concerns during well completion and workover in low-pressure, high-permeability, and/or fractured reservoirs, especially with high temperature (HT). In this paper, a highly elastic composite gel is developed on the basis of the solution blending for “intercalated crosslinking.” The mechanism is the intercalation of polymer and crosslinker into layered silicate material (LSM) using a specific procedure. The gel is composed of HT resistant copolymer, crosslinker polyethyleneimine (PEI), LSM, and antioxidant in freshwater. The effects of main variables on the gelation performance are investigated. The mature composite gel strength is noticeably improved with increasing temperature. The elastic modulus (G′) of the mature composite gel prepared at 160°C can reach up to 15 000 Pa, while only a value of 6000 Pa is obtained for the gel at 130°C. The composite gel remains robust after aging 10 days at 160°C. The pressure-bearing capacity and rigidity of the mature composite gel are noticeably improved with increasing layered silicate concentration. This unique feature can benefit stress buffering when the sealing operation is conducted under high differential pressure such as the case with a long hydrostatic column. Scanning electron microscope (SEM) is used to further reveal the intercalated crosslinking mechanism of the composite gel. A temporary plugging experiment for a fractured limestone core also supports the gel's high-pressure (HP) resistance and low adsorption and retention to alleviate formation damage. The composite gel is promising for fluid loss mitigation that could be extended to other related near-wellbore operations in HT wells.

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Effect of Nanoparticle Shape on Viscoelastic Surfactant Performance at High Temperatures

SPE Journal ◽

10.2118/203836-pa ◽

2020 ◽

pp. 1-19 ◽

Cited By ~ 1

Author(s):

Ahmed Hanafy ◽

Faisal Najem ◽

Hisham A. Nasr-El-Din

Keyword(s):

Thermal Stability ◽

High Pressure ◽

High Temperature ◽

Carrying Capacity ◽

Spherical Particles ◽

Formation Damage ◽

Fluid Loss ◽

Stability Range ◽

Fracturing Fluids ◽

High Pressure High Temperature

Summary Viscoelastic surfactants (VESs) have been used for acid diversion and fracturing fluids. VESs were introduced because they are less damaging than polymers. VESs’ high cost, low thermal stability, and incompatibility with several additives (e.g., corrosion inhibitors) limit their use. The goal of this study is to investigate the interaction of VES micelles with different nanoparticle shapes to reduce VES loadings and enhance their thermal stability. This work examined spherical and rod-shaped nanoparticles of silica and iron oxides. The effects of particle size, shape, and surface charge on a zwitterionic VES micellization were conducted. The physical properties were measured using zeta-potential, dynamic light scattering (DLS), and transmission electron microscopy (TEM). The rheological performances of VES solutions were evaluated at 280 and 350°F using a high-pressure/high-temperature rotational rheometer. The proppant-carrying capacity of the fracturing fluids was evaluated using a high-pressure/high-temperature see-through cell and dynamic oscillatory viscometer. The fluid loss and formation damage were determined using corefloods and computed-tomography scans. The interaction between nanoparticles and VES is strongly dependent on the VES concentration, temperature, nanoparticle characteristics, and concentration. The spherical particles at 7-lbm/1,000 gal loading extended the VES-based-fluid thermal stability at VES loading of 4 wt% up to 350°F. The nanorods effectively enhanced and extended the thermal-stability range of the VES system at VES concentration of only 2 wt%. Both particle shapes performed similarly at 4 wt% VES and 280°F. The addition of silica nanorods extended the thermal stability of the 4 wt% VES aqueous fluid, which resulted in an apparent viscosity of 200 cp for 2 hours. The addition of rod-shaped particles enhanced the micelle to micelle entanglement, especially at VES loading of 2 wt%. The use of nanoparticles enhanced the micelle/micelle networking, boosting the fluid-storage modulus and enhancing the proppant-carrying capacity. The addition of nanoparticles to the VES lowered its fluid-loss rate and minimized formation damage caused by VES-fluid invasion. This research gives guidelines to synthesize nanoparticles to accommodate the chemistry of surfactants for higher-temperature applications. It highlights the importance of the selected nanoparticles on the rheological performance of VES.

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Influence of Formate Concentration on the Rheology and Thermal Degradation of Xanthan Gum

Polymers ◽

10.3390/polym13193378 ◽

2021 ◽

Vol 13 (19) ◽

pp. 3378

Author(s):

María José Martín-Alfonso ◽

Javier Mauricio Loaiza ◽

Clara Delgado-Sánchez ◽

Francisco José Martínez-Boza

Keyword(s):

Mechanical Properties ◽

High Temperature ◽

Xanthan Gum ◽

Oil Industry ◽

Gel Strength ◽

Threshold Concentration ◽

Formation Damage ◽

Fluid Loss ◽

Ordered Structure ◽

Loss Of Strength

Xanthan gum solutions have gained increasing interest for their use as environmentally friendly chemicals in the oil industry. Xanthan is compatible with most concentrate brines used for controlling formation damage and fluid loss. Particularly, formate brines reinforce the ordered structure of the biopolymer in solution, gel strength, and the specific gravity of the resulting fluid. In this paper, we studied the effect of thermal aging on the rheological behavior of xanthan solutions as a function of the concentration in potassium formate. Ionic strength below a threshold concentration does not prevent the degradation of the structure of xanthan after being submitted to aging at 165 °C. Aged solutions show an important loss of strength in their mechanical properties, lower pH, and higher content in furfural and hydroxymethylfurfural. Highly concentrated formate brines are necessary to maintain the strength of the rheological properties after exposure to high-temperature environments.

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Lost Circulation Material Implementation Strategies on Fluid Loss Remediation and Formation Damage Control

10.2118/199249-ms ◽

2020 ◽

Author(s):

Mingzheng Yang ◽

Yuanhang Chen

Keyword(s):

Damage Control ◽

Implementation Strategies ◽

Formation Damage ◽

Fluid Loss ◽

Lost Circulation ◽

Formation Damage Control

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Experimental Study of Heavy Oil In-Situ Upgrading Using High Temperature Gas-Oil Gravity Drainage in Naturally Fractured Reservoirs

10.2118/177220-ms ◽

2015 ◽

Cited By ~ 1

Author(s):

Ricardo G. Suarez Suarez ◽

Carlos Scott ◽

S. Hossein Hejazi ◽

Pedro Pereira-Almao

Keyword(s):

Experimental Study ◽

High Temperature ◽

Heavy Oil ◽

Fractured Reservoirs ◽

Naturally Fractured Reservoirs ◽

Gravity Drainage ◽

Gas Oil ◽

Naturally Fractured ◽

High Temperature Gas

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Rheological Characteristics of Viscoelastic Surfactant Fluid Mixed With Silica Nanoparticles

ASME 2013 4th International Conference on Micro/Nanoscale Heat and Mass Transfer ◽

10.1115/mnhmt2013-22047 ◽

2013 ◽

Cited By ~ 1

Author(s):

Yueqiong Wu ◽

Zhongyang Luo ◽

Hong Yin ◽

Tao Wang

Keyword(s):

High Temperature ◽

Shear Rate ◽

Volume Fraction ◽

Sio2 Nanoparticles ◽

Fluid Loss ◽

Rheological Characteristics ◽

High Shear ◽

Fracturing Process ◽

Viscoelastic Surfactant ◽

Rheological Performance

Since the surfactant can form rod-like micelles or even cross-link structures, viscoelastic surfactant (VES) fluid has unique rheological characteristics. The demerits of VES fluids have been proven after being applied as the fracturing fluid for several years. However, the fluid has high fluid loss and a low viscosity at high temperature, which limits the application to hydraulic fracturing. This paper focuses on the VES fluid mixed with nanoparticles which should be an effective way to maintain the viscosity at high temperature and high shear rate. The experiments were based on preparation of uniform and stable nanocolloids, which utilize Microfluidizer high shear fluid processor. Dynamic light scattering and microscopic methods are employed to investigate the stability and micro-structure of the VES fluid. The effects of temperature, shear rate and volume fraction of the nanoparticles on rheology of VES were studied. The SiO2 nanoparticles could significantly improve the rheological performance of VES fluid, although the rheological performance at the temperature over 90 °C needs to be enhanced. The mechanisms of interactions between nanoparticles and micelles are also discussed later in the paper. At the end, the potential of VES fluid mixed with nanoparticles during application in fracturing process was discussed.

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The Feasibility for Potassium-Based Phosphate Brines To Serve as High-Density Solid-Free Well-Completion Fluids in High-Temperature/High-Pressure Formations

SPE Journal ◽

10.2118/194008-pa ◽

2018 ◽

Vol 24 (05) ◽

pp. 2033-2046 ◽

Cited By ~ 1

Author(s):

Hu Jia ◽

Yao–Xi Hu ◽

Shan–Jie Zhao ◽

Jin–Zhou Zhao

Keyword(s):

High Pressure ◽

High Temperature ◽

Oil And Gas ◽

Pressure Coefficient ◽

High Density ◽

Well Drilling ◽

Well Completion ◽

Oil And Gas Resources ◽

Completion Fluids ◽

High Temperature High Pressure

Summary Many oil and gas resources in deep–sea environments worldwide are often located in high–temperature/high–pressure (HT/HP) and low–permeability reservoirs. The reservoir–pressure coefficient usually exceeds 1.6, with formation temperature greater than 180°C. Challenges are faced for well drilling and completion in these HT/HP reservoirs. A solid–free well–completion fluid with safety density greater than 1.8 g/cm3 and excellent thermal endurance is strongly needed in the industry. Because of high cost and/or corrosion and toxicity problems, the application of available solid–free well–completion fluids such as cesium formate brines, bromine brines, and zinc brines is limited in some cases. In this paper, novel potassium–based phosphate well–completion fluids were developed. Results show that the fluid can reach the maximum density of 1.815 g/cm3 at room temperature, which makes a breakthrough on the density limit of normal potassium–based phosphate brine. The corrosion rate of N80 steel after the interaction with the target phosphate brine at a high temperature of 180°C is approximately 0.1853 mm/a, and the regained–permeability recovery of the treated sand core can reach up to 86.51%. Scanning–electron–microscope (SEM) pictures also support the corrosion–evaluation results. The phosphate brine shows favorable compatibility with the formation water. The biological toxicity–determination result reveals that it is only slightly toxic and is environmentally acceptable. In addition, phosphate brine is highly effective in inhibiting the performance of clay minerals. The cost of phosphate brine is approximately 44 to 66% less than that of conventional cesium formate, bromine brine, and zinc brine. This study suggests that the phosphate brine can serve as an alternative high–density solid–free well–completion fluid during well drilling and completion in HT/HP reservoirs.

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

Molecules ◽

10.3390/molecules26164877 ◽

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.

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Prediction of Formation Damage, Fluid Loss and Rheological Properties of Water Based Mud with Corn Cob

European Journal of Engineering Research and Science ◽

10.24018/ejers.2020.5.10.2203 ◽

2020 ◽

Vol 5 (10) ◽

pp. 1269-1273

Author(s):

Godwin Chukwuma Jacob Nmegbu ◽

Bright Bariakpoa Kinate ◽

Bari-Agara Bekee

Keyword(s):

Rheological Properties ◽

High Pressures ◽

Chemical Properties ◽

Analytical Models ◽

Formation Damage ◽

Fluid Loss ◽

Drilling Mud ◽

Corn Cob ◽

Core Samples ◽

Water Based

The extent of damage to formation caused by water based drilling mud containing corn cob treated with sodium hydroxide to partially replace polyanionic cellulose (PAC) as a fluid loss control additive has been studied. Core samples were obtained from a well in Niger Delta for this study with a permeameter used to force the drilling mud into core samples at high pressures. Physio-chemical properties (moisture content, cellulose and lignin) of the samples were measured and the result after treatment showed reduction. The corn cob was combined with the PAC in the ratio of 25-75%, 50-50% and 75-25% in the mud. Analyzed drilling mud rheological properties such as plastic viscosity, apparent viscosity, yield point and gel strength all decreased as percentage of corn cob increased in the combination and steadily decreased as temperature increased to 200oF. Measured fluid loss and pH of the mud showed an increase in fluid loss and pH in mud sample with 100% corn cob. The extent of formation damage was determined by the differences in the initial and final permeability of the core samples. Experimental data were used to develop analytical models that can serve as effective tool to predict fluid loss, rheological properties of the drilling mud at temperature up to 200oF and percentage formation damage at 100 psi.

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