A new mud design to reduce formation damage in sandstone reservoirs

Liew, Chean Xing; Gholami, Raoof; Safari, Mehdi; Raza, Arshad; Rabiei, Minou; Fakhari, Nikoo; Rasouli, Vamegh; Vettaparambil, Jose Varghese

doi:10.1016/j.petrol.2019.106221

Cited by 10 publications

(4 citation statements)

References 22 publications

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“…However, tight sandstone characterizes low permeability, strong water-wet condition and narrow pore throats, which lead to high capillary forces [4,5]. During the drilling process of reservoirs in oil and gas fields, working fluids in the wellbore such as drilling fluids, completion fluids, fracturing fluids, acidizing fluids, etc., intrude into the reservoir due to the capillary effect, which can increase the water saturation in the formation and further cause the decrease of gas flow capacity [6][7][8]. In the process of oil/ gas production, due to the reservoir capillary retention effect, the intruding fluid would be hard to flow out the pore space in tight sandstone, so that the relative permeability of gas cannot be restored [9].…”

Section: Introductionmentioning

confidence: 99%

Pore structure characterization and its influence on aqueous phase trapping damage in tight gas sandstone reservoirs

Guo,

Lu,

Liu

et al. 2024

PLoS ONE

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Aqueous phase trapping (APT), which is one of the most prominent damages, seriously restricts the natural gas production in tight gas sandstone with low permeability. Pore size and microscopic pore structures are the most important factors to determine the water blocking damage. In this paper, 9 core samples from tight gas sandstone with various physical properties were employed, and the pore size distribution (PSD) of the core samples were investigated by high pressure mercury intrusion tests (HPMI). Results showed that the porosity of core samples ranges from 5.68% to 13.7%, and the permeability ranges from 0.00456 to 7.86 mD, which is a typical tight reservoir with strong heterogeneity. According to the HPMI capillary curve, the cores can be divided into two types: Type I and Type II, and the pore sizes of type I are larger than that of type II. Fractal distributions were obtained using HPMI data to further determine the pore structure characteristics of tight reservoirs. The pore structures of tight sandstones display the multifractal fractal feature: D1 corresponding to macro-pores, and D2 corresponding to fractal dimension of micro-pores. Furthermore, APT damage was determined by the permeability recovery ratios (Kr) after gas flooding tests. The correlation of Kr and PSD and fractal dimensions were jointly analyzed in tight gas sandstone. Although positive correlations between pore size parameters and the permeability recovery ratios were observed with relatively weak correlations, for those core samples with very close permeability, pore size parameters (both permeability and PSD) is inadequate in clarifying this damage. The fractal dimension can well describe the complexity and heterogeneity of flow channels in pores, which can become the determining factor to distinguish the flow capacity of tight sandstone. The D2 for samples of type I and type II exhibited a good negative relation with Kr with a correlation coefficient of 0.9878 and 0.7723, respectively. The significance of this finding is that for tight gas sandstone, fractal dimensions, especially the small pore fractal dimension (D2), can be used to predict the possible APT damage very well.

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Section: Introductionmentioning

confidence: 99%

Pore structure characterization and its influence on aqueous phase trapping damage in tight gas sandstone reservoirs

Guo,

Lu,

Liu

et al. 2024

PLoS ONE

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“…New research has shown that the addition of CTAB with graphene formulation into drilling fluid produces high shale dispersion recovery and low clay swelling degrees in comparison to drilling fluids that had no such formulations added . Additionally, introducing CTAB additives into drilling fluids helps diminish formation damage affected by mud invasion, but then it could also potentially lead to the separation of the clay to produce a thick mud cake around the borehole . A recent study by Moslemizadeh et al examined the swelling inhibitive behavior of CTAB on clay .…”

Section: Introductionmentioning

confidence: 99%

“… 16 Additionally, introducing CTAB additives into drilling fluids helps diminish formation damage affected by mud invasion, but then it could also potentially lead to the separation of the clay to produce a thick mud cake around the borehole. 17 A recent study by Moslemizadeh et al examined the swelling inhibitive behavior of CTAB on clay. 18 The shale’s wellbore stability was enhanced by means of CTAB and its wettability alteration.…”

Section: Introductionmentioning

confidence: 99%

Stability, Rheological Behavior, and pH Responsiveness of CTAB/HCl Acidic Emulsion: Experimental Investigation

et al. 2023

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Cetyltrimethylammonium bromide (CTAB) surfactant was proven to be a reliable emulsifier for creating stable emulsions used for drilling, well stimulation, and EOR. The presence of acids like HCl during such operations may lead to the formation of acidic emulsions. No previous comprehensive investigations have been done to study the performance of CTAB-based acidic emulsions. This paper, therefore, presents experimental investigations of the stability, rheological behavior, and pH responsiveness of a CTAB/HCl-based acidic emulsion. The effects of temperature, pH, and CTAB concentration on the emulsion stability and rheology have been investigated using a bottle test and a TA Instrument DHR1 rheometer. Viscosity and flow sweep were analyzed for the steady state at a shear range of 2.5–250 s–1. For the dynamic tests, the storage modulus (G′) and loss modulus (G″) were observed by applying the oscillation test at the range of shear frequency from 0.1 to 100 rad/s. The results revealed that the emulsion exhibits steady rheological behaviors ranging from Newtonian to shear-dependent (psedosteady), depending on the temperature and CTAB concentration. The tendency of the emulsion to exhibit a solid-like behavior is also dependent on CTAB concentration, temperature, and pH. However, the pH responsiveness of the emulsion is more significantly observed within the acidic range of the pH.

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“…In recent years, many studies have been conducted on the control of the rheological properties and amount of water-based drilling fluid filtration. These studies show that the use of different additives, especially polymers and surfactants, can improve the rheological and filtration properties of drilling fluids and reduce the change in the wettability of the porous medium toward more oil wetness. − On the other hand, the use of these materials may be ineffective in various conditions such as high temperature and pressure or excessive concentration of material, and in addition to not being able to prevent the damage, they themselves might damage the porous medium. ,− …”

Section: Introductionmentioning

confidence: 99%

Insights into the Pore-Scale Mechanisms of Formation Damage Induced by Drilling Fluid and Its Control by Silica Nanoparticles

Mohammadi

Mahani

2020

Energy Fuels

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The formation damage (FD) caused by the invasion of drilling fluid severely affects reservoir performance during production. Most of the published research studies which address this type of FD have been carried out at the core or field scale. Thus, the main aim of the paper is to investigate the pore-scale mechanisms of FD induced by drilling fluids and their control with silica nanoparticles (NPs) using a microfluidic approach. The proper identification of the mechanisms of FD can lead to the proper selection of NP type and concentration as well as a suitable method to remediate FD. The micromodel was designed in a way to closely simulate the cross-flow at the wellbore surface. A water-based drilling fluid was prepared at low-and high-pH values of 9 and 10.7, respectively. The drilling fluid was augmented with silica NPs at different concentrations to study its impact on FD remediation. The drilling fluid was injected into an initially oil-saturated micromodel. Thereafter hydrochloric acid was injected as a cleanup fluid. Lastly, oil was flowed back into the micromodel from the opposite side to simulate the back production. The study was complemented with cutting transport simulation and measurement of filtration and bulk rheological properties of the drilling fluid. The pore-scale observations reveal three types of FD associated with the drilling fluid invasion: (1) primary, (2) secondary, and (3) tertiary. The type of FD was found to be dependent on the mud pH, necessitating the use of different NP concentrations. Primary FD is caused immediately after drilling fluid invasion into the porous medium and includes the internal mudcake deposition (with both low-and high-pH muds) and water blockage (mainly with high-pH mud). After acid cleaning and oil flow-back, the secondary FD is induced which includes in situ acid-in-oil emulsion formation within the pore structure of the mudcake (with both low-and high-pH muds) as well as on the micromodel surface (mainly with high-pH mud). The tertiary FD originates from the relocation and trapping of mobile emulsions. It was also found that, in the case of primary FD, the NPs reduce the penetration depth of the drilling fluid into the micromodel through external (or face) and internal plugging mechanisms. Moreover, NPs eliminate the water blockage by reducing the mud infiltrate volume as well as reducing the IFT. For the case of secondary FD, NPs do not allow the formation of acid-in-oil emulsions within the internal mudcake due to increased drilling fluid stability. In addition to reducing the infiltrate volume, NPs prevent the formation of emulsions on the pore surface by altering the wettability of the micromodel to a more water-wetting state. By reducing the primary and secondary FD, the tertiary FD is eliminated too. The findings from the micromodel experiments highlight the importance of optimizing the NP concentration based on both attaining an efficient cutting transport in the well and ensuring low mud invasion into the porous medium.

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A new mud design to reduce formation damage in sandstone reservoirs

Cited by 10 publications

References 22 publications

Pore structure characterization and its influence on aqueous phase trapping damage in tight gas sandstone reservoirs

Pore structure characterization and its influence on aqueous phase trapping damage in tight gas sandstone reservoirs

Stability, Rheological Behavior, and pH Responsiveness of CTAB/HCl Acidic Emulsion: Experimental Investigation

Insights into the Pore-Scale Mechanisms of Formation Damage Induced by Drilling Fluid and Its Control by Silica Nanoparticles

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