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High-density brines have been recognized beneficial for oilfield applications, with various key areas such as drilling, completion and formation evaluation. High-density brines can play a critical role in the development and production of oil and gas reservoirs during the primary, secondary, and tertiary recovery phases. High-density brines can enhance the mobility and recovery of the oil in the reservoir by controlling the density and viscosity. However, a less attention has been given to the application of highdensity brine in the area of reservoir development. This review is shedding light on a concise overview of reservoir development stages in association with the recovery mechanisms. In addition, most possible applications of high-density fluids have also been reviewed in the field of the reservoir development. In summary, this review state that high-density brines can be used to stimulate reservoirs by hydraulic fracturing during the primary recovery phase. However, the risk of increased interfacial tension, which relies on the density difference of two fluids, can trap more residual oil relative to conventional water flooding. In addition, high-density brines are effective in decreasing the mobility ratio and facilitating favorable displacement during polymer flooding. However, they can be least effective in alkaline flooding due to the high IFT related to large density differences. Thus, it is suggested to consider the utilization of sustainable high-density brines by taking into account effective factors in petroleum engineering aspects such as stimulation, secondary recovery and polymer flooding. [ABSTRACT FROM AUTHOR]

Drilling through shale formations can be expensive and time-consuming due to the instability of the wellbore. Further, there is a need to develop inhibitors that are environmentally friendly. Our study discovered a cost-effective solution to this problem using Gum Arabic (ArG). We evaluated the inhibition potential of an ArG clay swelling inhibitor and fluid loss controller in water-based mud (WBM) by conducting a linear swelling test, capillary suction timer test, and zeta potential, fluid loss, and rheology tests. Our results displayed a significant reduction in linear swelling of bentonite clay (Na-Ben) by up to 36.1% at a concentration of 1.0 wt. % ArG. The capillary suction timer (CST) showed that capillary suction time also increased with the increase in the concentration of ArG, which indicates the fluid-loss-controlling potential of ArG. Adding ArG to the drilling mud prominently decreased fluid loss by up to 50%. Further, ArG reduced the shear stresses of the base mud, showing its inhibition and friction-reducing effect. These findings suggest that ArG is a strong candidate for an alternate green swelling inhibitor and fluid loss controller in WBM. Introducing this new green additive could significantly reduce non-productive time and costs associated with wellbore instability while drilling. Further, a dynamic linear swelling model, based on machine learning (ML), was created to forecast the linear swelling capacity of clay samples treated with ArG. The ML model proposed demonstrates exceptional accuracy (R2 score = 0.998 on testing) in predicting the swelling properties of ArG in drilling mud. [ABSTRACT FROM AUTHOR]

The barite scale (barium sulfate) is considered one of the most common scales in oil and gas wells. Barite scale removal is crucial for flow assurance but it still represents a challenge to the oil and gas industry because of its low solubility in water and mineral acids such as HCl. Despite the huge amounts of chelating agents required to remove the barite scale, the solubility of barite (BaSO4) in these chelates is very limited. In this experimental work, a new formulation to remove the barite scale is presented with a small volume of chelating agent used and a converting agent as the main feature of the dissolver. Dissolution of BaSO4 was conducted using tetrapotassium ethylene-diamine-tetra-acetic acid (K4-EDTA) chelating agent and then obtaining the dissolution rate at 200°F to mimic the wellbore condition. The concentration of the K4-EDTA was selected based on the optimum dissolution rate of BaSO4 at 24 h of soaking time. The variation of pH was investigated using potassium base KOH at two different pH values (10.5 and 13). Converting agent concentrations were obtained based on the high solubility of the scale to the total amount of solids. As the result of the study, it was revealed that a 15 wt% concentration of potassium base EDTA with 10 wt% K2CO3 as a converting agent at high pH was highly effective in dissolving up to 100% of 3 wt% BaSO4 in less than 6 h at temperatures of 200°F and 300°F. This new formulation has proven to be a reliable and efficient solution for removing BaSO4 from wellbores and surface equipment. [ABSTRACT FROM AUTHOR]

One of the foremost causes of wellbore instability during drilling operations is shale swelling and hydration induced by the interaction of clay with water-based mud (WBM). Recently, the use of surfactants has received great interest for preventing shale swelling, bit-balling problems, and providing lubricity. Herein, a novel synthesized magnetic surfactant was investigated for its performance as a shale swelling inhibitor in drilling mud. The conventional WBM and magnetic surfactant mixed WBM (MS–WBM) were formulated and characterized using Fourier Transform Infrared (FTIR) and Thermogravimetric analyzer (TGA). Subsequently, the performance of 0.4 wt% magnetic surfactant as shale swelling and clay hydration inhibitor in drilling mud was investigated by conducting linear swelling and capillary suction timer (CST) tests. Afterward, the rheological and filtration properties of the MS–WBM were measured and compared to conventional WBM. Lastly, the swelling mechanism was investigated by conducting a scanning electron microscope (SEM), zeta potential measurement, and particle size distribution analysis of bentonite-based drilling mud. Experimental results revealed that the addition of 0.4 wt% magnetic surfactant to WBM caused a significant reduction (~30%) in linear swelling. SEM analysis, contact angle measurements, and XRD analysis confirmed that the presence of magnetic surfactant provides long-term swelling inhibition via hydrophobic interaction with the bentonite particles and intercalation into bentonite clay layers. Furthermore, the inhibition effect showed an increase in fluid loss and a decrease in rheological parameters of bentonite mixed mud. Overall, the use of magnetic surfactant exhibits sterling clay swelling inhibition potential and is hereby proffered for use as a drilling fluid additive. [ABSTRACT FROM AUTHOR]

Polymer flooding is used to improve the viscosity of an injectant, thereby decreasing the mobility ratio and improving oil displacement efficiency in the reservoir. Thanks to their environmentally benign nature, natural polymers are receiving prodigious attention for enhanced oil recovery. Herein, the rheology and oil displacement properties of okra mucilage were investigated for its enhanced oil recovery potential at a high temperature and high pressure (HTHP) in carbonate cores. The cellulosic polysaccharide used in the study is composed of okra mucilage extracted from okra (Abelmoschus esculentus) via a hot water extraction process. The morphological property of okra mucilage was characterized with Fourier transform infrared (FTIR), while the thermal stability was investigated using a thermogravimetric analyzer (TGA). The rheological property of the okra mucilage was investigated for seawater salinity and high-temperature conditions using a TA rheometer. Finally, an oil displacement experiment of the okra mucilage was conducted in a high-temperature, high-pressure core flooding equipment. The TGA analysis of the biopolymer reveals that the polymeric solution was stable over a wide range of temperatures. The FTIR results depict that the mucilage is composed of galactose and rhamnose constituents, which are essentially found in polysaccharides. The polymer exhibited pseudoplastic behavior at varying shear rates. The viscosity of okra mucilage was slightly reduced when aged in seawater salinity and at a high temperature. Nonetheless, the cellulosic polysaccharide exemplified sufficiently good viscosity under high-temperature and high-salinity (HTHS) conditions. Finally, the oil recovery results from the carbonate core plug reveal that the okra mucilage recorded a 12.7% incremental oil recovery over waterflooding. The mechanism of its better displacement efficiency is elucidated [ABSTRACT FROM AUTHOR]

Hydration of shale formation by water‐based drilling fluids leads to several problems, such as the collapse of boreholes, tight holes, and stuck pipe, which may impede further drilling and time loss in rectifying the problems, leading to heavy economic losses. This study reports the development of new gemini cationic surfactants as shale‐swelling inhibitors. These gemini surfactants are structurally similar but differ in terms of the spacer group. Saturated butyl group (GS1) and unsaturated 2‐butenyl (GS2) and 2‐butynyl (GS3) were introduced as spacer groups of gemini surfactants. To assess the performance of new gemini cationic surfactants, two reliable clay sources were considered. The first clay is from an unconventional formation and the second clay is sodium bentonite. The inhibition characteristics of gemini surfactants were evaluated using dynamic swelling, hot rolling, rheology, and filtration experiments. Different formulations based on commercially available solutions for shale‐swelling inhibitors were applied and compared with cationic shale inhibitors. It was observed that the new gemini cationic surfactants with different spacers (saturated and unsaturated) reduced the shale swelling by different percentages. The GS2 surfactant, containing an unsaturated double bond proved to be a good swelling inhibitor as compared to GS1 and GS3. It also showed acceptable performance compared with the common shale inhibitor (KCl) used in the industry. The addition of surfactant has less impact on the rheological properties as compared to KCl. The filtration properties of the base mud were unchanged when surfactants were used. However, the commercial inhibitor, KCl, significantly increased the filtration volume that is associated with the disintegration of the clay. In summary, unlike commercial inhibitors, the synthesized surfactants reduced the clay swelling without affecting the other properties of the drilling fluids. [ABSTRACT FROM AUTHOR]

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. [ABSTRACT FROM AUTHOR]