Improving Water-Based Drilling Mud Performance Using Biopolymer Gum: Integrating Experimental and Machine Learning Techniques.

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.

Sand consolidation using enzyme-induced carbonate precipitation: new insights on temperature and particle size effects.

Sand production is a major issue in the oil and gas industry. Unconsolidated sand can be produced with the oil or gas a cause many issues to the production facilities. Enzyme-induced carbonate precipitation (EICP) is a promising method for sand consolidation and is characterized by its environment friendliness. Numerous studies have shown its effectiveness in ambient conditions. However, oil and gas downhole well operations are high pressure and high-temperature conditions. The objective of this study is to investigate effect of high temperature on EICP reaction and its efficiency in terms of uniformity to consolidate different types of sand samples. In this paper, the behavior of EICP solutions is examined in high temperatures from 25 to 90 °C. The study shows that high temperature environment doesn't handicap efficiency but in contrast it can favor the reaction if optimum concentration of reactants has been selected. The temperature effect is also discussed in terms of controllability of reaction which can favor application of reaction. Qualitive analysis shows when EICP solutions containing more than 50,000 ppm of metal ions and stoichiometrically surplus urea requires exposure to heat for reaction progress. The effect of sand particle size and its implication on the consolidation process was examined. Particle size of fine and medium sand ranged from 125 to 250 µm and 250 to 425 µm respectively while for coarse sand 70% sand particle size was between 425 and 700 µm. Designed EICP solutions achieve 9,000 psi for medium and almost 5,000 psi intrinsic specific energy for coarse sand samples. However, treated samples were subject to non-uniform distribution of strength of which can be up to 8,000 psi difference between top and bottom half of the samples.

Optimization of calcium carbonate precipitation during alpha-amylase enzyme-induced calcite precipitation (EICP).

The sand production during oil and gas extraction poses a severe challenge to the oil and gas companies as it causes erosion of pipelines and valves, damages the pumps, and ultimately decreases production. There are several solutions implemented to contain sand production including chemical and mechanical means. In recent times, extensive work has been done in geotechnical engineering on the application of enzyme-induced calcite precipitation (EICP) techniques for consolidating and increasing the shear strength of sandy soil. In this technique, calcite is precipitated in the loose sand through enzymatic activity to provide stiffness and strength to the loose sand. In this research, we investigated the process of EICP using a new enzyme named alpha-amylase. Different parameters were investigated to get the maximum calcite precipitation. The investigated parameters include enzyme concentration, enzyme volume, calcium chloride (CaCl2) concentration, temperature, the synergistic impact of magnesium chloride (MgCl2) and CaCl2, Xanthan Gum, and solution pH. The generated precipitate characteristics were evaluated using a variety of methods, including Thermogravimetric analysis (TGA), Fourier-transform infrared spectroscopy (FTIR), and X-ray diffraction (XRD). It was observed that the pH, temperature, and concentrations of salts significantly impact the precipitation. The precipitation was observed to be enzyme concentration-dependent and increase with an increase in enzyme concentration as long as a high salt concentration was available. Adding more volume of enzyme brought a slight change in precipitation% due to excessive enzymes with little or no substrate available. The optimum precipitation (87%) was yielded at 12 pH and with 2.5 g/L of Xanthan Gum as a stabilizer at a temperature of 75°C. The synergistic effect of both CaCl2 and MgCl2 yielded the highest CaCO3 precipitation (32.2%) at (0.6:0.4) molar ratio. The findings of this research exhibited the significant advantages and insights of alpha-amylase enzyme in EICP, enabling further investigation of two precipitation mechanisms (calcite precipitation and dolomite precipitation).

A Magnetic Surfactant Having One Degree of Unsaturation in the Hydrophobic Tail as a Shale Swelling Inhibitor.

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.

Effect of Seawater Ions on Polymer Hydration in the Presence of a Chelating Agent: Application to Hydraulic Fracturing.

Seawater (SW) and produced water (PW) could replace freshwater in hydraulic fracturing operations, but their high salinity impacts the fluid stability and results in formation damage. Few researchers investigated SW and PW individual ions' impact on polymer hydration and rheology. This research examines the rheology of carboxy methyl hydroxy propyl guar (CMHPG) polymer hydrated in salt ions in the presence of a chelating agent. The effect of various molar concentrations of SW and PW salt ions on the rheology of CMHPG polymer solution was examined. The tested salt ions included calcium chloride, magnesium chloride, sodium chloride, and sodium sulfate, which were compared to SW and deionized water (DI) solutions. The solutions were tested at 70 °C temperature, 500 psi pressure, and 100 1/s shear rate. A GLDA chelating agent was utilized at different concentrations to examine their impact on stabilizing the solution viscosity. We found that adding the GLDA to magnesium and calcium chloride solutions increased the viscosity. Results showed that sulfate ions control the rheology of seawater due to their similar rheological response to the addition of GLDA. The results help to understand how the SW and PW ions impact the rheology of fracturing fluids.

Machine Learning-Based Accelerated Approaches to Infer Breakdown Pressure of Several Unconventional Rock Types.

Unconventional oil and gas reservoirs are usually classified by extremely low porosity and permeability values. The most economical way to produce hydrocarbons from such reservoirs is by creating artificially induced channels. To effectively design hydraulic fracturing jobs, accurate values of rock breakdown pressure are needed. Conducting hydraulic fracturing experiments in the laboratory is a very expensive and time-consuming process. Therefore, in this study, different machine learning (ML) models were efficiently utilized to predict the breakdown pressure of tight rocks. In the first part of the study, to measure the breakdown pressures, a comprehensive hydraulic fracturing experimental study was conducted on various rock specimens. A total of 130 experiments were conducted on different rock types such as shales, sandstone, tight carbonates, and synthetic samples. Rock mechanical properties such as Young's modulus (E), Poisson's ratio (ν), unconfined compressive strength, and indirect tensile strength (σt) were measured before conducting hydraulic fracturing tests. ML models were used to correlate the breakdown pressure of the rock as a function of fracturing experimental conditions and rock properties. In the ML model, we considered experimental conditions, including the injection rate, overburden pressures, and fracturing fluid viscosity, and rock properties including Young's modulus (E), Poisson's ratio (ν), UCS, and indirect tensile strength (σt), porosity, permeability, and bulk density. ML models include artificial neural networks (ANNs), random forests, decision trees, and the K-nearest neighbor. During training of ML models, the model hyperparameters were optimized by the grid-search optimization approach. With the optimal setting of the ML models, the breakdown pressure of the unconventional formation was predicted with an accuracy of 95%. The accuracy of all ML techniques was quite similar; however, an explicit empirical correlation from the ANN technique is proposed. The empirical correlation is the function of all input features and can be used as a standalone package in any software. The proposed methodology to predict the breakdown pressure of unconventional rocks can minimize the laboratory experimental cost of measuring fracture parameters and can be used as a quick assessment tool to evaluate the development prospect of unconventional tight rocks.

Experimental Study on the Application of Cellulosic Biopolymer for Enhanced Oil Recovery in Carbonate Cores under Harsh Conditions.

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.

Single step calcium sulfate scale removal at high temperature using tetrapotassium ethylenediaminetetraacetate with potassium carbonate.

Calcium sulfate (CaSO4) scale has been identified as one of the most common scales contributing to several serious operating problems in oil and gas wells and water injectors. Removing this scale is considered an economically feasible process in most cases as it enhances the productivity of wells and prevents potential severe equipment damage. In this study, a single-step method utilizing potassium carbonate and tetrapotassium ethylenediaminetetraacetate (K4-EDTA) at high temperature (200 °F) has been used to remove CaSO4 scale. The CaSO4 scale was converted to calcium carbonate (CaCO3) and potassium sulfate (K2SO4) using a conversion agent, potassium carbonate (K2CO3), at a high temperature (200 °F) and under various pH conditions. Various parameters were investigated to obtain a dissolver composition at which the optimum dissolution efficiency is achieved including the effect of dissolver pH, soaking time, the concentration of K4-EDTA, the concentration of potassium carbonate (K2CO3), temperature impact and agitation effect. Fourier transform infrared, X-ray crystallography, ion chromatography, stability tests and corrosion tests were carried out to test the end product of the process and showcase the stability of the dissolver at high temperature conditions. A reaction product (K2SO4) was obtained in most of the tests with different quantities and was soluble in both water and HCl. It was observed that the dissolver solution was effective at low pH (7) and resulted in a negligible amount of reaction product with 3 wt% CaSO4 dissolution. The 10.5-pH dissolver was effective in most of the cases and provided highest dissolution efficiency. The reaction product has been characterized and showed it is not corrosive. Both 7-pH and 10.5-pH dissolvers showed high stability at high temperature and minimum corrosion rates. The single step dissolution process showed its effectiveness and could potentially save significant pumping time if implemented in operation.

Fluorinated surfactants: A review on recent progress on synthesis and oilfield applications.

The selection of appropriate chemicals and the synthetic method plays an important role in oilfield application. The objectives of this study are to describe the various synthetic route for the preparation of fluorinated surfactants and highlight their oilfield applications. Fluorinated surfactants are the type of surfactants where the hydrophobic tail is either partially fluorinated or replaced totally with fluorine molecules. Fluorinated surfactants have distinct properties compared to corresponding hydrocarbon surfactants such as lower surface tension, better efficiency in lowering the interfacial tension, both oleophobic and hydrophobic nature, high thermal stability, and better chemical tolerance. These properties make them a material of choice for several applications which include but are not limited to fire-fighting, household items, foaming, coating, and paints. Despite these attractive properties, environmental concerns associated with fluorinated surfactants is a major hurdle in extending the application of such surfactants. This review discusses the various synthetic routes for the synthesis of different classes of surfactants such as cationic, anionic, non-ionic, and zwitterionic surfactants. The fundamental surface/interface properties of the synthesized surfactants are also highlighted. In addition, the review highlights the application of fluorinated surfactants in the oil & gas industry.

Optimum Selection of H2S Scavenger in Light-Weight and Heavy-Weight Water-Based Drilling Fluids.

During hydrocarbon drilling operations, the presence of hydrogen sulfide (H2S) gas could cause serious health and safety issues. Scavenging this gas and eliminating its impact are essential requirements for a safe drilling operation. This study investigated the impact of three H2S scavenger additives (copper nitrate, iron gluconate, and potassium permanganate) on water-based drilling fluids (WBDFs). The additives were tested on two actual field drilling mud samples that differ mainly in their weight. The scavengers' impact on drilling muds was investigated by measuring their scavenging capacity and their effect on rheology, fluid loss, and pH. Potassium permanganate outperformed the other scavengers when added to the lighter (lower density) WBDF. However, it did not impact the scavenging capacity of the heavier mud system. Copper nitrate outperformed the other scavengers in the heavier drilling mud system. Also, the addition of copper nitrate in the lighter mud system increased its H2S-scavenging capacity greatly, while for iron gluconate, it did not perform very well. Overall, all the scavenger-containing drilling muds did not have any significant harmful impact on the plastic viscosity or the fluid loss properties of the drilling muds. Furthermore, all the tested drilling mud samples showed an excellent ability to clean wellbores and suspend drill cuttings evident by the high carrying capacity with the exception of iron gluconate or potassium permanganate with the heavy mud system.

Application of Anhydrous Calcium Sulfate as a Weighting Agent in Oil-Based Drilling Fluids.

The hydrostatic pressure exerted during the drilling operation is controlled by adding a weighting agent into drilling fluids. Various weighting materials such as barite, calcium carbonate, hematite, and ilmenite are used to increase the density of drilling fluids. Some weighting additives can cause serious drilling problems, including particle settling, formation damage, erosion, and insoluble filters. In this study, anhydrite (calcium sulfate) is used as a weighting additive in the oil-based drilling fluid (OBDF). Anhydrite is an abundantly available resource used in the preparation of desiccant, plaster of Paris, and Stucco. Anhydrite application in drilling fluids is discouraged because of its filter cake removal issue. This study investigated anhydrite (anhydrous CaSO4) as a weighting agent and its filter cake removal procedure for OBDFs. The anhydrite performance as a weighting agent in OBDFs was evaluated by conducting several laboratory experiments such as density, rheology, fluid loss, and electrical stability and compared with that of commonly used weighting materials (barite, calcium carbonate, and hematite). The anhydrite was mixed in three different concentrations (62, 124, and 175 ppb) in a base-drilling fluid. The results showed that calcium sulfate enhanced rheological parameters such as plastic viscosity, yield point, apparent viscosity, and gel strength. CaSO4 reduced the fluid loss and provided better control over the fluid loss than other tested weighting materials tested at the same concentration of 124 ppb. Similarly, the emulsion stability was decreased with the increase in the amount of calcium sulfate in the OBDF. The calcium sulfate filter cake can be removed easily from the wellbore with an efficiency of 83 to 91% in single-stage and multistage removal processes, respectively using the newly developed formulation consisting of 20 wt % potassium salt of glutamic acid-N,N-diacetic acid (K4GLDA) as a chelating agent, 6 wt % potassium carbonate, and 10% ethylene glycol monobutyl ether. The introduction of anhydrite as a weighting agent can be more beneficial for both academia and industry.

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

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.

Dicationic Surfactants as an Additive in Fracturing Fluids to Mitigate Clay Swelling: A Petrophysical and Rock Mechanical Assessment.

The interactions of clays with freshwater in unconventional tight sandstones can affect the mechanical properties of the rock. The hydraulic fracturing technique is the most successful technique to produce hydrocarbons from unconventional tight sandstone formations. Knowledge of clay minerals and their chemical interactions with fracturing fluids is extremely vital in the optimal design of fracturing fluids. In this study, quaternary ammonium-based dicationic surfactants are proposed as clay swelling inhibitors in fracturing fluids to reduce the fractured face skin. For this purpose, several coreflooding and breakdown pressure experiments were conducted on the Scioto sandstone samples, and the rock mechanical properties of the flooded samples after drying were assessed. Coreflooding experiments proceeded in a way that the samples were flooded with the investigated fluid and then postflooded with deionized water (DW). Rock mechanical parameters, such as compressive strength, tensile strength, and linear elastic properties, were evaluated using unconfined compressive strength test, scratch test, indirect Brazilian disc test, and breakdown pressure test. The performance of novel synthesized surfactants was compared with commercially used clay stabilizing additives such as sodium chloride (NaCl) and potassium chloride (KCl). For comparison, base case experiments were performed with untreated samples and samples treated with DW. Scioto sandstone samples with high illite contents were used in this study. Results showed that the samples treated with conventional electrolyte solutions lost permeability up to 65% when postflooded with DW. In contrast, fracturing fluid containing surfactant solutions retained the original permeability even after being postflooded with DW. Conventional clay stabilizing additives led to the swelling of clays caused by high compression and tensile strength of the rock when tested at dry conditions. Consequently, the rock fractures at a higher breakdown pressure. However, novel dicationic surfactants do not cause any swelling, and therefore, the rock fractures at the original breakdown pressure.

Magnetic surfactants: A review of recent progress in synthesis and applications.

Magnetic surfactants are a special class of surfactants with magneto-responsive properties. These surfactants possess lower critical micelle concentrations and are more effective in reducing surface tension as compared to conventional surfactants. Such surfactants' ability to manipulate self-assembly in a controlled way by tuning the magnetic field makes them an attractive choice for several applications, including drug delivery, catalysis, separation, oilfield, and water treatment. In this work, we reviewed the properties of magnetic surfactants and possible explanations of magnetic behavior. This article also covers the synthesis methods that can be used to synthesize different types of cationic, anionic, nonionic, and zwitterionic magnetic surfactants. The applications of magnetic surfactants in different fields such as biotechnology, water treatment, catalysis, and oilfield have been discussed in detail.

Novel Expandable Cement System for Prevention of Sustained Casing Pressure and Minimization of Lost Circulation.

Sustained casing pressure (SCP) is a common issue in the oil and gas industry. There were several solutions applied to contain it either by mechanical means or by injecting high-performing cement slurries. There are some limitations associated with these solutions such as volume loss, mechanical failures, limited expansion, exact spotting, and material deterioration with time. In this study, a novel expandable cement system contains a novel silicate aqueous alkali alumino silicate (AAAS) and zinc (Zn) metal slurry, and class G cement is introduced as an expandable solution to prevent annulus flow between the casing and formation. The silicate-based admixture reacts with the Zn metal slurry to generate hydrogen gas that results in the expansion of the cement slurry. The reaction and expansion can be controlled by optimizing the quantities of silicate systems and metal slurry. The expansive properties of the silicate system can be utilized to formulate a cement mix for plugging off the annulus flow. Cement slurries with different percentages such as 3, 5, and 8% by weight of water (BWOW) of AAAS silicate and Zn metal slurry were prepared and tested for their expansion. Several laboratory tests such as expansion, consistency, viscosity, and unconfined compressive strength were performed to assess the percentage expansion. The expansion was tested in the plastic tube as well as in expansion molds. The cement slurries were cured at 50 °C temperature in a water bath. It was observed that metal slurry upon reaction with AAAS silicate resulted in cement expansion by several percentages. The cement expansion was reduced by 16% at 8% BWOW concentration of AAAS silicate as compared to the expansion gained at 3% BWOW concentration. Further, the temperature triggers the expansion of cement slurry. The consistency and viscosity were impacted by the addition of AAAS and metal slurry. The application of expandable slurry can help in preventing the annulus flow and eliminating the safety issues associated with SCP. The expansion solution can be applied in loss circulation zones.

H2S Scavenging Capacity and Rheological Properties of Water-Based Drilling Muds.

Drilling hydrocarbon formations where hydrogen sulfide (H2S) is present could lead to the carryover of H2S with the drilling mud (i.e., drilling fluid) to the surface, exposing working personnel to this lethal gas. Additionally, H2S is very corrosive, causing severe corrosion of metal parts of the drilling equipment, which in turn results in serious operational problems. The addition of an effective H2S scavenger(s) in the drilling mud formulations will overcome these health, safety, and operational issues. In this work, zinc oxide (ZnO), which is a common H2S scavenger, has been incorporated into water-based drilling mud. The H2S scavenging performance of this ZnO-containing drilling mud has been assessed. Additionally, drilling mud formulations containing either copper nitrate (Cu(NO3)2·3H2O) or potassium permanganate (KMnO4) have been prepared, and their H2S scavenging performances have been studied and compared to that of the ZnO-containing drilling mud. It has been observed that the scavenging performance (in terms of the H2S amounts scavenged up to the breakthrough time and at the saturation condition) of the ZnO-containing drilling mud is very poor compared to those of the copper nitrate-containing and KMnO4-containing drilling muds. For instance, the amounts of H2S scavenged up to the breakthrough time by ZnO-containing, copper nitrate-containing, and KMnO4-containing drilling muds were 5.5, 15.8, and 125.3 mg/g, respectively. Furthermore, the amounts of H2S scavenged at the saturation condition by these drilling muds were, respectively, 35.1, 146.8, and 307.5 mg/g, demonstrating the superiority of the KMnO4-containing drilling mud. Besides its attractive H2S scavenging performance, the KMnO4-containing drilling mud possessed more favorable rheological properties [i.e., plastic viscosity (PV), yield point (YP), carrying capacity of the drill cuttings, and gelling characteristics] relative to the base and the ZnO-containing and copper nitrate-containing drilling muds. The addition of KMnO4 to the base drilling mud increased its apparent viscosity, PV, and YP by 20, 33, and 10%, respectively. Additionally, all tested drilling muds possessed acceptable fluid loss characteristics. To the best of our knowledge, there are so far no published studies concurrently tackling the H2S scavenging (i.e., breakthrough time, breakthrough capacity, saturation time, saturation capacity, and scavenger utilization) and the rheological properties of water-based drilling muds, as demonstrated in the current study, highlighting the novelty of this work.

Imidazolium-Based Ionic Liquids as Clay Swelling Inhibitors: Mechanism, Performance Evaluation, and Effect of Different Anions.

Clay swelling is one of the challenges faced by the oil industry. Water-based drilling fluids (WBDF) are commonly used in drilling operations. The selection of WBDF depends on its performance to improve rheology, hydration properties, and fluid loss control. However, WBDF may result in clay swelling in shale formations during drilling. In this work, the impact of imidazolium-based ionic liquids on the clay swelling was investigated. The studied ionic liquids have a common cation group, 1-allyl-3-methyllimidozium, but differ in anions (bromide, iodide, chloride, and dicyanamide). The inhibition behavior of ionic liquids was assessed by linear swell test, inhibition test, capillary suction test, rheology, filtration, contact angle measurement, scanning electron microscopy, and X-ray diffraction (XRD). It was observed that the ionic liquids with different anions reduced the clay swelling. Ionic liquids having a dicyanamide anion showed slightly better swelling inhibition performance compared to other inhibitors. Scanning electron microscopy images showed the water tendency to damage the clay structure, displaying asymmetrical cavities and sharp edges. Nevertheless, the addition of an ionic liquid to sodium bentonite (clay) exhibited fewer cavities and a smooth and dense surface. XRD results showed the increase in d-spacing, demonstrating the intercalation of ionic liquids in interlayers of clay. The results showed that the clay swelling does not strongly depend on the type of anion in imidazolium-based ILs. However, the type of anion in imidazolium-based ILs influences the rheological properties. The performance of ionic liquids was compared with that of the commonly used clay inhibitor (sodium silicate) in the oil and gas industry. ILs showed improved performance compared to sodium silicate. The studied ionic liquids can be an attractive alternative for commercial clay inhibitors as their impact on the other properties of the drilling fluids was less compared to commercial inhibitors.

Evaluation of Clay Hydration and Swelling Inhibition Using Quaternary Ammonium Dicationic Surfactant with Phenyl Linker.

Water-based drilling fluids are extensively used for drilling oil and gas wells. However, water-based muds cause clay swelling, which severely affects the stability of wellbore. Due to two adsorption positions, it is expected that cationic gemini surfactants can reduce the clay swelling. In this work, quaternary ammonium dicationic gemini surfactants containing phenyl linkers and different counterions (Cl- and Br-) were synthesized, and the effect of variation in counterions on swelling and hydration properties of shales was studied. Numerous water-based drilling fluid formulations were prepared with different concentrations of surfactants to study the swelling inhibition capacity of surfactants. The performance of surfactant-containing drilling muds was evaluated by comparing them with base drilling mud, and sodium silicate drilling mud. Various experimental techniques were employed to study drilling mud characteristics such as rheology and filtration. The inhibition properties of drilling mud formulations were determined by linear swelling experiment, capillary suction time test, particle size distribution measurement, wettability measurements, and X-ray Diffraction (XRD). Experimental results showed that surfactant-based formulation containing bromide counterion exhibited superior rheological properties as compared to other investigated formulations. The filtration test showed that the gemini surfactant with chloride counterion had higher filtrate loss compared to all other formulations. The bentonite swelling was significantly reduced with increasing the concentration of dicationic surfactants as inhibitors, and maximum reduction in the linear swelling rate was observed by using a formulation containing surfactant with chloride counterion. The lowest capillary suction timer (CST) was obtained in the formulation containing surfactant with chloride counterion as less CST indicated the enhanced inhibition capacity. The particle size measurement showed that average bentonite particle size increased upon the addition of surfactants depicting the inhibition capacity. The increase in basal spacing obtained from XRD analysis showed the intercalation of gemini surfactants in interlayers of bentonite. The contact angle measurements were performed to study the wettability of the bentonite film surface, and the results showed that hydrophobicity increased by incorporating the surfactants to the drilling fluid.

Application of a Novel and Sustainable Silicate Solution as an Alternative to Sodium Silicate for Clay Swelling Inhibition.

Shale swelling during drilling operations causes many problems mainly related to wellbore instability. The oil-based muds (OBMs) are very effective in controlling the swelling potential of clay-rich shale formation, but their environmental concerns and the economic aspects curtail their usage. In the application of water-based mud (WBM), it is mixed with various swelling inhibitors such as inorganic salts (KCl and NaCl), sodium silicate, polymers, and amines of various types. The above-mentioned materials are however afflicted by some limitations in terms of their toxicity, their effect on drilling mud rheology, and their limited tolerance toward temperature and oil contamination. In this study, we investigated a novel hybrid aqueous alkali alumino silicate (AAAS) as a shale swelling inhibitor in WBM. The AAAS is a mixture of sodium, aluminum, and silicon oxides. Experimental investigations were carried out using a linear swell meter, hot rolling and capillary suction timer, ζ-potential test, filtration test, and rheology test. The application of hybrid silicate as a swelling inhibitor was studied in two phases. In the first phase, only silicate solutions were prepared in deionized water at various ratios (1, 2, and 5%) and tested on sodium bentonite and shale samples containing high contents of kaolinite clay. Further testing on commonly used inhibitors such as KCl and sodium silicate solutions was conducted for comparative purposes. In the second phase, different drilling mud formulations consisting of various percentages of AAAS were mixed and tested on original shale samples. It was observed that the novel silicate-based mix proved to be a strong shale swelling inhibitor. Its inhibition performance was better as compared to the sodium silicate solution and KCl solution. It not only inhibits shale swelling but also acts as a shale stabilizer due to its high adsorption on the shale surface, which prevents the shale/water reactivity, makes the shale formation stronger, and prevents caving.

Development of New Rheological Models for Class G Cement with Nanoclay as an Additive Using Machine Learning Techniques.

The rheology of the oil well cement plays a pivotal role in the cement placement. Accurate prediction of cement rheological parameters helps to monitor the durability and pumpability of the cement slurry. In this study, an artificial neural network is used to develop different models for the prediction of various rheological parameters such as shear stress, apparent viscosity, plastic viscosity, and yield point of a class G cement slurry with nanoclay as an additive. An extensive experimental study was conducted to generate enough data set for the training of artificial intelligence models. The class G oil well cement slurries were prepared by fixing the water-cement ratio to 0.44 and adding organically modified nanoclays as a strength enhancer. The rheological properties of the oil well cement slurries were investigated at a wide range of temperatures (37 ≤ T ≤ 90 °C) and shear rates (5 ≤ γ ≤ 500 s-1). Experimental data generated were used for the training of feed-forward neural networks. The predicted values of the rheological properties from the trained model showed a good agreement when compared with the experimental values. The average absolute percentage error was less than 5% in both training and validation phases of modeling. A trend analysis was carried out to ensure that the proposed models can define the underlying physics. From the validation and the trend analysis, it was found that the new models can be used to predict cement rheological properties within the range of data set on which the models were trained. The proposed models are independent of laboratory-dependent variables and can give quick and real-time values of the rheological parameters.