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.

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.

Evaluation of the Dynamic Interfacial Tension between Viscoelastic Surfactant Solutions and Oil Using Porous Micromodels.

Interfacial tension (IFT) is a crucial parameter in many natural and industrial processes, such as enhanced oil recovery and subsurface energy storage. IFT determines how easy the fluids can pass through pore throats and hence will decide how much residual fluids will be left behind. Here, we use a porous glass micromodel to investigate the dynamic IFT between oil and Armovis viscoelastic surfactant (VES) solution based on the concept of drop deformation while passing through a pore throat. Three different concentrations of VES, that is, 0.5, 0.75, and 1.25% vol% prepared using 57 K ppm synthetic seawater, were used in this study. The rheology obtained using a rheometer at ambient temperature showed zero shear viscosity of 325, 1101, and 1953 cP for 0.5%, 0.75%, and 1.25% VES, respectively, with a power-law region between 2 and 50 1/s. The dynamic IFT increases with the shear rate and then reaches a plateau. The results of IFT were compared with those obtained from the spinning drop method, which shows 97% accuracy for 1.25% VES, whereas the accuracy decreased to 65% for 0.75 VES and 51% for 0.5% VES. The findings indicate that we can reliably estimate the IFT of VES at higher concentrations directly during multiphase flow in porous micromodels without the need to perform separate experiments and wait for a long time to reach equilibrium.

A Modified Contact Angle Measurement Process to Suppress Oil Drop Spreading and Improve Precision.

Static contact angle measurement is a widely applied method for wettability assessment. Despite its convenience, it suffers from errors induced by contact angle hysteresis, material heterogeneity, and other factors. This paper discusses the oil drop spreading phenomenon that was frequently observed during contact angle measurements. Experimental tests showed that this phenomenon is closely related to surfactants in the surrounding phase, the remaining oil on the rock surface, and oil inside the surrounding phase. A modified contact angle measurement process was proposed. In the modified method, deionized water was used as the surrounding phase, and a rock surface cleaning step was added. Subsequent measurements showed a very low chance of oil drop spreading and improved precision. A further comparison study showed that, when the surrounding phase was deionized water, the measured contact angle values tended to be closer to intermediate-wet conditions compared to the values measured in clean surfactant solutions. This difference became more significant when the surface was strongly water-wet or strongly oil-wet. As a result, the developed process has two prerequisites: that the in-situ contact angle values inside surfactant solutions are not required, and that the wettability alteration induced by the surfactant solution is irreversible.

Effect of Native Reservoir State and Oilfield Operations on Clay Mineral Surface Chemistry.

An understanding of clay mineral surface chemistry is becoming critical as deeper levels of control of reservoir rock wettability via fluid-solid interactions are sought. Reservoir rock is composed of many minerals that contact the crude oil and control the wetting state of the rock. Clay minerals are one of the minerals present in reservoir rock, with a high surface area and cation exchange capacity. This is a first-of-its-kind study that presents zeta potential measurements and insights into the surface charge development process of clay minerals (chlorite, illite, kaolinite, and montmorillonite) in a native reservoir environment. Presented in this study as well is the effect of fluid salinity, composition, and oilfield operations on clay mineral surface charge development. Experimental results show that the surface charge of clay minerals is controlled by electrostatic and electrophilic interactions as well as the electrical double layer. Results from this study showed that clay minerals are negatively charged in formation brines as well as in deionized water, except in the case of chlorite, which is positively charged in formation water. In addition, a negative surface charge results from oilfield operations, except for operations at a high alkaline pH range of 10-13. Furthermore, a reduction in the concentrations of Na, Mg, Ca, and bicarbonate ions does not reverse the surface charge of the clay minerals; however, an increase in sulfate ion concentration does. Established in this study as well, is a good correlation between the zeta potential value of the clay minerals and contact angle, as an increase in fluid salinity results in a reduction of the negative charge magnitude and an increase in contact angle from 63 to 102 degree in the case of chlorite. Lastly, findings from this study provide vital information that would enhance the understanding of the role of clay minerals in the improvement of oil recovery.

Reduction of Breakdown Pressure by Filter Cake Removal Using Thermochemical Fluids and Solvents: Experimental and Numerical Studies.

The process of well cleanup involves the removal of an impermeable layer of filter cake from the face of the formation. The inefficient removal of the filter cake imposes difficulty on fracturing operations. Filter cake's impermeable features increase the required pressure to fracture the formation. In this study, a novel method is introduced to reduce the required breakdown pressure to fracture the formation containing the water-based drilling fluid filter cake. The breakdown pressure was tested for five samples of similar properties using different solutions. A simulated borehole was drilled in the core samples. An impermeable filter cake using barite-weighted drilling fluid was built on the face of the drilled hole of each sample. The breakdown pressure for the virgin sample without damage (filter cake) was 6.9 MPa. The breakdown pressure increased to 26.7 MPa after the formation of an impermeable filter cake. Partial removal of filter cake by chelating agent reduced the breakdown pressure to 17.9 MPa. Complete dissolution of the filter cake with chelating agents resulted in the breakdown pressure approximately equivalent to the virgin rock breakdown pressure, i.e., 6.8 MPa. The combined thermochemical and chelating agent solution removed the filter cake and reduced the breakdown pressure to 3.8 MPa. Post-treatment analysis was carried out using nuclear magnetic resonance (NMR) and scratch test. NMR showed the pore size redistributions with good communication between different pores after the thermochemical removal of filter cake. At the same time, there was no communication between the different pores due to permeability impairment after filter cake formation. The diffusion coupling through NMR scans confirmed the higher interconnectivity between different pores systems after the combined thermochemical and chelating agent treatment. Compressive strength was measured from the scratch test, confirming that filter cake formation caused added strength to the rock that impacts the rock breakdown pressure. The average compressive strength of the original specimen was 44.5 MPa that increased to 73.5 MPa after the formation of filter cake. When the filter cake was partially removed, the strength was reduced to 61.7 MPa. Complete removal with chelating agents removed the extra strength that was added due to the filter cake presence. Thermochemical and chelating agents resulted in a significantly lower compressive strength of 25.3 MPa. A numerical model was created to observe the reduction in breakdown pressure due to the thermochemical treatment of the filter cake. The result presented in this study showed the engineering applications of thermochemical treatment for filter cake removal.

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.

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.

Novel Treatment for Mitigating Condensate Bank Using a Newly Synthesized Gemini Surfactant.

Condensate accumulation in the vicinity of the gas well is known to curtail hydrocarbon production by up to 80%. Numerous approaches are being employed to mitigate condensate damage and improve gas productivity. Chemical treatment, gas recycling, and hydraulic fracturing are the most effective techniques for combatting the condensate bank. However, the gas injection technique showed temporary condensate recovery and limited improvement in gas productivity. Hydraulic fracturing is considered to be an expensive approach for treating condensate banking problems. In this study, a newly synthesized gemini surfactant (GS) was developed to prevent the formation of condensate blockage in the gas condensate reservoirs. Flushing the near-wellbore area with GS will change the rock wettability and thereby reduce the capillary forces holding the condensate due to the strong adsorption capacity of GS on the rock surface. In this study, several measurements were conducted to assess the performance of GS in mitigating the condensate bank including coreflood, relative permeability, phase behavior, and nuclear magnetic resonance (NMR) measurements. The results show that GS can reduce the capillary pressure by as much as 40%, increase the condensate mobility by more than 80%, and thereby mitigate the condensate bank by up to 84%. Phase behavior measurements indicate that adding GS to the oil-brine system could not induce any emulsions at different salinity levels. Moreover, NMR and permeability measurements reveal that the gemini surfactant has no effect on the pore system and no changes were observed in the T2 relaxation profiles with and without the GS injection. Ultimately, this work introduces a novel and effective treatment for mitigating the condensate bank. The new treatment showed an attractive performance in reducing liquid saturation and increasing the condensate relative permeability.

A Novel Approach to Improve Acid Diversion in Carbonate Rocks Using Thermochemical Fluids: Experimental and Numerical Study.

The distribution of acid over all layers of interest is a critical measure of matrix acidizing efficiency. Chemical and mechanical techniques have been widely adapted for enhancing acid diversion. However, it was demonstrated that these often impact the formation with damage after the acid job is completed. This study introduces, for the first time, a novel solution to improve acid diversion using thermochemical fluids. This method involves generating nitrogen gas at the downhole condition, where the generated gas will contribute in diverting the injected acids into low-permeability formations. In this work, both lab-scale numerical and field-scale analytical models were developed to evaluate the performance of the proposed technique. In addition, experimental measurements were carried out in order to demonstrate the application of thermochemical in improving the acid diversion. The results showed that a thermochemical approach has an effective performance in diverting the injected acids into low-permeability rocks. After treatment, continuous wormholes were generated in the high-permeability rocks as well as in low-permeability rocks. The lab-scale model was able to replicate the wormholing impact observed in the lab. In addition, alternating injection of thermochemical and acid fluids reduced the acid volume 3.6 times compared to the single stage of thermochemical injection. Finally, sensitivity analysis indicates that the formation porosity and permeability have major impacts on the acidizing treatment, while the formations pressures have minor effect on the diversion performance.

Influence of Varying Oil-Water Contents on the Formation of Crude Oil Emulsion and Its Demulsification by a Lab-Grown Nonionic Demulsifier.

This study describes how varying oil/water contents affect emulsion formation and the impact they have on emulsion droplet size, viscosity, and interfacial behavior. Crude oil (continuous phase) volume fractions of 40, 50, 60, and 70 vol % were probed in the various W/O emulsions formed. Experimental results from optical morphology revealed the emulsion droplets kept reducing as the crude oil fraction kept increasing, while the droplets were nearly unnoticeable in the emulsions derived from 60 and 70% crude oil. The viscosity-shear rate of emulsions produced from 40, 50, and 60 vol % crude oil exhibited a non-Newtonian behavior owing to the substantial volume of water content in their emulsions, whereas the viscosity-shear rate of the emulsion with 70 vol % crude oil exhibited a Newtonian behavior similar to the pure crude oil, suggesting a thorough blending of oil-water at this crude oil fraction. Besides, the viscosity-temperature measurements revealed that the viscosity of these emulsions diminished as the temperature increased and the viscosity reduction became more noticeable in an emulsion comprising 70 vol % crude oil. In the interfacial assessment, the increased crude oil content in the produced emulsion led to a sharp reduction in the interfacial tension (IFT). The IFT values after 500 s contacts between the emulsion and water (surrounding phase) were 11.86, 10.02, 8.08, and 6.99 mN/m for 40, 50, 60, and 70 vol % crude oil, respectively. Demulsification experiments showed that water removal becomes more challenging with a large volume of crude oil and a small water content. Demulsification performances of the lab-grown nonionic demulsifier (NID) after 10 h of demulsification activity at room temperature (25 °C) were 98, 90, 17.5, and 10% for the emulsions formed from 40, 50, 60, and 70 vol % crude oil, respectively, indicating that the demulsification degree decreases with an increasing crude oil content. Viscosity-time determination was applied to affirm the activity of NID on the emulsion formulated with a 50% crude oil fraction. The injection of NID in this emulsion triggered a sharp viscosity reduction, indicating the adsorption of NID at the oil-water interface and disruption of emulsifiers, enabling emulsion stability.

Impact of Pressure and Temperature on Foam Behavior for Enhanced Underbalanced Drilling Operations.

Foam, a versatile underbalanced drilling fluid, shows potential for improving the drilling efficiency and reducing formation damage. However, the existing literature lacks insight into foam behavior under high-pH drilling conditions. This study introduces a novel approach using synthesized seawater, replacing the conventional use of freshwater on-site for the foaming system's liquid base. This approach is in line with sustainability objectives and offers novel perspectives on foam stability under high-pH conditions. Experiments, conducted with a high-pressure, high-temperature (HPHT) foam analyzer, investigate how pressure and temperature affect foam properties. The biodegradable foaming agent ammonium alcohol ether sulfate (AAES) is employed. Results demonstrate that the pressure significantly impacts foam stability. Increasing pressure enhances stability, reducing decay rates and promoting uniform bubble sizes, especially at lower temperatures. This highlights foam's capacity to withstand high-pressure conditions. Conversely, the temperature plays a substantial role in foam decay, particularly at elevated temperatures (75 and 90 °C). Decreased liquid viscosity accelerates the liquid drainage and foam decay. While pressure mainly influences the AAES foam stability at temperatures up to 50 °C, temperature becomes the dominant factor at higher temperatures. Temperature's impact on foamability is minimal under constant pressure, maintaining consistent gas volume for maximum foam height. However, foam stability is sensitive to temperature variations, with increasing temperature leading to a more significant bubble size increase gradient. These findings stress the importance of considering temperature effects in foam drilling, particularly in deep and high-temperature environments. AAES foam exhibits stability at lower temperatures, making it suitable for surface and intermediate drilling. Understanding temperature-induced changes in foam structure and bubble size is essential for optimizing performance in high-temperature and deep drilling scenarios.

Prediction of Foam Rheology Models Parameters Utilizing Machine Learning Tools.

Rheological models are usually used to predict foamed fluid viscosity; however, obtaining the model constants under various conditions is challenging. Hence, this paper investigated the effect of different variables on foam rheology, such as shear rate, temperature, pressure, surfactant types, gas phase, and salinity, using a high-pressure high-temperature foam rheometer. Power-law, Bingham plastic, and Casson fluid models fit the experimental data well. Therefore, the data were fed to different machine learning techniques to evaluate the rheological model constants with different features. In this study, seven different machine learning techniques have been applied to predict the rheological models' constants, including decision tree, random forest, XGBoost (XGB), adaptive gradient boosting, gradient boosting, support vector regression, and voting regression. We evaluated the performance of our machine learning models using the coefficient of determination (R2), cross-plots, root-mean-square error, and average absolute percentage error. Based on the prediction outcomes, the XGB model outperformed the other ML models. The XGB model exhibited remarkably low error rates, achieving a prediction accuracy of 95% under ideal conditions. Furthermore, our prediction results demonstrated that the Casson model accurately captured the rheological behavior of the foam. Additionally, we used Pearson's correlation coefficients to assess the significance of various properties in relation to the constants within the rheological models. It is evident that the XGB model makes predictions with nearly all features contributing significantly, while other machine learning techniques rely more heavily on specific features over others. The proposed methodology can minimize the experimental cost of measuring rheological parameters and serves as a quick assessment tool.

Demulsification of asphaltene stabilized crude oil emulsions by biodegradable ethylcellulose polymers with varying viscosities.

Efficient demulsifiers for fast demulsification of asphaltene stabilized crude oil emulsions are currently in high demand. In this work, we evaluated the demulsification potential of ethyl cellulose (EC) demulsifiers with varying viscosities-4 cp, 22 cp, and 100 cp, designated as EC-4, EC-22, and EC-100. Demulsifcation efficiency (DE) of these demulsifiers to remove water from emulsions produced from distilled water, seawater, and different salts (NaCl, MgCl2, and CaCl2) solution were assessed using the bottle test technique at ambient and elevated temperatures (25 °C and 90 °C). The bottle test outcomes showed that EC-4 and EC-22 had better performance at the ambient conditions to demulsify the emulsions formed from distilled water with %DE of 85.71% and 28.57%, respectively, while EC-100 achieved 3.9% water removal owing to its high viscosity which inhibited its adsorption at the oil-water interface. At demulsification temperature (90 °C) under the emulsions from distilled water, the %DE of EC-4, EC-22, and EC-100 was 99.23%, 58.57%, and 42.85%, respectively. Seawater hastened the demulsification activities of these demulsifiers. Also, these demulsifiers demonstrated excellent demulsification in emulsions from various salts. The demulsification performance of the EC-4 demulsifier in the presence of any of these salts was approximately 98% while MgCl2 and CaCl2 accelerated the water/oil separation performance of EC-22 and EC-100 by promoting their diffusion and adsorption at the interface. Viscosity and shear stress measurements corroborated the results obtained from the bottle tests. Injection of EC demulsifiers led to a reduction in the viscosity and shear stress of the formed emulsion. Reduction in the shear stress and viscosity were highest in EC-4 and lowest in EC-100. Optical microscopic images of emulsion injected with EC-4 demulsifier were analyzed at various periods during viscosity measurements. Based on the optical images obtained at different durations, a demulsification mechanism describing the activity of the EC demulsifier was proposed.

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.

Impact of Methylene Blue on Enhancing the Hydrocarbon Potential of Early Cambrian Khewra Sandstone Formation from the Potwar Basin, Pakistan.

Significant amounts of hydrocarbon resources are left behind after primary and secondary recovery processes, necessitating the application of enhanced oil recovery (EOR) techniques for improving the recovery of trapped oil from subsurface formations. In this respect, the wettability of the rock is crucial in assessing the recovery and sweep efficiency of trapped oil. The subsurface reservoirs are inherently contaminated with organic acids, which renders them hydrophobic. Recent research has revealed the significant impacts of nanofluids, surfactants, and methyl orange on altering the wettability of organic-acid-contaminated subsurface formations into the water-wet state. This suggests that the toxic dye methylene blue (MB), which is presently disposed of in huge quantities and contaminates subsurface waters, could be used in EOR. However, the mechanisms behind hydrocarbon recovery using MB solution for attaining hydrophilic conditions are not fully understood. Therefore, the present work examines the impacts of MB on the wettability reversal of organic-acid-contaminated Khewra sandstone samples (obtained from the outcrop in the Potwar Basin, Pakistan) under the downhole temperature and pressure conditions. The sandstone samples are prepared by aging with 10-2 mol/L stearic acid and subsequently treated with various amounts of aqueous MB (10-100 mg/L) for 1 week. Contact angle measurements are then conducted under various physio-thermal conditions (0.1-20 MPa, 25-50 °C, and salinities of 0.1-0.3 M). The results indicate that the Khewra sandstone samples become hydrophobic in the presence of organic acid and under increased pressure, temperature, and salinity. However, the wettability changes from oil-wet to preferentially water-wet in the presence of various MB solutions, thus highlighting the favorable effects of MB on EOR from the Khewra sandstone formation. Moreover, the most significant change in wettability is observed for the Khewra sandstone sample that was aged using 100 mg/L MB. These results suggest that injecting MB into deep underground Khewra sandstone reservoirs may produce more residual hydrocarbons.

Investigation of the Coupled Effect of IFT Reduction and Wettability Alteration for Oil Recovery: New Insights.

Interfacial tension (IFT) reduction and wettability alteration (WA) are both important enhanced oil recovery (EOR) mechanisms. In oil-wet formations, IFT reduction reduces the magnitude of negative capillary pressure, releasing trapped oil. WA changes the negative capillary pressure to positive conditions, helping the entrance of the aqueous phase, and the displacement of the oil phase. In most cases, IFT reduction and WA happen at the same time. However, studies regarding the coupled effect provided different, sometimes conflicting observations. It requires further study and better understanding. In our study, oil-aged Indiana limestone samples were chosen to represent oil-wet carbonate rocks. Static contact angle and spinning drop method were adopted for wettability assessment and IFT measurement, respectively. Spontaneous imbibition was adopted to reflect on the oil recovery mechanisms in different cases. The impact of IFT reduction, WA, and permeability on the coupled effect was discussed by choosing four pairs of comparison tests. Results showed that when the coupled effect took place, both a higher IFT value and a stronger WA performance resulted in faster and higher oil recoveries. The importance of IFT reduction was enhanced in the higher-permeability condition, while the importance of WA was enhanced in the lower-permeability condition.

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).

Ecofriendly Natural Surfactants in the Oil and Gas Industry: A Comprehensive Review.

The use of different types of chemicals in upstream oilfield operations is critical for optimizing the different operations involved in hydrocarbon exploration and production. Surfactants are a type chemical that are applied in various upstream operations, such as drilling, fracturing, and enhanced oil recovery. However, due to their nonbiodegradability and toxicity, the use of synthetic surfactants has raised environmental concerns. Natural surfactants have emerged because of the hunt for sustainable and environmentally suitable substitutes. This Review discusses the role of natural surfactants in upstream operations as well as their benefits and drawbacks. The Review discusses the basic characteristics of surfactants, their classification, and the variables that affect their performance. Finally, the Review examines the possible applications of natural surfactants in the upstream oil sector and identifies areas that require further research.

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.