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.

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.

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.

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.

A Guide for Selection of Aging Time and Temperature for Wettability Alteration in Various Rock-Oil Systems

Wettability alteration has been identified to be one of the important mechanisms to improve the microscopic recovery in many of the enhanced oil recovery (EOR) methods including polymer flood, surfactant flood, low salinity flood, microbial flood, alkaline flood, etc. Ensuring the oil-wet nature of the formation before flooding in the laboratory is necessary to study the efficiency of the EOR process, which targets microscopic recovery through wettability alteration. Nevertheless, altering the wettability depends on several parameters, such as aging time, aging temperature, core nature, oil properties, etc. Although several researchers investigated the effect of individual parameters on wettability alteration, the literature is scarce, and the question of what is the shortest and yet the most reliable aging time for ensuring wettability alteration for the specific rock-oil system at different temperatures remains unclear. This paper attempts to seek an answer to this question by compiling the relevant literature to find the effect of individual parameters such as different aging times, temperatures, oil compositions, and rock lithologies on wettability alteration. Results observed from data analysis showed different windows for aging conditions depending on the core sample lithology, initial wettability, and type of oil used. It was noticed that the higher the asphaltene content in the crude oil used, the lower the time and temperature that it takes to alter the sample wettability. Aging a sandstone core under 80 °C using crude oil with 11 wt % % asphaltene took 7 days to shift the core from strongly water-wet to neutral-wet. The same wettability alteration was achieved in 14 days when aging the sandstone sample at 90 °C using crude oil with 0.85 wt % asphaltene content. Generally, it was observed that the aging time decreased as the temperature increased. Moreover, as the sample has a lower initial water wettability condition, the time that it needs to be aged becomes higher. Results indicated that carbonates in general require less aging time to alter their wettability condition to oil-wet, around 1-7 days, compared with sandstones, around 14-21 days.

Static and dynamic adsorption of a gemini surfactant on a carbonate rock in the presence of low salinity water

In chemical enhanced oil recovery (cEOR) techniques, surfactants are extensively used for enhancing oil recovery by reducing interfacial tension and/or modifying wettability. However, the effectiveness and economic feasibility of the cEOR process are compromised due to the adsorption of surfactants on rock surfaces. Therefore, surfactant adsorption must be reduced to make the cEOR process efficient and economical. Herein, the synergic application of low salinity water and a cationic gemini surfactant was investigated in a carbonate rock. Firstly, the interfacial tension (IFT) of the oil-brine interface with surfactant at various temperatures was measured. Subsequently, the rock wettability was determined under high-pressure and high-temperature conditions. Finally, the study examined the impact of low salinity water on the adsorption of the cationic gemini surfactant, both statically and dynamically. The results showed that the low salinity water condition does not cause a significant impact on the IFT reduction and wettability alteration as compared to the high salinity water conditions. However, the low salinity water condition reduced the surfactant's static adsorption on the carbonate core by four folds as compared to seawater. The core flood results showed a significantly lower amount of dynamic adsorption (0.11 mg/g-rock) using low salinity water conditions. Employing such a method aids industrialists and researchers in developing a cost-effective and efficient cEOR process.

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.

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.

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).

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

Rheological Study of Seawater-Based Fracturing Fluid Containing Polymer, Crosslinker, and Chelating Agent

Freshwater is usually used in hydraulic fracturing as it is less damaging to the formation and is compatible with the chemical additives. In recent years, seawater has been the subject of extensive research to reduce freshwater consumption. The study aims to optimize the rheology of seawater-based fracturing fluid with chemical additives that reduce the formation damage. The studied formulation consists of a polymer, a crosslinker, and a chelating agent to reduce seawater hardness. We used a standard industry rheometer to perform the rheology tests. By comparing five distinct grades [hydroxypropyl guar (HPG) and carboxymethyl hydroxypropyl guar (CMHPG)], we selected the guar derivative with the best rheological performance in seawater. Five different polymers (0.6 wt %) were hydrated with seawater and freshwater to select the suitable one. Then, the best performing polymer was chosen to be tested with (1.6, 4, and 8 wt %) N, N-dicarboxymethyl glutamic acid GLDA chelating agent and 1 wt % zirconium crosslinker. In the first part, the testing parameters were 120 °C temperature, 500 psi pressure, and 100 1/s shear rate. Then, the same formulations were tested at a ramped temperature between 25 and 120 °C. We observed that higher and more stable viscosity levels can be achieved by adding the GLDA after polymer hydration. In seawater, an instantaneous crosslinking occurs once the crosslinker is added even at room temperature, while in freshwater, the crosslinker is activated by ramping the temperature. We noted that, in the presence of a crosslinker, small changes in the chelating agent concentration have a considerable impact on the fluid rheology, as demonstrated in ramped temperature results. It is observed that the viscosities are higher and more persistent at lower concentrations of GLDA than at higher concentrations. The study shows the rheological response when different chemical additives are mixed in saline water for hydraulic fracturing applications.

Effect of Sulfate-Based Scales on Calcite Mineral Surface Chemistry: Insights from Zeta-Potential Experiments and Their Implications on Wettability

Scale formation and deposition in the subsurface and surface facilities have been recognized as a major cause of flow assurance issues in the oil and gas industry. Sulfate-based scales such as sulfates of calcium (anhydrite and gypsum) and barium (barite) are some of the commonly encountered scales during hydrocarbon production operations. Oilfield scales are a well-known flow assurance problem, which occurs mainly due to the mixing of incompatible brines. Researchers have largely focused on the rocks' petrophysical property modifications (permeability and porosity damage) caused by scale precipitation and deposition. Little or no attention has been paid to their influence on the surface charge and wettability of calcite minerals. Thus, this study investigates the effect of anhydrite and barite scales' presence on the calcite mineral surface charge and their propensity to alter the wetting state of calcite minerals. This was achieved vis-à-vis zeta-potential (ζ-potential) measurement. Furthermore, two modes of the scale control (slug and continuous injections) using ethylenediaminetetraacetic acid (EDTA) were examined to determine the optimal control strategy as well as the optimal inhibitor dosage. Results showed that the presence of anhydrite and barite scales in a calcite reservoir affects the colloidal stability of the system, thus posing a threat of precipitation, which would result in permeability and porosity damage. Also, the calcite mineral surface charge is affected by the presence of calcium and barium sulfate scales; however, the magnitude of change in the surface charge via ζ-potential measurement is insignificant to cause wettability alteration by the mineral scales. Slug and continuous injections of EDTA were implemented, with the optimal scale control strategy being the continuous injection of EDTA solutions. The optimal dosage of EDTA for anhydrite scale control is 5 and 1 wt % for the formation water and seawater environments, respectively. In the case of barite, in both environments, an EDTA dosage of 1 wt % suffices. Findings from this study not only further the understanding of the scale effects on calcite mineral systems but also provide critical insights into the potential of scale formation and their mechanisms of interactions for better injection planning and the development of a scale control strategy.

Iron Sulfide Scale Inhibition in Carbonate Reservoirs

Hydrocarbon production operations include water injection, varying stimulation approaches, and enhanced oil recovery techniques. These treatments often affect reservoir formation, production, and injection facilities. Such sorts of well operations cause the formation of organic and inorganic scales in the near-wellbore region and various production and injection structures. Downhole squeeze treatment is commonly used as a control measure to prevent scale precipitation. A scale inhibitor solution is introduced into a formation by applying a squeeze treatment. The method allows scale inhibitors to adsorb on the internal rock surface to avoid settling down the scale precipitates. Thus, the study of adsorption of different types of inhibitors to prevent scale formation on the reservoir rock through the execution of downhole squeeze treatment is becoming necessary. This study incorporated different experimental techniques, including dynamic adsorption experiments of chelating agents employing a coreflooding setup, inductively coupled plasma-optical emission spectrometry (ICP-OES) to inhibit the formation of iron-containing scales in limestone rocks, and ζ-potential measurements targeting determination of iron precipitation in varying pH environments on calcite minerals. The influence of the inhibitor soaking time and salt existence in the system on chelating agent adsorption was also evaluated in the coreflooding experiments. The findings based on the coreflooding tests reveal that the concentration of chelating agents plays a significant role in their adsorption on carbonate rocks. The treatments with 20 wt % ethylenediaminetetraacetic acid (EDTA) and 20 wt % diethylenetriaminepentaacetic acid produced the highest adsorption capacity in limestone rock samples by inhibiting 84 and 85% of iron(III) ions, respectively. Moreover, the presence of the salts (CaCl₂ and MgCl₂) considerably decreased the adsorption of 10 wt % EDTA to 56% (CaCl₂) and 52% (MgCl₂) and caused nearly 20% more permeability reduction, while more inhibitor soaking time resulted in comparably higher adsorption and lesser permeability diminution. The results of ζ-potential measurements showed that the pH environment controls iron(II) and (III) precipitation, and iron(III) starts to deposit from a low pH region, whereas iron(II) precipitates in increased pH environments in calcite minerals.

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.

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.

Application of Polymers for Chemical Enhanced Oil Recovery: A Review

Polymers play a significant role in enhanced oil recovery (EOR) due to their viscoelastic properties and macromolecular structure. Herein, the mechanisms of the application of polymeric materials for enhanced oil recovery are elucidated. Subsequently, the polymer types used for EOR, namely synthetic polymers and natural polymers (biopolymers), and their properties are discussed. Moreover, the numerous applications for EOR such as polymer flooding, polymer foam flooding, alkali–polymer flooding, surfactant–polymer flooding, alkali–surfactant–polymer flooding, and polymeric nanofluid flooding are appraised and evaluated. Most of the polymers exhibit pseudoplastic behavior in the presence of shear forces. The biopolymers exhibit better salt tolerance and thermal stability but are susceptible to plugging and biodegradation. As for associative synthetic polyacrylamide, several complexities are involved in unlocking its full potential. Hence, hydrolyzed polyacrylamide remains the most coveted polymer for field application of polymer floods. Finally, alkali–surfactant–polymer flooding shows good efficiency at pilot and field scales, while a recently devised polymeric nanofluid shows good potential for field application of polymer flooding for EOR.

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.

Feature Ranking and Modeling of Mineral Effects on Reservoir Rock Surface Chemistry Using Smart Algorithms

Reservoir rock minerals and their surface charge development have been the subject of several studies with a consensus reached on their contribution to the control of reservoir rock surface interactions. However, the question of what factors control the surface charge of minerals and to what extent do these factors affect the surface charge remains unanswered. Also, with several factors identified in our earlier studies, the question of the order of effect on the mineral surface charge was unclear. To quantify the mineral surface charge, zeta potential measurements and Deryaguin-Landau-Verwey-Overbeek (DLVO) theories, as well as surface complexation models, are used. However, these methods can only predict a single mineral surface charge and cannot approximate the reservoir rock surface. This is because the reservoir rock is composed of many minerals in varying proportions. To address these drawbacks, for the first time, we present the implementation of machine learning models to predict reservoir minerals' surface charge. Four different models namely the Adaptive Boosting Regressor, Random Forest Regressor, Support Vector Regressor, and the Gradient Boosting tree were implemented for this purpose with all the model predictions over 95% accuracy. Also, feature ranking of the factors that control the mineral surface charge was carried out with the most dominant factors being the mineral type, salt type, and pH of the environment. Findings reveal an opportunity for accurate prediction of reservoir rock surface charge given the enormous amount of data available.

Surfactant Adsorption Isotherms: A Review

The need to minimize surfactant adsorption on rock surfaces has been a challenge for surfactant-based, chemical-enhanced oil recovery (cEOR) techniques. Modeling of adsorption experimental data is very useful in estimating the extent of adsorption and, hence, optimizing the process. This paper presents a mini-review of surfactant adsorption isotherms, focusing on theories of adsorption and the most frequently used adsorption isotherm models. Two-step and four-region adsorption theories are well-known, with the former representing adsorption in two steps, while the latter distinguishes four regions in the adsorption isotherm. Langmuir and Freundlich are two-parameter adsorption isotherms that are widely used in cEOR studies. The Langmuir isotherm is applied to monolayer adsorption on homogeneous sites, whereas the Freundlich isotherm suites are applied to multilayer adsorption on heterogeneous sites. Some more complex adsorption isotherms are also discussed in this paper, such as Redlich-Peterson and Sips isotherms, both involve three parameters. This paper will help select and apply a suitable adsorption isotherm to experimental data.

Development of Oil and Gas Stimulation Fluids Based on Polymers and Recycled Produced Water

Freshwater scarcity is a highly pressing and accelerating issue facing our planet. Therefore, there is a great incentive to develop sustainable solutions by reusing wastewater or produced water (PW), especially in places where it is generated abundantly. PW represents the water produced as a by-product during oil and gas extraction operations in the petroleum industry. It is the largest wastewater stream within the industry, with hundreds of millions of produced water barrels per day worldwide. This research investigates a reuse opportunity for PW to replace freshwater utilization in well stimulation applications. Introducing an environmentally friendly chelating agent (GLDA) allowed formulating a PW-based fluid system that has similar rheological properties in fresh water. This work aims at evaluating the rheological properties of the developed stimulation fluid. The thickening profile of the fluid was controlled by chelation chemistry and varying different design parameters. The experiments were carried out using a high-pressure, high-temperature (HPHT) viscometer. Variables such as polymer concentration and pH have a great impact on the viscosity, while temperature and concentration of the chelating agents are shown to control the thickening profile, as well as its stability and breakage behaviors. Furthermore, 50 pptg of carboxymethyl hydroxypropyl guar (CMHPG) polymer in 20 wt.% chelating solution was shown to sustain 172 cP viscosity for nearly 2.5 h at 150 °F and 100 S⁻¹ shear rate. The newly developed fluid system, solely based on polymer, chelating agent, and PW, showed great rheological capabilities to replace the conventional stimulation fluids based on fresh water. The newly developed fluid can also have economic value realization due to fewer additives, compared with conventional fluids.

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.

Impact of Asphaltene Precipitation and Deposition on Wettability and Permeability

Asphaltene precipitation and deposition have been a formation damage problem for decades, with the most devastating effects being wettability alteration and permeability impairment. To this effect, a critical look into the laboratory studies and models developed to quantify/predict permeability and wettability alterations are reviewed, stating their assumptions and limitations. For wettability alterations, the mechanism is predominantly surface adsorption, which is controlled by the asphaltene contacting minerals as they control the surface chemistry, charge, and electrochemical interactions. The most promising wettability alteration evaluation techniques are nuclear magnetic resonance, ζ potential, and the use of high-resolution microscopy. The integration of such techniques, which is still missing, would reinforce the understanding of asphaltene interaction with rock minerals (especially clays), which holds the key to developing a strategy for modeling wettability alteration. With regard to permeability impairment, surface deposition, pore plugging, and fine migration have been identified as the dominant mechanisms with several models reporting the simultaneous existence of multiple mechanisms. Existing experimental findings showed that asphaltene deposition is non-uniform due to mineral distribution which further complicates the modeling process. It also remains a challenge to separate changes due to adsorption (wettability changes) from those due to pore size reduction (permeability impairment).

Impact of Asphaltene Precipitation and Deposition on Wettability and Permeability

Asphaltene precipitation and deposition have been a formation damage problem for decades, with the most devastating effects being wettability alteration and permeability impairment. To this effect, a critical look into the laboratory studies and models developed to quantify/predict permeability and wettability alterations are reviewed, stating their assumptions and limitations. For wettability alterations, the mechanism is predominantly surface adsorption, which is controlled by the asphaltene contacting minerals as they control the surface chemistry, charge, and electrochemical interactions. The most promising wettability alteration evaluation techniques are nuclear magnetic resonance, ζ potential, and the use of high-resolution microscopy. The integration of such techniques, which is still missing, would reinforce the understanding of asphaltene interaction with rock minerals (especially clays), which holds the key to developing a strategy for modeling wettability alteration. With regard to permeability impairment, surface deposition, pore plugging, and fine migration have been identified as the dominant mechanisms with several models reporting the simultaneous existence of multiple mechanisms. Existing experimental findings showed that asphaltene deposition is non-uniform due to mineral distribution which further complicates the modeling process. It also remains a challenge to separate changes due to adsorption (wettability changes) from those due to pore size reduction (permeability impairment).

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.

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.

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.

A Surface Charge Approach to Investigating the Influence of Oil Contacting Clay Minerals on Wettability Alteration

Reservoir rock wettability has been linked to the adsorption of crude fractions on the rock, with much attention often paid to the bulk mineralogy rather than contacting minerals. Crude oil is contacted by different minerals that contribute to rock wettability. The clay mineral effect on wettability alterations is examined using the mineral surface charge. Also, the pH change effect due to well operations was investigated. Clay mineral surface charge was examined using zeta potential computed from the particle electrophoretic mobility. Clay minerals considered in this study include kaolinite, montmorillonite, illite, and chlorite. Results reveal that the clay mineral charge development is controlled by adsorption of ionic species and double layer collapse. Also, clay mineral surface charge considered in this study shows that their surfaces become more conducive for the adsorption of hydrocarbon components due to the presence of salts. The salt effect is greater in the following order: NaHCO₃ < Na₂SO₄ < NaCl < MgCl₂ < CaCl₂. Furthermore, different well operations induce pH environments that change the clay mineral surface charge. This change results in adsorption prone surfaces and with reservoir rock made up of different minerals, and the effect of contacting minerals is critical as shown in our findings. This is due to the contacting mineral control wettability rather than the bulk mineralogy.

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.

Impact of Iron Minerals in Promoting Wettability Alterations in Reservoir Formations

Asphaltene adsorption and deposition onto rock surfaces are predominantly the cause of wettability and permeability alterations which result in well productivity losses. These alterations can be induced by rock-fluid interactions which are affected by well operations such as acidizing, stimulation, gas injections, and so forth. Iron minerals are found abundantly in sandstone reservoir formations and pose a problem by precipitation and adsorption of polar crude components. This is due to rock-fluid interactions, which are dependent on reservoir pH; thus, this research work studied the surface charge development of pyrite, magnetite, and hematite. To ascertain conditions that will result in iron mineral precipitation and adsorption of asphaltene on iron mineral surfaces, zeta potential measurement was carried out. This is to determine the charge and colloidal stability of the iron mineral samples across wide pH values. Experimental results show that the charge development of iron minerals is controlled by mineral dissolution, the formation of complexes, adsorption of ions on the mineral surface, and the collapse of the double layer. The findings provide insights into the implications of iron mineral contacting crude oil in reservoir formations and how they contribute to wettability alterations due to different well operations.

Effect of Conformance Control Patterns and Size of the Slug of In Situ Supercritical CO2 Emulsion on Tertiary Oil Recovery by Supercritical CO2 Miscible Injection for Carbonate Reservoirs

The reservoir heterogeneity is the major cause of poor volumetric sweep efficiency in sandstone and carbonate reservoirs. Displacing fluids (water, chemical solution, gas, and supercritical CO₂ (sc-CO₂)) flow toward the high permeable zone. A significant fraction of oil remains in the low permeable zone due to the permeability contrast. This study used in situ sc-CO₂ emulsion as a conformance control agent to plug the high permeable zone and improve the low permeable zone's volumetric sweep efficiency in carbonate formation. We investigated the effect of two types of conformance control patterns and the size of sc-CO₂ emulsion on tertiary oil recovery performance by sc-CO₂ miscible injection for carbonate reservoirs at reservoir conditions. The conformance control patterns are achieved using two different approaches. In the first approach, the low permeable zone was isolated, and the diverting gel system, a 0.4 pore volume slug, was injected into a high permeable zone. In the second approach, the simultaneous injection of the diverting gel system, a 0.2 pore volume slug, was done on both the low and high permeable zones. The first sc-CO₂ injection was conducted as a tertiary oil recovery mode to recover the remaining oil after water flooding. The diverting gel system was injected after the first sc-CO₂ flood for the conformance control. The second or post sc-CO₂ injection was conducted after the diverting gel system injection. The diverting gel system used in this study consisted of a polymer and a surfactant. An in situ emulsion was generated when the injected diverting gel system interacts with the sc-CO₂ in the core plug. Results obtained from dual-core core flooding experiments suggested that the in situ sc-CO₂ emulsion was generated successfully in the formation based on the different pressure increases and observation of the dual-core core flooding experiments. The volumetric sweep efficiency and oil recovery in both conformance control patterns were improved. The production performances were also compared for both conformance control models before and after the diverting gel system injection. The conformance control model 2 (simultaneous injection of the diverting gel system into low and high permeability cores) has a better choice to be applied in field application due to high recovery with a small sc-CO2 emulsion easy operation in the field.

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.

Comprehensive Investigation of Dynamic Characteristics of Amphoteric Surfactant-Sulfonated Polymer Solution on Carbonate Rocks in Reservoir Conditions

To recover the remaining oil after water flooding, amphoteric surfactant-sulfonated polymer (S-P) flooding has attracted attention as a tertiary oil recovery technique. Oil recovery by S-P flooding not only is influenced by reservoir heterogeneity but also depends on chemical adsorption and interactions of S-P solution with the surface of rocks. This paper presents comprehensive laboratory results related to the dynamic adsorption, resistance factor (RF), residual resistance factor (RRF), and adsorbed layer thickness of S-P solution on the surface of carbonate rocks. Three core flooding experiments were conducted. The S-P solution was composed of an amphoteric surfactant (0.2 wt %) and sulfonated polymer solution (0.2 wt %) in seawater. The S-P solution was injected until the effluent concentration reached the inlet concentration. Seawater was injected after S-P injection to displace S-P solution until the effluent concentration reduced to a minimum value or constant value for desorption study. Total organic carbon (TOC) and Hyamine methods were used to determine the adsorption of the polymer and surfactant, respectively. The individual amount of dynamic adsorption and the total amount of adsorption of S-P solution onto carbonate rock were determined and compared with the results of single adsorption of a surfactant solution published previously. The residual resistance factor, resistance factor, and adsorbed layer thickness of S-P solution on carbonate rocks were calculated based on the differential pressure before and after injecting the S-P solution. We found that the dynamic adsorption, RF, RRF, and adsorbed layer thickness of the S-P solution strongly depends on pore geometry or reservoir properties. Some of the relationships are proposed for the first time. The loss of injectivity and liquid permeability during S-P solution injection are evaluated in detail in this paper. This paper presents insights into the dynamic adsorption, residual resistance factor, resistance factor, adsorbed layer thickness, and injectivity of S-P solution on carbonate rocks with reservoir parameters, which could help in designing the chemical enhanced oil recovery process in carbonate reservoirs.

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.

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.

Novel Approach for Sandstone Acidizing Using in Situ-Generated Hydrofluoric Acid with the Aid of Thermochemicals

In this study, an in situ-generated hydrofluoric acid (HF) was used for sandstone acidizing, where an acid precursor (ammonium fluoride NH₄F) reacted with a suitable oxidizer (sodium bromates NaBrO₃) in an exothermic reaction. First, the new chemical mixture was prepared to react with pure quartz samples and the reaction effluent was analyzed to identify the presence of Si⁺ ions using the inductively coupled plasma (ICP) technique. Core flooding experiments were performed using Gray Berea sandstone cores (6 in. length and 1.5 in. diameter). A preflush stage of 5 PV of 7 wt % HCl was injected to remove any calcite content in the core. The main chemicals were then flushed for 3 successive cycles of 1 PV each. To assure core integrity, scratch tests and NMR scans were run on the core sample before and after the treatment. The new chemical mixture could dissolve the quartz sample and reduce its weight by 80 mg. The concentration of the dissolved Si⁺ ions was more than 90 ppm. This proves the capability of the chemical mixture to generate HF. The initial core permeability was measured at a stabilized flow rate of 2 cm³/min to be 33 mD. After the acid preflush stage, the core permeability reduced to 31 mD. Core permeability increased immediately after the first treatment cycle and reached 41 mD. At the end, the core flooding results showed a permeability improvement for Gray Berea sandstone cores by almost 40%. The ICP analysis of the effluent showed a total amount of chelated Si⁺ ions of about 10.5 mg. In addition to the high temperature generated in the near-wellbore area, the pressure increased because of the produced nitrogen gas from the exothermic reaction and reached about 600 psi. The scratch test showed an increase in the sample uniaxial compressive strength from 7432 to 9235 psi. The dynamic Poisson's ratio and the dynamic Young's modulus increased as well from 0.17 to 0.19 and from 2159 to 3585 ksi, respectively. The enhancement in the mechanical properties of the core can be attributed to the presence of the potassium element in Berea cores and its solidification reaction with the HF generated. The NMR measurements of the core sample before and after the acidizing process show an increase in the core porosity; however, the core preserved its original pore system. Upon application of this new stimulation technology, the true production potential of sandstone reservoirs can be achieved, well tubular corrosion will be minimized, and handling hazardous chemicals such as HF will be avoided. Most importantly, controlling the reaction rate, by controlling the amount of exothermic chemicals, can ensure deep acid penetration as well.

Performance Evaluation of Novel Polymers for CO2 Foam Enhanced Oil Recovery

The oil recovery from foam flooding mainly depends on the stability of the foam flow in porous media. At severe reservoir conditions, CO2 foam becomes unstable due to water drainage and gas diffusion through the lamella. The petroleum industry is using several foaming agents to produce and stabilize the CO2 foams. These are mainly water-soluble surfactants, CO2 soluble surfactants, nanoparticles, and water-soluble polymers. Addition of a water-soluble polymer in a conventional foam can increase foam stability, viscosity, and oil tolerance. Most of the previous studies utilized partially hydrolyzed polyacrylamide (HPAM) for CO2 foam stabilization. However, the data on CO2 foam stabilization using other polymers is limited.

In this work, CO2 foam stability was assessed using several novel polymers. The foam was generated using alpha olefin sulfonate (AOS) surfactant at a constant concentration. These polymers were mainly acrylamide-based sulfonated polymers that contain thermally stable monomers that increase salt tolerance and thermal stability. The foamability, foam stability, foam diameter and bubble count per unit area of different foaming systems were measured using a dynamic foam analyzer.

The result showed that the addition of polymers enhanced foam stability and reduced liquid drainage. Novel sulfonated polymers showed much better performance compared to the conventional HPAM polymer. Reduction in liquid drainage rate was much higher for sulfonated polymers compared to the conventional HPAM due to viscosity of the foaming solutions. For HPAM, the viscosity of the solution reduced at high temperature in presence of salts whereas sulfonated polymers maintained a high viscosity in the presence of salts that resulted in less liquid drainage and enhanced foam stability. The foam stability was also assessed using foam structure analysis.

This is the first systematic study on the application of sulfonated polymer with varying molecular weight and structure for CO2 foam stabilization. This study helps in understanding the role of polymer molecular structure, molecular weight, and degree of hydrolysis on foam stabilization for CO2 -EOR.

Surface and thermal properties of synthesized cationic poly(ethylene oxide) gemini surfactants: the role of the spacer

The solubility and heat stability of surfactants are the prerequisites for their oilfield applications. Most commercial surfactants undergo hydrolysis at high temperature and prolonged heating at 40 °C or above leads to decomposition. In this report, three cationic poly(ethylene oxide) gemini surfactants (GSs) containing flexible and rigid spacers were synthesized for oilfield applications. The chemical structures of the GSs were elucidated with the aid of ¹³C NMR, ¹H NMR, FT-IR, and MALDI-TOF MS. The GSs exhibit pronounced solubility in deionized water, seawater, and formation brine and no cloudiness, phase separation, or precipitation were detected after keeping GS solutions in an oven at 90 °C for three weeks. According to thermal gravimetric analysis, the degradation temperature of all the GSs was above 240 °C, which is higher than the existing oilfield temperature (≥90 °C). The critical micelle concentration (CMC) of the synthesized GSs decreases upon increasing the temperature. Additionally, CMC values were observed to increase even further with increasing salinity. The low CMC values of gemini surfactants containing a flexible structure indicate that they create a more closely packed micelle structure compared with gemini surfactants with a rigid structure. The distinct surface and thermal features of the synthesized GSs reveal them to be appropriate materials for high salinity and elevated temperature reservoirs.

Synthesis of new cationic poly(ethylene oxide) gemini surfactants containing flexible and rigid spacer groups to tolerate harsh reservoir condition.