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.

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.

From declared asset retirement obligations to a decommissioning cost estimate for onshore crude oil fields in Nigeria.

As in most mature crude oil producing regions, asset divestment has commenced in Nigeria. Decommissioning and associated environmental liabilities are expected to become important problems requiring attention. Public and government engagement on decommissioning will be ineffective without information on cost of decommissioning liabilities, which are held confidential by oil companies. This study demonstrates a method to determine generic aggregate cost of decommissioning liabilities for Nigeria onshore fields, using non-proprietary data from annual financial reports of operating companies in Nigeria. The results can be used as basis for negotiation with operators and to help government in preparation for decommissioning risk.

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.

Primary Investigation of Barite-Weighted Water-Based Drilling Fluid Properties.

Drilling fluid is a critical component in drilling operation due to its various functions. It consists of many elements, and one of the main components is the weighting material which controls the mud density. The weighting material type and concentration have a significant impact on the drilling fluid properties. A common weighting material used in the oil and gas industry is barite. In this work, the impact of barite concentration on water-based drilling fluid was evaluated. The investigated drilling fluid properties are density, pH value, filtration behavior, and rheological parameters. An intense investigation was carried out to evaluate the impact of barite concentration on the filtration and filter cake sealing properties. The density and pH values were measured at room temperature, filtration test was performed at room temperature, and differential pressure was equal to 100 psi. The rheological parameters were determined after hot rolling for 16 h at a temperature of 250 °F. The results showed that both the density and pH value increased linearly with barite dosage. The filtration volume, filter cake thickness, and permeability increased with the incremental increase in barite dosage, and the exponential relationship was the best in describing the relation with barite concentration. However, the filter cake porosity had an inverse proportional relation with barite dosage. In the case of rheological properties, all the investigated properties including the plastic viscosity, yield point, ratio of yield point to plastic viscosity, and gel strength at two different times (i.e., 10 s and 10 min) increased in general as the barite concentration increased.

Assessment of Serum Electrolytes and Glycated Hemoglobin Level in Non-diabetic Iron-Deficient Anaemic Patients.

INTRODUCTION: The WHO has recognised iron deficiency anaemia (IDA) as the most common nutritional deficiency in the world, with 30% of the population being affected by this condition. The patient's glycemic status during the past three months is shown by the glycated haemoglobin A1C (HbA1c) test. According to several studies, iron deficiency can increase HbA1C levels without affecting blood sugar levels. HbA1C levels of ≥ 6.5% have been approved by the American Diabetes Association (ADA) as a diagnostic indicator for diabetes mellitus (DM). An imbalance in serum electrolyte levels and anaemia have been linked by several studies.  Aim: To analyze the effect of iron deficiency anaemia on HbA1c levels and serum electrolytes in an adult non-diabetic population. METHODS: This was a descriptive cross-sectional study conducted in Shri BM Patil Medical College, Hospital and Research Centre, Vijayapura, Karnataka, India from January 2021 to June 2022. A total of 65 moderate to severe normoglycemic iron deficiency anemia patients between 18 to 75 years were enrolled in the study after fulfilling inclusion and exclusion criteria. A detailed history, clinical and biochemical examination was performed including HbA1c levels. The results were pooled and statistical analyses were performed using Statistical Package for Social Sciences (SPSS) version 20 (IBM Corp., Armonk, NY, USA). RESULTS: We found elevated HbA1c levels (5.67±1.1%) in non-diabetic iron-deficient anaemia individuals, and elevation was more in women of reproductive age group (30.8%). There was a statistically significant Spearman negative correlation between hemoglobin and HbA1C levels. Also, 16 patients had hyponatremia with a mean haemoglobin (Hb) of 4.8 g/dL and one patient had hyperkalemia with a mean Hb of 3.2 g/dL which was statistically non-significant. CONCLUSION: In this study haemoglobin and HbA1c had a statistically significant positive correlation with serum sodium and a negative correlation with serum potassium in moderate to severely iron-deficient anaemic patients, especially females of the reproductive age group.

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.

Novel Environmentally Friendly Nanomaterials for Drag Reduction of the Emulsified Acid System.

Matrix acidizing is a technique that is widely used in the petroleum industry to remove scales and create channels in the rock. Removal of scales and creation of channels (wormhole) enhance productivity. Conventional acidizing fluids, such as hydrochloric acid (HCl) for carbonate and a mixture of hydrofluoric acid (HF) and HCl acid, are used for the matrix acidizing process. However, these fluids have some drawbacks, including strong acid strength, corrosion at high temperatures, and quick reactions with scale and particles. Emulsified acid systems (EASs) are used to address these drawbacks. EASs can create deeper and narrower wormholes by reducing the reaction rate of the acid due to the external oil phase. However, EASs have a much higher viscosity compared to conventional acidizing fluids. The high viscosity of EASs leads to a high drag that restricts pumping rates and consumes energy. This study aims to utilize environmentally friendly and widely available nanomaterials as drag-reducing agents (DRAs) of the EAS. The nanomaterials used in this study are carbon nanodots (CNDs). CNDs have unique properties and are used in diverse applications in different industries. The size of these CNDs is usually smaller than 10 nm. CNDs are characterized by their biocompatibility and chemical stability. This study investigates the use of CNDs as DRAs for EAS. Several experiments have been conducted to investigate the CNDs as a DRA for the EAS. The developed EAS was initially tested for conductivity and drop-test analysis to ensure the formation of an inverted emulsion. Thereafter, the thermal stability for the range of temperatures and the rheological properties of the EAS were evaluated to meet the criteria of field operation. Then flow experiments with EASs were conducted before and after adding the CNDs to investigate the efficacy of drag reduction of EASs. The results revealed that CNDs can be used as viscosity reducers for the EAS, where adding the CNDs to the EAS reduces the viscosity at two different HCl concentrations (15 and 20%). It reduces the viscosity of the EAS in the presence of corrosion inhibitors as well as other additives to the EAS, showing its compatibility with the field formulation. The drag reduction was observed at the range of temperatures investigated in the study. The conductivity, stability, and rheology experiments for the sample taken after the flow experiment are consistent, ensuring CNDs work as a DRA. The developed EAS with CNDs is robust in terms of field mixing procedures and thermally stable. The CNDs can be used as a DRA with EAS, which will reduce drag in pipes, increasing pumping rates and saving energy.

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.

Papillary Thyroid Carcinoma Arising from Thyroglossal Cyst-an Institutional Experience over a Decade.

Papillary carcinoma constitutes 80% of thyroglossal duct cyst carcinoma (TGCC). The mainstay of treatment for TGCC is Sistrunk procedure. Due to lack of clear-cut guidelines in managing TGCC, the role of total thyroidectomy, neck dissection and adjuvant radioiodine therapy is still debatable. This was a retrospective study which included cases of TGCC treated in our institution over a period of 11 years. The aim of study was to assess the need for total thyroidectomy in management of TGCC. Patients were divided into two groups based on the surgical treatment they underwent and the treatment outcomes were compared. The histology was papillary carcinoma in all cases of TGCC. Overall, 43.3% of TGCCs had a focus of papillary carcinoma in total thyroidectomy specimen. Lymph node metastasis was noted only in 10% of TGCC and not identified in isolated papillary carcinoma confined to thyroglossal cyst. 7-year overall survival (OS) for TGCC was 83.1%. Prognostic factors like extracapsular extension or lymph node metastasis did not affect OS. Addition of total thyroidectomy and neck dissection to Sistrunk procedure did not offer any survival advantage. In a case of TGCC, FNAC should be done from any clinically suspicious thyroid nodules or lymph nodes. TGCC has a good prognosis following treatment and none of the cases in our series has disease recurrence during follow-up. Sistrunk procedure was an adequate procedure for treatment of TGCC with clinically and radiologically normal thyroid gland.

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.

Hyperparameter Tuning of Artificial Neural Networks for Well Production Estimation Considering the Uncertainty in Initialized Parameters.

A well production rate is an essential parameter in oil and gas field development. Traditional models have limitations for the well production rate estimation, e.g., numerical simulations are computation-expensive, and empirical models are based on oversimplified assumptions. An artificial neural network (ANN) is an artificial intelligence method commonly used in regression problems. This work aims to apply an ANN model to estimate the oil production rate (OPR), water oil ratio (WOR), and gas oil ratio (GOR). Specifically, data analysis was first performed to select the appropriate well operation parameters for OPR, WOR, and GOR. Different ANN hyperparameters (network, training function, and transfer function) were then evaluated to determine the optimal ANN setting. Transfer function groups were further analyzed to determine the best combination of transfer functions in the hidden layers. In addition, this study adopted the relative root mean square error with the statistical parameters from a stochastic point of view to select the optimal transfer functions. The optimal ANN model's average relative root mean square error reached 6.8% for OPR, 18.0% for WOR, and 1.98% for GOR, which indicated the effectiveness of the optimized ANN model for well production estimation. Furthermore, comparison with the empirical model and the inputs effect through a Monte Carlo simulation illustrated the strength and limitation of the ANN model.

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.

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.

Mucosal Melanomas of the Oral Cavity: A Tertiary Care Centre Experience of Surgically Treated Cases.

Mucosal melanoma of oral cavity (MMO) is a relatively rare tumour comprising of 40% of all head and neck mucosal melanomas. This study assessed the treatment outcomes and factors affecting prognosis in oral cavity mucosal melanomas. The clinical case records of 25 cases of oral cavity mucosal melanomas treated in our institution during 2003-2013 were retrospectively reviewed. Various clinicopathological parameters were taken into consideration and statistical analysis done by Kaplan-Meier method and Cox's proportional hazards model. The most common sites of MMO were upper alveolus and hard palate (64%) followed by lower alveolus (28%). 57.1% mucosal melanomas of hard palate and upper alveolus had associated metastatic lymph nodes whereas all cases of MMO of lower alveolus had lymph node metastasis. Disease failure at distant sites was higher than that at primary site or lymph nodes. The most common site of distant metastases was brain. The 5-year OS for treated cases was 23.8% and among subsites, MMO of hard palate and upper alveolus had the highest survival. Metastasis to lymph nodes and bone infiltration by tumour significantly decreased the survival. Recurrence at primary site had the worst prognosis. MMO with lymph nodal involvement and bone erosion had poor prognosis. Due to high chances of lymph node metastases and disease recurrence in lymph nodes following treatment, it is essential to do an elective neck dissection for all cases of MMO. Disease failure at primary site was an independent predictor of outcome in MMO.