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.

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.

Enhancing the Oil Recovery from Naturally Fractured Reservoirs Using Viscoelastic Surfactant (VES) Flooding: A Field-Scale Simulation.

A viscoelastic surfactant (VES) has the combined properties of a surfactant and a polymer. Injection of VES fluids into naturally fractured reservoirs (NFRs) can control the mobility of the injected fluid and enhance the total oil recovery. This paper presents a field-scale simulation to evaluate the performance of a noble VES fluid in enhancing the oil recovery from a naturally fractured reservoir. In this work, the results of coreflooding, computerized tomography (CT)-scan, rheology, interfacial tension (IFT), and adsorption measurements were used to build and calibrate a lab-scale model. Thereafter, a chemical enhanced oil recovery (EOR) modeling simulator developed by a computer modeling group (CMG-STARS) was used to build a field-scale simulation. Real seismic data, permeability and porosity distributions, and operating conditions were utilized to develop and evaluate the simulation model. The results show that VES can outperform the surfactant-polymer (SP) flooding and waterflooding in NFRs; VES improved the oil recovery by 10% and reduced the water cut by 47%, at the same conditions. VES reduced the IFT by two orders of magnitude (100 times) compared to waterflooding. Also, VES altered the rock wettability to a more water-wet status, leading to reduce the relative permeability to water (K rw) by a factor of 10, on average. Finally, the simulation study indicated that applying waterflooding after VES flooding leads to a minor increase in the oil recovery. Overall, this study provides a detailed comparison between VES flooding, SP flooding, and conventional waterflooding in NFRs. Sensitivity analysis was performed to study the impact of treatment parameters on the oil recovery from naturally fractured reservoirs. Using actual NFR data, the optimum VES flooding was determined, which will help in conducting VES flooding for real EOR operations.

Application of a Pickering Emulsified Polymeric Gel System as a Water Blocking Agent.

The conventional methods for controlling excess water production in oil/gas wells can be classified on the basis of the mechanism (pore-blocking mechanism and relative permeability modification) used. Gel systems developed on the basis of a pore-blocking mechanism completely block the pores and stop the flow of both oil and water, whereas a relative permeability modifier (RPM) only restricts the flow of a single phase of the fluid. The gel working on the basis of the pore-blocking mechanism is known as a total blocking gel. An invert emulsified (PAM-PEI) polymer gel is a relative permeability modifier system. The same invert emulsion system is tested as a total blocking gel system in this research work. The dual-injection technique (1st injection and 2nd injection) was used for this purpose. In this research work, the emulsion system was tested at a temperature of 105 °C. The core sections with drilled holes and fractures were used for the core flooding experiments, representing a highly fractured reservoir. The developed emulsified gel system was characterized using a dilution test, an inverted bottle test, microscopic images, and FTIR images. The emulsified polymer gel was tested using a core flooding experiment. After the 2nd injection, the postflood medical CT and micro-CT images of the core sections clearly showed the presence of two different phases in the core section, i.e., the oil phase and the gel phase. The core flooding experiment result indicates that the gel formed after the 2nd injection of the emulsion system can withstand a very high differential pressure, i.e., above 2000 psi. The gel did not allow any oil or water to be produced. Hence, the developed emulsified polymer gel system with the help of a dual-injection technique can be efficiently used as a total blocking gel for high-temperature reservoirs.

Deducing the Relation between Viscosity and Oil-Induced Structural Changes of Viscoelastic Surfactants Using a Kinetic Approach.

The present study relates viscosity reduction with time of a wormlike micellar solution to the micellar transitions that occur with time in the presence of three n-alkanes, namely, n-decane, n-dodecane, and n-hexadecane. Steady-shear rheology and small-angle X-ray scattering were used to deduce the relationship. The effect of n-alkane concentration was tested only with n-decane. There were at most three stages of viscosity reduction, which appeared in the following order: (i) the rising viscosity stage, (ii) the fast viscosity reduction stage, and (iii) the low-viscosity stage. The stages and rates of viscosity transition depended on the type of micelles present and the degree of micelle entanglement. Moreover, the rate of transition increased when the n-alkane concentration was increased and when the n-alkane molecular mass was reduced. n-Hexadecane induced only the first two stages of transition at a slower rate compared to the other oils.

Rapid Determination of Emulsion Stability Using Turbidity Measurement Incorporating Artificial Neural Network (ANN): Experimental Validation Using Video/Optical Microscopy and Kinetic Modeling.

Determination of emulsion stability has important applications in crude oil production, separation, and transportation. The turbidimetry method offers advantage of rapid determination of stability at a relatively low cost with good accuracy. In this study, the stability of an oil-in-water (O/W) emulsion prepared by dispersing heavy oil particles in the aqueous solution containing poly(vinyl alcohol) (PVA) has been determined using turbidity measurements. The turbidimetry theory of emulsion stability has been validated using experimental data of turbidity at different wavelengths (350-800 nm) and storage times (0-300 min). The artificial neural network (ANN) has been found to give good predictive performance of the turbidity data. The characteristic change in turbidity has been supported using particle size and distribution analyses performed using optical/video microscopy. The results obtained from the turbidimetry correlation show that the emulsion destabilization rate constant (κ', min-1) is in the range of 0.01-0.04 min-1 (at wavelengths between 350 and 800 nm, respectively). The rate constant remains unchanged (κ' = 0.02 min-1) between the wavelength of 375 and 650 nm. In addition, the demulsification rate constant (κ' = 0.015 min-1) obtained from kinetic modeling using the bottle test is in close agreement with this value. The overall findings ultimately revealed that the turbidimetry method could be used to determine stability of typical O/W emulsions with an acceptable level of accuracy.

Molecular Fractionation in the Organic Materials of Source Rocks.

Hydrocarbons that are transported in a hierarchal path from the nanoporous constituents of a shale matrix to natural and then hydraulic fractures are subject to continuous fractionation during the journey. The organic nanopores of a source rock matrix known as kerogen have pore sizes on the angstrom scale. At that degree of confinement, pores can act as a selective membrane, preferentially maintaining some components over the others in a continuous fractionation phenomenon that alters the adsorption/desorption isotherm. Several studies have considered the adsorption/desorption behavior of kerogen on the basis of a single component. In reality, methane is associated with other hydrocarbons, making that assumption questionable. The present work investigates the multicomponent gas sorption of kerogen structures via a molecular computational approach. The continuous fractionation results in the accumulation of heavier components. The compositional changes alter the phase behavior, enlarging the anticipated two-phase regime. Additionally, the ability of molecules to diffuse from kerogen was also found to be affected by the fractionation effect. These microscale effects provide some insights into the potential factors that influence the productivity at the reservoir scale.