Jitendra Sangwai

Matured reservoirs are being targeted for enhanced oil recovery (EOR) operations in the hope to recover the residual oil that remains trapped within the porous media. Chemical enhanced oil recovery is one of the successful oil recovery methods which is being employed for the recovery of the residual oil. Many of the conventional chemicals fail to perform under high temperature and high saline reservoir conditions. These situations lead to the search for alternate flooding techniques which could efficiently produce the crude oil to the surface. The present work investigates a possible solution for the recovery of trapped crude oil using lactam and imidazolium based ionic liquids (ILs) specifically targeted towards recovery in high saline environment. Initially, the interfacial tension of the crude oil-water system has been investigated using various chemical agents, such as sodium dodecyl sulfate (SDS), and six different ILs at varying high saline concentrations as a function of temperature (283.15–353.15 K). Subsequently, flooding experiments with only polymer, only SDS, only IL, SDS + polymer and IL + polymer at zero and high saline conditions were performed. It was observed that the IL + polymer flood performed very well in both zero and high salinity conditions as compared to all other flooding systems. The present investigation also portrays an intuition on the evaluation of ILs based on their alkyl chain length.

The total recovery of crude oil can be significantly improved by injecting fluids during the secondary and tertiary stages of production. The process leading to improved vertical and areal sweep efficiency is highly influenced by viscous and capillary forces. Along with reservoir rock properties, the reservoir fluid and displacing fluid properties play a critical role during enhanced oil recovery processes. In this study, a two-dimensional differential two-lobe pore throat structure was modelled to investigate the phenomena of water and polymer flooding. Computational fluid dynamics (CFD) with transient analysis was incorporated to study the oil recovery efficiency with changing effect of wettability conditions, and oil and injecting fluid properties. The fractional flow of water at the outlet, breakthrough time, and residual oil saturation were considered as the evaluation factor for numerical experiments. Navier–Stokes equation coupled with the volume of fluid (VoF) model is used to describe the flooding process and for interface tracking. Inconsistent water cut at the outlet was observed in cases with high viscosity contrast. A significant difference in residual oil saturation (10–25%) was observed between water-wet and oil-wet conditions. Polymer flooding improved the total recovery by 7–22% as compared to simple water flooding.

Supercritical fluids find use in various areas in oil and gas production operations due to their unique properties. Supercritical CO2 (sc-CO2) with its reduced viscosity, increased diffusivity, and liquid like density, is attractive for enhanced hydrocarbon recovery, shale gas fracturing and drilling (especially in underbalanced condition). Apart from enhanced hydrocarbon recovery CO2 injection is also desirable due to associated CO2 storage through various trapping mechanisms. CO2-EOR/EGR and storage processes are affected by coupled geochemical, petrophysical and geomechanical alterations due interaction of sc-CO2 with reservoir rock/fluids Along with diffusion/dispersion of sc-CO2 in the fluid filled pore spaces. CO2-monitoring combined with lifecycle analysis can help to ensure safety and optimize the CO2-EOR/storage project, considering the environment. However, many technical, financial and policy challenges need to be overcome to realize the success of the CO2-EOR/storage project and achieve carbon neutrality. This review paper discusses such challenges, the current mitigation practice, gaps and future direction of research. This holistic review would help gain insights into the sc-CO2-EOR/storage mechanisms, selection criteria, various limitations, mitigation and optimizations while applying the method for unconventional reservoirs with heterogeneity and varying fluid properties.

Most of the crude oil reservoirs in the world are getting matured leading to the increased production and deposition of long chain paraffins (wax) at subsurface and surface facilities creating a challenge for flow assurance and safer operation. Deposition of wax on the inner walls of the pipelines tends to decrease the flow of crude oil thereby causing billions of dollars of loss. This article reviews in detail about the various aspects of the microbial degradation of waxy crude oil, along with different mechanisms involved in the hydrocarbon degradation. In addition, the article acts as a guide to screen the microorganism suitable for different environmental conditions for their applications in pipelines, oil spill remediation and microbial-based enhanced oil recovery technique to waxy and heavy oil reservoirs for environmentally safe operation.

The purpose of the present work is to evaluate applicability of ionanofluids for enhanced oil recovery (EOR) applications. Two different ionanofluids have been prepared for this study by adding silica nanoparticles into two different ionic liquids (tripropyl ammonium sulphate and triethyl ammonium sulphate) solutions. The effects of nanoparticle and ionic liquid on the interfacial tension of crude oil-nanofluid and their enhanced oil recovery performances have been evaluated. Ionanofluids are found to have the ability to reduce the interfacial tension to a significantly low value. The results of this study also indicate that ionanofluids has much higher enhanced oil recovery efficiencies in comparison to nanofluid and ionic liquid alone. Therefore, ionanofluids have the potential to be used as an excellent future EOR agent.

Hypothesis: Low salinity surfactant nanofluids have recently shown promising characteristics in wettability alteration of the silicate-based rock representative substrate and interfacial tension reduction of oil/aqueous phase interface. Pore level understanding of the physical processes entailed in this new class of low salinity injection fluids in oil-phase saturated real rock porous media is required, which has not been conceived yet. Experiments: Thus, we investigate the oil recovery performance and possible mechanisms of oil recovery by the injection of low salinity surfactant (SDBS, 1.435 mM) aqueous solutions (with 0%, 0.01% and 0.1% (by weight) ZrO2 nanoparticles) into the oil phase saturated Doddington sandstone miniature core plugs. The designed experiment involves core flooding with X-ray transparent core-holder developed in-house and analysis/processing of the acquired image data. Findings: The injection of low salinity surfactant nanofluids with 0.01% ZrO2 nanoparticles leads to maximum oil phase recovery. The results suggest that the dominating mechanisms for oil recovery are wettability alteration, inherent interfacial tension reduction, and the effect of significant amount of microemulsions formation is rather trivial. Low salinity effect, even in combination with surfactant, caused fines migrations (not reported earlier), is found to be significantly mitigated using nanoparticles. This new class of fluids may significantly enhance oil recovery.

Production performance of a water alternate gas injection (WAG) method has been reported for the effect of several operating parameters, such as, WAG injection cycles, viz., single cycle WAG and five-cycle WAG and the tapered WAG at the reservoir conditions of 120°C and 230 kg/cm2 for hydrocarbon gas and CO2 gas. It is observed that the number of cycles in the WAG injection process affects the recovery of oil from the core sample. It is of oil initially in place. The observations on the effect of gases revealed that the CO2 gas with five-cycle WAG process gives higher incremental recovery than the five cycle WAG process using hydrocarbon gas. It is observed that the saturation profile of CO2 WAG injection shows the better gas saturation in the core as against the hydrocarbon gas in the WAG process. Copyright © 2014 Inderscience Enterprises Ltd.

Nanotechnology offers potential benefits for improving the next-generation enhanced oil recovery (EOR) process from Brownfield reservoirs. In our recent study (Sharma et al., 2014a), we formulated novel Pickering emulsion stabilized using conventional oilfield polymer polyacrylamide (PAM) and nanoparticles (SiO2 and clay) in the presence of surfactant, which is thermally stable at elevated temperature and suitable for EOR application. In this study, the use of these Pickering emulsion is investigated for enhanced oil recovery. Two types of flood systems, viz., surfactant-polymer (SP) and o/w Pickering emulsion flood, are prepared and used for 12 core flooding experiments to study the additional oil recovery at reservoir pressure of 13.6MPa and temperature ranges from 313 to 363K. These reservoir conditions of pressure and temperature are representative to one of the mature reservoirs in India. The incorporation of nanoparticle was observed to provide relatively lower and stable interfacial tension (IFT) for the Pickering emulsion. The viscosity of SP system was observed to decrease with temperature (313-363K), while that of Pickering emulsion was observed to remain stable and thereby indicating a possible stable mobility ratio downhole during EOR. Nanoparticle stabilized Pickering emulsion observed to give enhanced oil recovery by about 80% more at elevated temperatures as compared to conventional SP flood, showing promising advantages of employment of nanoparticles in oilfield industry. The investigation on the permeability reduction indicated a relatively larger retention of SiO2 nanoparticle than its counterpart clay, which is attributed to its larger size in the system.

Efficient flooding agents are required to produce additional oil from mature reservoir. In this work, oil-in-water Pickering emulsion systems stabilized using nanoparticles, surfactant, and polymer have been developed and tested for enhanced oil recovery with and without a conventional polymer flood. Stability of nanoparticles in the dispersion of surfactant-polymer solution was tested using zeta-potential before use. Several flooding experiments have been conducted using Berea core samples at 13.6 MPa and temperatures of 313 and 353 K. It has been observed that a combination of 0.5 PV polymer flood with 0.5 PV Pickering emulsion was efficient and have resulted in 1-6% additional oil recovery as compared to 0.5 PV Pickering emulsion flooding alone. The injection of polymer flood have shown to enhance the pressure drop in the core sample after emulsion flooding and considered as an important factor for an additional recovery of oil. The effect of temperature on the viscosity of flooding agents in relation to pressure drop and oil recovery have also been investigated. Viscosity and pressure drop of emulsion flood systems have shown to marginally decrease with increase in temperature. Studies on nanoparticle retention using SEM have shown that nanoparticles were retained in the core sample during emulsion flooding which may be detrimental for permeability of core sample. It is observed that Pickering emulsion flood with polymer flood would be effective for the enhanced oil recovery suitable for matured reservoirs.