Effective Enhanced Oil Recovery Research Articles

Impact of a novel biosynthesized nanocomposite (SiO2@Montmorilant@Xanthan) on wettability shift and interfacial tension: Applications for enhanced oil recovery

Nanoparticles are used in various nano-energy applications such as wettability shift of hydrophobic surfaces to hydrophilic surfaces in oil-brine-mineral systems and interfacial tension (IFT) reduction for enhanced oil recovery. This is possible due to their small size (1–100 nm) and chemical and physical properties. Mechanistically, they can interact with a fluid in the pore space and provide favourable conditions for wettability shift, IFT and oil viscosity reduction, and thus improve oil recovery. However, literature is scarce in terms of providing comprehensive information about the behaviour of nanocomposites (NCs) and associated formulations.In this paper, we present biosynthesis, characterization, and application of a novel nanocomposite (SiO2@Montmorilant@Xanthan) which is used with various concentrations (100, 250, 500, 1000, 1500, and 2000 ppm) as dispersing agents in porous media. The NC was characterized using X-Ray Diffraction (XRD), Scanning Electron Microscopy (SEM), Thermogravimetric Analysis (TGA), Fourier Transform Infrared Spectroscopy (FTIR), and Energy Dispersive Spectroscopy (EDS). The effects of different concentrations of the nano-suspensions on zeta potential, pH, conductivity, IFT, and wettability are investigated. Core flooding tests were done on sandstone and carbonate reservoir rocks to measure the secondary and tertiary recovery potential by injecting seawater and optimum NC concentrations, respectively.Zeta potential and conductivity experiments demonstrated that 250 ppm NCs can optimally reduce the IFT from 36 mN/m to 15.42 mN/m (56% reduction). The similar optimum concentration has shifted the wettability of examined carbonate rocks from 150° to 33° leading to an 11.72% increase in tertiary oil recovery. Whereas, the optimum concentration of NCs for sandstone rocks was 1000 ppm; which, has optimally altered the wettability from 140° to 34°, and has increased the tertiary oil recovery by 15.79%. This reduction in IFT, the reversal of wettability, and an increase in tertiary oil recovery can improve significantly the design of effective enhanced oil recovery schemes for petroleum reservoirs.

Research progress of viscoelastic surfactants for enhanced oil recovery

Although new energy has been widely used in our lives, oil is still one of the main energy sources in the world. After the application of traditional oil recovery methods, there are still a large number of oil layers that have not been exploited, and there is still a need to further increase oil recovery to meet the urgent need for oil in the world economic development. Chemically enhanced oil recovery (CEOR) is considered to be a kind of effective enhanced oil recovery technology, which has achieved good results in the field, but these technologies cannot simultaneously effectively improve oil sweep efficiency, oil washing efficiency, good injectability, and reservoir environment adaptability. Viscoelastic surfactants (VES) have unique micelle structure and aggregation behavior, high efficiency in reducing the interfacial tension of oil and water, and the most important and unique viscoelasticity, etc., which has attracted the attention of academics and field experts and introduced into the technical research of enhanced oil recovery. In this paper, the mechanism and research status of viscoelastic surfactant flooding are discussed in detail and focused, and the results of viscoelastic surfactant flooding experiments under different conditions are summarized. Finally, the problems to be solved by viscoelastic surfactant flooding are introduced, and the countermeasures to solve the problems are put forward. This overview presents extensive information about viscoelastic surfactant flooding used for EOR, and is intended to help researchers and professionals in this field understand the current situation.

Conformance control study of preformed particle gels (PPGs) in mature waterflooded reservoirs: numerical and experimental investigations

Improving conformance control in reservoirs with a heterogeneous permeability distribution is the objective of many enhanced oil recovery (EOR) methods. In recent years, the injection of preformed Particle Gels (PPGs) is suggested as an effective EOR method to control the in-depth conformance of waterfronts. In this study, a new mathematical transport model of PPG injection in mature waterflooded reservoirs is developed. The model is based on the experimental results of PPG swelling ratio and entrapment analyses in a carbonate rock sample. The entrapment is considered as a function of the PPG-to-pore size ratio, fluid velocity, temperature, salinity, PPG concentration, and swelling ratio. The formulations of the resistance factor (RF) and residual resistance factor (RRF) are obtained from the injection experiment results at various fluid velocity and PPG concentrations. The entrapment model is coupled with the transport equations of the MATLAB Reservoir Simulation Toolbox (MRST). The model is validated by predicting the pressure drop changes during the 1D PPG injection experiments at three different flow rates. The validated model is then used to predict PPG transport behavior in several 3D field-scale scenarios. The sensitivity analysis results show that a higher recovery increment can be achieved when the reservoir permeability contrast is increased. There is an appropriate PPG-to-pore size ratio (i.e., DPT of 1.75) that can guarantee deep conformance control and avoid PPG washing out during post-waterflooding. Furthermore, the PPG concentration of 1750 ppm resulted in a significant entrapment in the porous medium.

Evaluation of the Effectiveness of Continuous Gas Displacement for EOR in Hydraulically Fractured Shale Reservoirs

SummaryThe main objective of this study is to analyze and describe quantitatively the effectiveness of continuous gas displacement as an enhanced oil recovery (EOR) process to increase production from multifractured shale oil reservoirs. The study uses CH4 continuously injected through horizontal wells parallel to the production wells as the displacement agent and investigates the effects of various attributes of the matrix and of the induced and natural fracture systems.This numerical simulation study focuses on the analysis of the 3D minimum repeatable element (stencil/domain) that can describe a hydraulically fractured shale reservoir under production. The stencil is discretized using a very fine (millimeter-scale) grid. We compare the solutions to a reference case that involves simple depressurization-induced production (i.e., without a gas drive). We monitor continuously (a) the rate and composition of the production stream and (b) the spatial distributions of pressure, temperature, phase saturations, and relative permeabilities.The results of the study indicate that a continuous CH4-based displacement that begins at the onset of production does not appear to be an effective EOR method for hydraulically fractured shale oil reservoirs over a 5-year period in reservoirs in which natural or induced fractures in the undisturbed reservoir and/or in the stimulated reservoir volume (SRV) can be adequately described by a single-medium porosity and permeability. Under these conditions in a system with typical Bakken or Eagle Ford matrix and fracture attributes, continuous CH4 injection by means of a horizontal well parallel to the production well causes a reduction in water production and an (expected) increase in gas production but does not lead to any significant increase in oil production. This is attributed to (a) the limited penetration of the injected gas into the ultralow-k formation, (b) the dissolution of the injected gas into the oil, and (c) its early arrival at the hydraulic fracture (HF; thus, short circuiting the EOR process by bypassing the bulk of the matrix), in addition to (d) the increase in the pressure of the HF and the consequent reduction in the driving force of production and the resulting flow. Under the conditions of this study, these observations hold true for domains with and without an SRV over a wide range of matrix permeabilities and for different lengths and positions (relative to the HF) of the gas injection wells.

Evaluation of the economic efficiency of the WAG process based on experimental data for one of the domestic oil fields

The challenge related to the need for an increase of the recovery factor concerns numerous mature, also domestic oilfields, including the most important ones – located in Main Dolomite formation. Satisfactory recovery factor can be ensured only through applying an effective enhanced oil recovery method (EOR). Water Alternating Gas (WAG), as one of the most effective EOR methods, has been tested in conditions characteristic for domestic deposits in carbonate formations. The results of experimental and simulation works carried out at the Oil and Gas Institute (INiG – PIB) indicate significant potential for the application of the WAG method in domestic conditions. An unquestionable advantage of the WAG method is the opportunity to utilize various types of gases, including flue/waste gas or low-energy natural gas. This issue deserves special attention because, as we know, the reduction in the emissions of gases involved in global warming is critical for the future of our planet. Their utilization in EOR methods, coupled with their safe storage in geological structures, constitute measures that reduce the environmental footprint of produced oil. In the article, based on the of experimental results, a simplified economic analysis of the utilization of four gas types in the form of acidic gases (carbon dioxide and its mixture with hydrogen sulfide) and natural gases (high and very high nitrogen content) in the WAG method was carried out. That allowed to identify the most economically optimal variants of the WAG method. The results showed that despite significantly lower effectiveness of nitrogen-rich natural gases in enhancing oil recovery (in the context of recovery factor), their application might be justified in economic terms. The selection of the optimal variant for enhancing recovery is strongly influenced by the assumed (current) cost of acquiring the injected media, and of course by the current (and forecasted) crude oil price.

Mixed CO2/N2 Foam for EOR as a Novel Solution for Supercritical CO2 Foam Challenges in Sandstone Reservoirs.

Among the various enhanced oil recovery (EOR) processes, CO2 injection has been widely utilized for oil displacement in EOR. Unfortunately, gas injection suffers from gravity override and high mobility, which reduces the sweep efficiency and oil recovery. Foams can counter these problems by reducing gas mobility, which significantly increases the macroscopic sweep efficiency and results in higher recovery. Nevertheless, CO2 is unable to generate foam or strong foam above its supercritical conditions (for CO2, 1100 psi at 31.1 °C), and most of the reservoirs exist at higher temperatures and pressure than CO2 supercritical conditions. The formation of strong CO2 foam becomes more difficult with an increase in pressure and temperature above its supercritical conditions and exacerbated CO2-foam properties. These difficulties can be overcome by replacing a portion of CO2 with N2 because a mixture of N2 and CO2 gases can generate foam or strong foam above CO2 supercritical conditions. Although many researchers have investigated EOR by using CO2 or N2 foam separately, the performance of mixed CO2/N2 foam on EOR has not been investigated. This study provides a solution to generate CO2 foam above its supercritical conditions by replacing part of CO2 with N2 (mixed CO2/N2 foam). The mixed foam not only generates strong foam above CO2 supercritical conditions but also remarkably increases the oil recovery. This solution overcomes the difficulties associated with the formation of CO2 foam at HPHT conditions enabling the use of the CO2-foam system for effective EOR and other applications of CO2 foam such as conformance control.

Dynamic Contact Angle Reformulates Pore-Scale Fluid-Fluid Displacement at Ultralow Interfacial Tension

Summary Surfactant flooding is an effective enhanced oil recovery method in which the oil/water interfacial tension (IFT) is reduced to ultralow values (<0.01 mN/m). The microscopic fluid-fluid displacement has been extensively studied at high IFT (>10 mN/m). However, the microscopic displacement dynamics can be significantly different when the IFT is ultralow because the dynamic contact angle increases with the increase of the capillary number. In this study, surfactant flooding was performed and visualized in micromodels to investigate the dynamics of multiphase displacement at ultralow IFT. Although the micromodels used were strongly water-wet, the displacements of oil by surfactant solutions at ultralow IFT appeared as drainage. Furthermore, a macroscopic oil film was left behind on the surface, which indicates that a contact line instability occurred during displacements. The shape of the oil/water meniscus was determined by the balance between viscous forces and capillary forces. The meniscus can be significantly distorted by viscous forces at ultralow IFT. Therefore, the water-wet micromodel exhibits an oil-wet behavior at ultralow IFT, and the displacements of oil by surfactant solutions at ultralow IFT manifested as drainage rather than imbibition. The flow behavior is further complicated by the spontaneous formation of microemulsion during displacement. The microemulsion is mainly formed from the residual oil. The formation of a microemulsion bank made the surfactant solution discontinuous, with transport in the form of droplets in the microemulsion bank and displacement front. The novelty of this work is to reveal the effects of dynamic contact angle on the ultralow IFT displacement.

Enhanced oil recovery from denatured algal biomass: Synergy between conventional and emergent fuels

This work aims to assess the viability of converting algal biomass into production fluids for use in enhanced oil recovery. This proteinaceous biomass, which is the main waste product of algae-based biofuels and other bioproducts, may be modified and commercialized to produce conventional petroleum fuels, thereby benefiting both industries for the global energy portfolio. Tertiary oil production is generally performed on a thin profit margin to the point that for many wells it is not economically feasible to produce beyond a water flood. However, it is hypothesized here that waste proteins may be a viable option as enhanced oil recovery (EOR) agents, especially if they are available at zero-cost or negative-cost. If this technology is developed by the industry, the injection of proteins into the earth should pose little environmental risk and might offer a “carbon offset” for the produced petroleum. In this study, the EOR effect of algal biomass modified by a variety of denaturants has been tested in sand packs. This study also investigates correlations of this effect with the pH and rheological properties of the EOR agents. Using these novel agents, up to 96% of the original oil in place was recovered, so it can be concluded that they have great potential for application. Correlations between the EOR, the denaturant type and concentration, and the EOR effects are discussed.

Enhancing Oil Recovery with Hydrophilic Polymer-Coated Silica Nanoparticles

Nanoparticles (NPs) have been proposed for enhanced oil recovery (EOR). The research has demonstrated marvelous effort to realize the mechanisms of nanoparticles EOR. Nevertheless, gaps still exist in terms of understanding the nanoparticles-driven interactions occurring at fluids and fluid–rock interfaces. Surface-active polymers or other surface additive materials (e.g., surfactants) have shown to be effective in aiding the dispersion stability of NPs, stabilizing emulsions, and reducing the trapping or retention of NPs in porous media. These pre-requisites, together with the interfacial chemistry between the NPs and the reservoir and its constituents, can result in an improved sweep efficiency. This paper investigates four types of polymer-coated silica NPs for the recovery of oil from water-wet Berea sandstones. A series of flooding experiments was carried out with NPs dispersed at 0.1 wt.% in seawater in secondary and tertiary oil recovery modes at ambient conditions. The dynamic interactions of fluids, fluid–rock, and the transport behavior of injected fluid in the presence of NPs were, respectively, studied by interfacial tension (IFT), spontaneous imbibition tests, and a differential pressure analysis. Core flooding results showed an increase in oil recovery up to 14.8% with secondary nanofluid injection compared to 39.7% of the original oil in place (OOIP) from the conventional waterflood. In tertiary mode, nanofluids increased oil recovery up to 9.2% of the OOIP. It was found that no single mechanism could account for the EOR effect with the application of nanoparticles. Instead, the mobilization of oil seemed to occur through a combination of reduced oil/water IFT, change in the rock surface roughness and wettability, and microscopic flow diversion due to clogging of the pores.

Gas Pressure Cycling (GPC) and Solvent-Assisted Gas Pressure Cycling (SA-GPC) Enhanced Oil Recovery Processes in a Thin Heavy Oil Reservoir

In this paper, gas pressure cycling (GPC) and solvent-assisted gas pressure cycling (SA-GPC) were developed as two new and effective enhanced oil recovery (EOR) processes. Eight coreflood tests were conducted by using a 2-D rectangular sandpacked physical model with a one or two-well configuration. More specifically, two cyclic solvent injection (CSI), three GPC, and three SA-GPC tests were conducted after the primary production, whose pressure was declined in steps from Pi = 3.0 MPa to Pf = 0.2 MPa. It was found that the CSI tests had poor performances because of the known CSI technical shortcomings and an additional technical issue of solvent trapping found in this study. Quick heavy oil viscosity regainment resulted in the solvent-trapping zone. In contrast, C3H8-GPC test at a pressure depletion step size of ∆PEOR = 0.5 MPa and C3H8-SA-CO2-GPC test at ∆PEOR = 1.0 MPa had the highest total heavy oil recovery factors (RFs) of 41.9% and 36.6% of the original oil-in-place (OOIP) among the two respective series of GPC and SA-GPC tests. The better performances of these two tests than C3H8- or CO2-CSI test were attributed to the effective displacement of the foamy oil toward the producer in the two-well configuration. Thus the back-and-forth movements of the foamy oil in CSI test in the one-well configuration were eliminated in these GPC and SA-GPC tests. Furthermore, C3H8-GPC test outperformed C3H8-SA-CO2-GPC test in terms of the heavy oil RF and cumulative gas-oil ratio (cGOR) because of the formation of stronger foamy-oil flow and the absence of CO2, which reduced the solubility of C3H8 in the heavy oil in the latter test. In summary, different solvent-based EOR processes were ranked based on the heavy oil RFs as follows: C3H8-GPC > C3H8-SA-CO2-GPC > CO2-GPC > C3H8-CSI > CO2-CSI.

Enhanced oil recovery by low-salinity water spontaneous imbibition (LSW-SI) in a typical tight sandstone formation of mahu sag from core scale to field scale

Accelerating mass exchange between matrix and fractures is the essence of enhanced oil recovery (EOR) in tight formations after natural depletion. Low salinity water (LSW) injection has been commercially-proven in conventional reservoirs EOR, with scale projects in progress worldwide. There is, however, a lack of understanding of the EOR effect in tight formations. Therefore, in this work, we introduced LSW-EOR to a target tight formation using huff-puff mode. Spontaneous imbibition (SI) tests were firstly performed on homogenous Berea sandstone cores with decreasing salinity brine to observe the production response. The results indicated that the oil recovery of the tight rock was boosted by tuning brine salinity. Of all the used brines with salinity ranging from 0.021% to 2.1% TDS (total dissolved salinity), the 0.21% TDS brine showed a rapid increase in oil production over imbibing time, which finally led to an incremental oil recovery of 4.5% OOIP (original oil in place). Core-scale modeling was conducted by history-matching the oil recovery dynamics of the SI results through modifying capillary pressure and relative permeability. A full-scale reservoir model was constructed using micro-seismic data to model fracture geometry combing fracturing results and scaling parameters obtained from core scale history-matching. It is proven that LSW huff- n -puff stimulated the oil production after natural depletion and improved MEE (mass exchange efficiency) of the target formation, but the EOR benefit was not comparable to CO 2 and surfactant-assisted water huff-puff methods.

Hybrid Engineered Water–Polymer Flooding in Carbonates: A Review of Mechanisms and Case Studies

The fast depletion of oil reserves has steered the petroleum industry towards developing novel and cost-effective enhanced oil recovery (EOR) techniques in order to get the most out of reservoirs. Engineered water–polymer flooding (EWPF) is an emerging hybrid EOR technology that uses the synergetic effects of engineered water (EW) and polymers to enhance both the microscopic and macroscopic sweep efficiencies, which mainly results from: (1) the low-salinity effect and the presence of active ions in EW, which help in detachment of carboxylic oil material from the rock surface, wettability alteration, and reduction in the residual oil saturation; (2) the favorable mobility ratio resulting from the use of a polymer; and (3) the improved thermal and salinity resistance of polymers in EW. Various underlying mechanisms have been proposed in the literature for EW EOR effects in carbonates, but the main driving factors still need to be understood properly. Both polymer flooding (PF) and EW have associated merits and demerits. However, the demerits of each can be overcome by combining the two methods, known as hybrid EWPF. This hybrid technique has been experimentally investigated for both sandstone and carbonate reservoirs by various researchers. Most of the studies have shown the synergistic benefits of the hybrid method in terms of two- to four-fold decreases in the polymer adsorption, leading to 30–50% reductions in polymer consumption, making the project economically viable for carbonates. EWPF has resulted in 20–30% extra oil recovery in various carbonate coreflood experiments compared to high-salinity water flooding. This review presents insights into the use of hybrid EWPF for carbonates, the main recovery driving factors in the hybrid process, the advantages and limitations of this method, and some areas requiring further work.

Experimental Investigation of Stability of Silica Nanoparticles at Reservoir Conditions for Enhanced Oil-Recovery Applications.

To be effective enhanced oil-recovery (EOR) agents, nanoparticles must be stable and be transported through a reservoir. However, the stability of a nanoparticle suspension at reservoir salinity and temperature is still a challenge and how it is affected by reservoir rocks and crude oils is not well understood. In this work, for the first time, the effect of several nanoparticle treatment approaches on the stability of silica nanoparticles at reservoir conditions (in the presence of reservoir rock and crude oil) was investigated for EOR applications. The stability of nanoparticle suspensions was screened in test tubes at 70 °C and 3.8 wt. % NaCl in the presence of reservoir rock and crude oil. Fumed silica nanoparticles in suspension with hydrochloric acid (HCl), polymer-modified fumed nanoparticles and amide-functionalized silica colloidal nanoparticles were studied. The size and pH of nanoparticle suspension in contact with rock samples were measured to determine the mechanism for stabilization or destabilization of nanoparticles. A turbidity scanner was used to quantify the stability of the nanoparticle suspension. Results showed that both HCl and polymer surface modification can improve nanoparticle stability under synthetic seawater salinity and 70 °C. Suspensions of polymer-modified nanoparticles were stable for months. It was found that pH is a key parameter influencing nanoparticle stability. Rock samples containing carbonate minerals destabilized unmodified nanoparticles. Crude oil had limited effect on nanoparticle stability. Some components of crude oil migrated into the aqueous phase consisting of amide-functionalized silica colloidal nanoparticles suspension. Nanoparticles modification or/and stabilizer are necessary for nanoparticle EOR application.

Oil Reservoir on a Chip: Pore-Scale Study of Multiphase Flow During Near-Miscible CO2 EOR and Storage

CO2 injection into oil reservoirs is widely accepted as an effective enhanced oil recovery and CO2 storage technique. While oil recovery and CO2 storage potential of this technique have been studied extensively at the core-scale, complex multiphase flow and fluid–fluid interactions at the pore scale during near-miscible CO2 injection have not, and this area needs more study. To address this, a unique high-pressure microfluidic system was implemented which allows for the optical visualisation of the flow using optical microscopy. The results show that during tertiary near-miscible CO2 injection, when CO2 phase contacts the oil, the oil spreads as a layer between the CO2 phase and water preventing CO2 phase from contacting the water phase. This is attributed to the positive value of the spreading coefficient. Furthermore, due to the presence of pore-scale heterogeneity in the chip, an early breakthrough of CO2 was observed causing a large amount of oil to be bypassed. However, after CO2 breakthrough, CO2 gradually started to diffuse and flow inside the bypassed oil zones in the transverse directions which is a characteristic of capillary crossflow. The driving force for this capillary crossflow was the interfacial tension gradient formed by the diffusion of CO2 into the oil phase and the extraction of light to medium hydrocarbon components from the oil into the CO2 phase. The same mechanism led to the recovery of the bypassed oil trapped in dead-end pores. This unique mechanism produced the majority of the bypassed oil after CO2 breakthrough and significantly increased the oil recovery. In our three-phase flow water-wet system, CO2 flow displaced the water through a multiple displacement mechanism which is unique to three-phase flow. CO2 displaced the oil in oil-filled pores thorough bulk flow, and the spreading oil layers were gradually produced by layer flow.

Rheological behavior of a wormlike micelle and an amphiphilic polymer combination for enhanced oil recovery

Amphiphilic polymers have been widely studied and applied in oil fields as effective enhanced oil recovery (EOR) agents. However, the viscosity of their aqueous solution is low at low concentration. In order to improve their poor viscosity-thickening ability at low concentrations, a combined system was used by mixing a zwitterionic surfactant (erucyl dimethyl amidopropyl betaine, EDAB) and an amphiphilic polymer (APC16) at the mass ratio of 2:1. The rheological properties and aggregate microstructure of the EDAB–APC16 combination system were investigated by rheometry, scanning electron microscopy, transmission electron microscopy, and fluorescence spectroscopy, and the EOR efficiency was measured using core flood tests. The results showed that EDAB can significantly increase the viscosity of the APC16 solution, even though the polymer concentration is lower than its critical aggregation concentration. In the EDAB–APC16 combination system, the wormlike micelles of EDAB can synergistically interact with APC16 through hydrophobic association and electrostatic attraction to achieve a thickening effect. Furthermore, the effects of temperature, pH, and the inorganic salts on the viscoelasticity of the EDAB–APC16 system were investigated. An optimized EDAB–APC16 system at 1500 mg/l [pH = 7.5 and c (NaCl) = 5000 mg/l] was selected to be the oil displacing agent, which achieved an EOR of 18.4% after the initial water flood. The polymer–surfactant composite system under development exhibited great potential as an effective chemical EOR agent.

Experiment investigation of microemulsion enhanced oil recovery in low permeability reservoir

Microemulsion flooding is a effective enhanced oil recovery for low permeability. In this paper, combined the advantage of sulphobetaine surfactant and gemini surfactant, a kind of gemini sulphobetaine surfactant (DPSB) was used to prepared microemulsion. The oil–water interfacial tension and adsorption for different concentration surfactant was measured to evaluate the DPSB property. The stability of microemulsion, the microemulsion volume percentage, solubilisation parameter and relative phase volume, microemulsion viscosity was also measured. The performance of this surfactant was further optimized by adding the additives. The relative permeability was determined to analyze the fluid flow characteristics, and the recovery efficiency was studied through natural core and visual core displacement experiment. The results show that the oil–water interfacial tension is 9.1 × 10−4 mN/m when DPSB concentration is 0.5%, and it can still maintain low interfacial tension after adsorption. The interfacial tension can be further decreased by adding n-butyl alcoholy. When the DPSB concentration is 1.5% and n-butyl alcohol concentration is 1.5%, the microemulsion volume percentage is 31%, and the viscosity is 4.37 mPa∙s. It can reduce the flow velocity of displacing fluid, and expand sweep volume. Compared with water flooding, the residual oil saturation reduces by about 30% in microemulsion flooding. The recovery efficiency is increased by about 4% compared with the low concentration of surfactant flooding.

Interfacial interactions between Bakken crude oil and injected gases at reservoir temperature: A molecular dynamics simulation study

Due to large amounts of oil remain in the Bakken Formation, an effective enhanced oil recovery (EOR) method is crucially important. Cyclic gas injection, like CO2, methane, and ethane, can mobilize the residual oil and enhance oil recovery. In this study, the gas solubility, volume swelling factor, oil diffusion coefficient, and minimum miscibility pressure (MMP) were studied to compare the efficiency of different gases in the EOR process. Based on the Bakken oil components, a molecular model of the crude oil containing different types of alkanes was built. A series of molecular dynamics (MD) simulations were carried out to study the interfacial interactions between Bakken crude oil and the injected gases. At various pressures and reservoir temperature, density profiles were plotted to show the distribution of different components, and the solubility of gases in crude oil was calculated. The swelling factor was obtained by comparing the density of gas-saturated crude oil and that of the pure crude oil. The vanishing interfacial tension (VIT) method was used to determine the MMPs. The simulation results show that all three gases hold great potential in further improving oil recovery. As the pressure increases, the gas solubility increases, and the interfacial width becomes wider. At constant temperature and pressure, ethane holds the highest solubility in crude oil and can induce the most pronounced oil swelling. Meanwhile, ethane can achieve the lowest MMP and the most significant oil diffusion coefficient, which means ethane is most effective in mobilizing and producing crude oil from the reservoir.

3D Physical Simulation Experiment of Edge Water Reservoir by Polymer/Surfactant Binary Flooding

To investigate the enhanced oil recovery (EOR) technology by chemical flooding in an edge water reservoir, a 3D physical simulation experimental device for the edge water reservoir was developed, and polymer/surfactant binary flooding experiments were carried out under different edge water energies. In addition, the effect and mechanism of binary flooding on EOR under different edge water energies were comprehensively analyzed. Experimental results show that edge water intrusion considerably affects EOR by binary flooding. The stronger the edge water energy, the worse the effect of EOR by binary flooding. Edge water possibly diluted the concentration of the chemical agent medium that is injected into the reservoir, and the degree of dilution varied in different regions. The dilution region was mainly distributed between the injection wells and edge water. The stronger the edge water energy, the higher the dilution multiple of chemical agent and the greater the recovery loss rate by binary flooding.

Experimental Investigation of Molecular Deposition Filming Flooding in a Low-Permeability Oil Reservoir

Molecular deposition (MD) filming flooding has proved to be an effective enhanced oil recovery (EOR) method in reservoirs where recovery was relatively difficult. The B425 block with a low permeabi...

Low-Salinity Water, CO2, Alkaline, and Surfactant EOR Methods Applied to Heavy Oil in Sandstone Cores

Summary Generally, injecting carbon dioxide (CO2) into oil reservoirs is an effective enhanced oil recovery (EOR) technique that improves oil recovery, but injecting CO2 alone can be compromised by problems, such as early breakthrough, viscous fingering, and gravity override. The base CO2 injection method was improved by water-alternating-gas (WAG) injection with formation water (FW) and with low-salinity (LS) water (LSW), with LSW WAG achieving greater recovery than WAG with FW. This study investigates various combinations of standard waterflooding (with FW); flooding with nonmiscible gaseous CO2; WAG with CO2 and FW and/or LSW; foam flooding by adding a surfactant with CO2; adding an alkaline treatment step; and finally adding an LSW spacer between the alkaline step and the foam. These various EOR combinations were tested on Bartlesville sandstone cores (ϕ of approximately12%, K of approximately 20 md) saturated with a heavy oil diluted slightly with 10% heptane for workability. The ultimate outcome from this work is a “recipe” of EOR methods in combination that uses alkaline, LSW, surfactant, and CO2 steps to achieve recovery of more than 63% of the oil originally in place (OOIP) in coreflooding tests. Combining CO2 injection with surfactant [sodium dodecyl sulfonate (SDS)] to produce a foam resulted in better recovery than the WAG methods. Adding alkaline as a leading step appeared to precipitate the surfactant and lower recovery somewhat. Adding an LSW spacer between the alkaline treatment and the foam resulted in a dramatic increase in recovery. The various cases of alkaline + LSW spacer + surfactant + CO2 (each with various concentrations of alkaline and surfactant) achieved an average improvement of 7.71% of OOIP over the identical case(s) without the LSW spacer. The synergistic effect of the LSW spacer was remarkable. ERRATUM NOTICE:An erratum has been added to this paper detailing addition of an omitted reference.