Enhance Sweep Efficiency Research Articles

Experimental and theoretical investigation of cationic-based fluorescent-tagged polyacrylate copolymers for improving oil recovery.

The growing need for energy and the depletion of oil wells necessitate advanced Enhanced Oil Recovery (EOR) techniques, particularly water and polymer flooding, which play a crucial role in augmenting hydrocarbon recovery rates. However, water flooding in high-permeability layers often leads to water breakthroughs, reduced sweep efficiency, and the formation of preferential channels, posing significant challenges to oil recovery and reservoir management. Conformance control treatments, including the use of polymer microspheres, offer a promising solution by sealing high-permeability zones and enhancing sweep efficiency. This study focuses on the application of fluorescent polymer microspheres based on polyacrylamide, which is extensively employed in the oil sector as an oil displacement agent. Fluorescent polymers called Poly 400, Poly 200, and Poly 600, incorporating cationic methacrylamide monomers, were synthesized through copolymerization to create amphiphilic polymers with enhanced stability and functionality. These fluorescent polymers were evaluated through flooding tests using a quarter-five-spot model of transparent quartz glass under UV light, allowing for instantaneous measurement and observation of fluorescence intensity. At reservoir conditions, the oil displacement experiments confirm that the incremental oil after water flooding by Poly 400, Poly 200, and Poly 600, is 13.1%, 9.1%, and 6.1% of OOIP respectively. The findings showed that fluorescent polymer microspheres could efficiently target high-permeability layers, adapt to varying pore throat sizes, and improve the plugging rate of high-permeability channels, thereby optimizing oil recovery. A subsequent simulation study using the CMG simulator provided further insights into the efficacy of these fluorescent polymers as EOR agents, revealing their potential to enhance sweep efficiency and enhance oil recovery. Simulation results showed that oil saturation decreased from 68% (initial) to 13.5%, 16.1%, and 18.3% after Poly 400, Poly 200, and Poly 600 flooding respectively. This work highlights the potential of fluorescent polymer microspheres as a valuable tool for EOR applications, offering significant advancements in reservoir management and oil recovery optimization.

Data-Analytics-Driven Sectorization Review Enables Efficient Reservoir Management

_ This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 216359, “Data-Analytics-Driven Subsurface Reservoir Sectorization Review of a Giant Abu Dhabi Onshore Field Carbonate Reservoir for Efficient Reservoir Management,” by Khalid Javid, Sara Alshkeili, and Fatema Al-Hammadi, ADNOC, et al. The paper has not been peer reviewed. _ The complete paper discusses an approach used to sectorize a mature onshore Abu Dhabi giant carbonate reservoir for the purposes of reservoir management, offtake, and injection balancing. The reservoir is developed under a line-drive water-alternating-gas (WAG) scheme in combination with peripheral water injection. The development plan for the reservoir includes massive deployment of maximum reservoir contact (MRC) horizontal wells and a gas-based enhanced oil recovery scheme. A practical data-driven approach, based on one of the operator’s integrated reservoir management (IRM) workflows, was selected for the purpose of sectorization. Field Development Background Reservoir A is part of a giant oil field considered low permeability. Its porosity ranges between 13 and 26%, while permeability increases from 1 md on the flanks to 50 md in the crest of the structure. Production began 30 years ago, and the development scheme has undergone several transformations since. Currently, it is being developed under mid-flank line-drive waterflooding combined with crestal WAG and peripheral water injection. The current recovery factor of Reservoir A is approximately 10%. Two field-trial pilots were implemented (gas-injection and water-injection pilots) and then were converted to WAG injection between 2007 and 2013. These locations show high gas/oil ratio (GOR) and high water cut (WC). The development scheme includes downspacing of the existing line-drive to approximately 300 m intended to enhance sweep efficiency and increase recovery factor. The number of wells is expected to increase substantially. To optimize well placement and reduce development capital expenditure and subsurface congestion with other development targets in the field, development will capitalize on long horizontal MRC wells. Reservoir Sectorization Objectives. The sectorization exercise undertaken for Reservoir A aimed to achieve the following: - Establish a manageable number of sectors and allow creation of relevant, meaningful reservoir management key performance indicators and more-efficient surveillance programs - Honor main geological features -Reflect reservoir pressure distribution and communication between different areas of the reservoir - Reflect fluid-front movement - Reflect well-performance trends - Honor future development plans (including MRC wells) Proposed Sectorization Options. Reservoir A originally was divided into 13 regions for reservoir management, surveillance, and reservoir monitoring planning purposes, including production and injection balancing, voidage replacement ratio (VRR), pressure performance, and diagnostic plots. At the start of the study, eight sectorization scenarios were proposed. These scenarios were evaluated following a methodology described in the complete paper, aiming to combine the initial 13 regions into a smaller number of sectors where possible. Each scenario was evaluated against criteria including data analytics; the scheme honoring most of the criteria with an optimal number of sectors would be selected.

Chemical-Assisted CO2 Water-Alternating-Gas Injection for Enhanced Sweep Efficiency in CO2-EOR.

CO2-enhanced oil recovery (CO2-EOR) is a crucial method for CO2 utilization and sequestration, representing an important zero-carbon or even negative-carbon emission reduction technology. However, the low viscosity of CO2 and reservoir heterogeneity often result in early gas breakthrough, significantly reducing CO2 utilization and sequestration efficiency. A water-alternating-gas (WAG) injection is a technique for mitigating gas breakthrough and viscous fingering in CO2-EOR. However, it encounters challenges related to insufficient mobility control in highly heterogeneous and fractured reservoirs, resulting in gas channeling and low sweep efficiency. Despite the extensive application and research of a WAG injection in oil and gas reservoirs, the most recent comprehensive review dates back to 2018, which focuses on the mechanisms of EOR using conventional WAG. Herein, we give an updated and comprehensive review to incorporate the latest advancements in CO2-WAG flooding techniques for enhanced sweep efficiency, which includes the theory, applications, fluid displacement mechanisms, and control strategies of a CO2-WAG injection. It addresses common challenges, operational issues, and remedial measures in WAG projects by covering studies from experiments, simulations, and pore-scale modeling. This review aims to provide guidance and serve as a reference for the application and research advancement of CO2-EOR techniques in heterogeneous and fractured reservoirs.

Insight into evolution of invasive patterns on fingering phenomenon during immiscible two-phase flow through pore structure

Understanding fingering, as a challenge to stable displacement during the immiscible flow, has become a crucial phenomenon for geological carbon sequestration, enhanced oil recovery, and groundwater protection. Typically governed by gravity, viscous and capillary forces, these factors lead invasive fluids to occupy pore space irregularly and incompletely. Previous studies have demonstrated capillary numbers, describing the viscous and capillary forces, to quantificationally induce evolution of invasion patterns. While the evolution mechanisms of invasive patterns have not been deeply elucidated under the constant capillary number and three variable parameters including velocity, viscosity, and interfacial tension. Our research employs two horizontal visualization systems and a two-phase laminar flow simulation to investigate the tendency of invasive pattern transition by various parameters at the pore scale. We showed that increasing invasive viscosity or reducing interfacial tension in a homogeneous pore space significantly enhanced sweep efficiency, under constant capillary number. Additionally, in the fingering crossover pattern, the region near the inlet was prone to capillary fingering with multi-directional invasion, while the viscous fingering with unidirectional invasion was more susceptible occurred in the region near the outlet. Furthermore, increasing invasive viscosity or decreasing invasive velocity and interfacial tension promoted the extension of viscous fingering from the outlet to the inlet, presenting that the subsequent invasive fluid flows toward the outlet. In the case of invasive trunk along a unidirectional path, the invasive flow increased exponentially closer to the outlet, resulting in a significant decrease in the width of the invasive interface. Our work holds promising applications for optimizing invasive patterns in heterogeneous porous media.

Radiation-Induced Polymerization of Thermo-Responsive Polymers for Enhanced Sweep Efficiency in Heterogeneous Oil Reservoirs

Radiation-Induced Polymerization of Thermo-Responsive Polymers for Enhanced Sweep Efficiency in Heterogeneous Oil Reservoirs

Comparative Assessment of Conventionally and Locally Sourced Surfactants for Enhancing Steam Flooding Techniques for Heavy Oil Recovery in Niger Delta

The recovery of heavy oil reserves presents a significant challenge in the petroleum industry due to its high viscosity and poor mobility characteristics. Steam flooding, as a thermal Enhanced Oil Recovery (EOR) technique, has shown promise in mobilizing heavy oil deposits. However, the limited success of conventional steam flooding in heavy oil reservoirs necessitates innovative approaches. This study explores the utilization of conventional and locally sourced surfactants in surfactant-enhanced steam flooding (SESF) for heavy oil recovery in the Niger Delta region. The study examines the selection, formulation, and injection of surfactants specifically tailored for heavy oil reservoir conditions. Laboratory experiments, core flooding tests, and numerical simulations are conducted to evaluate the impact of surfactants on interfacial tension reduction, wettability alteration, and improved oil mobility in heavy oil reservoirs subjected to steam flooding. The project’s findings demonstrate the significant potential of (SESF) for heavy oil recovery. The synergistic effects of surfactants and steam, including the reduction of oil-water interfacial tension, lead to increased oil production rates, reduced steam consumption, and enhanced sweep efficiency. Furthermore, economic assessments are conducted to evaluate the feasibility of implementing this approach on a field scale, considering both technical and economic aspects. This study not only contributes valuable insights to the field of heavy oil recovery but also underscores the practicality of surfactant-enhanced steam flooding as an environmentally responsible solution for unlocking the vast heavy oil reserves worldwide. The research bridges the gap between laboratory findings and real-world applications, offering a promising path forward for the sustainable development of heavy oil resources.

Development of Novel Delayed Swelling Polymer Gel Particles with Salt Resistance for Enhanced In-Depth Permeability Control

Summary Prolonged waterflooding or polymer flooding in oil fields often exacerbates reservoir heterogeneity, leading to premature water breakthrough and high water cut, which significantly hinders efficient oilfield development. To address this issue, polymer gel particles have been prescribed to enhance sweep efficiency and augment waterflooding recovery by plugging preferential pathways within the reservoir. However, inherent weaknesses of polymer gel particles, such as fast water absorption and expansion rates in the initial stage and low post-expansion rates, make it difficult to balance in-depth transportation and plugging performance. Additionally, these gel particles are sensitive to ions in the formation water, resulting in reduced expansion rates under high-salinity conditions. Therefore, there are still challenges in the application of polymer gel particles for in-depth permeability control. In this study, a new type of delayed swelling and salt-resistant polymer gel particle was synthesized through inverse emulsion copolymerization. To achieve delayed swelling, we use a degradable crosslinker and hydrophobic monomer to enhance the crosslinked network density and hydrophobicity of gel particles. Our double crosslinked gel particles keep their original size until Day 2, then gradually swell up to 20 days in NaCl solution with a concentration of 15×104 mg·L−1 at 90°C. In comparison, the traditional single crosslinked gel particles show significant disparities in swelling behaviors and quickly swell when just dispersed in a 15×104 mg·L−1 NaCl solution at 90°C, maintaining roughly the same size over the testing period. Coreflooding experiments demonstrate that the residual resistance before and after aging increases from 2.37 to 6.82. The newly synthesized delayed swelling and salt-resistant polymer gel particles exhibit promising potential for overcoming the challenges associated with reservoir heterogeneity and high salinity.

Silica aerogel nanoparticle-stabilized flue gas foams for simultaneous CO2 sequestration and enhanced heavy oil recovery

With declining conventional reserves, tapping heavy oils generates substantial emissions yet is essential to meet energy demands. This study pioneers an integrated approach using silica aerogels to develop thermally stable flue gas foams for enhanced CO2 sequestration and heavy oil recovery. Microfluidic experiments and molecular dynamics simulations revealed a 5-fold decrease in gas diffusion rates for aerogel-stabilized versus pure surfactant foams at 95 °C due to the ultralow thermal conductivity of the nanoparticle coating layer. The thermally stable nanoengineered foams demonstrated a remarkable 81.23% CO2 trapping efficiency in heterogeneous cores, surpassing conventional flue gas foam. Additionally, three-dimensional simulations in an oil reservoir model showed improved vertical conformance and oil recovery with aerogel-stabilized foam. The exceptional insulating properties redirected heat downward to enhance sweep efficiency. This novel concept transforms flue gas emissions into value-added foams for concurrent environmental and productivity benefits during heavy oil development.

Mitigation of Gravity Segregation by Foam to Enhance Sweep Efficiency

Foam-assisted gas injection exhibits promising potential for enhancing sweep efficiency through the amelioration of gravity segregation, particularly within reservoirs characterized by heterogeneity. In this work, the implicit-texture (IT) model featuring two flow regimes is employed to examine the impact of heterogeneity on gravity segregation. The validation of the numerical results for water–gas coinjection and pre-generated foam injection is accomplished through a comparative analysis with analytical solutions. A hypothetical two-layer model with varying permeabilities and thickness ratios is used to examine the impact of foam on gravity segregation. The numerical findings demonstrate satisfactory conformity with analytical solutions in homogeneous reservoirs. A high-permeability top layer in a layered model with a fixed injection rate results in sweep efficiency similar to that of a homogeneous reservoir with each individual permeability. A low-permeability top layer could increase the sweep efficiency, but with severe permeability contrast, the bottom high-permeability layer could impact the displacement process, even with a thin thickness. The sweep efficiency increases with the thickness of the high-permeability top layer and decreases with a thicker low-permeability top layer under fixed injection pressure. The predicted segregation length through a single-layer approximation cannot match the results of the layered models where the permeability contrast is too great or the thickness of two layers is comparable.

Effect of modified montmorillonite particles on generation of in-situ W/O emulsion and oil displacement mechanism in enhanced heavy oil recovery

Water-in-oil (W/O) emulsions can enhance the sweep efficiency and control the mobility ratio of oil and water simultaneously in heavy oil development. However, the W/O emulsions formed by heavy oils and injected fluids are prone to be with low phase inversion point and low maximum internal phase volume, which leads to serious tonguing and fingering especially in heterogeneous reservoirs. The authors thus proposed a new method of stabilizing W/O emulsions with modified montmorillonite particles (MMPs) to increase the phase inversion point as well as the internal phase volume to enable economically viable recovery of heavy oils. This paper evaluated the emulsions injected with different types of MMPs in terms of stability, maximum internal phase volume, and rheology. The optimal contact angle and particle concentration for modification were 105° and 3000 ppm, and under such conditions, the maximum internal phase volume fraction of the emulsions was increased to 85% and the viscosity by 40 times. In addition, the selected MMPs were then injected into multiple homogeneous cores of different permeabilities to verify the injectability and the viability to form W/O emulsions via pressure curves and NMR two-dimensional spectrum. The results showed that the modified particles can be injected into cores with permeability above 200 mD, but only in cores with permeability above 500 mD can a significant W/O emulsion be observed. Finally, three sets of heterogeneous core flooding tests were conducted in an online NMR system to determine the reasonable timing for injection of the MMPs and to verify its ability to enhance sweep efficiency by monitoring variations in NMR imaging, oil recovery, water cut, and pressure. Our work provides useful insights into the enhancement of sweep efficiency in heterogeneous heavy oil reservoirs by particle-stabilized W/O emulsions.

Experimental Investigation on the Pore-Scale Mechanism of Improved Sweep Efficiency by Low-Salinity Water Flooding Using a Reservoir-on-a-Chip.

Low-salinity water flooding, known as an environmentally friendly and efficient oil recovery technology, has attracted the attention of several researchers all over the world. However, its field application is suffering restrictions because of the ambiguous mechanisms of the oil recovery by controlling the salinity. In this study, a water flooding microfluidic experiment was conducted to investigate the pore-scale mechanism of enhanced sweep efficiency by low-salinity water flooding. This experiment used a reservoir-on-a-chip that preserved the real rock properties and morphological features. Crude oil–water–rock contact angle experiments by altering water salinity were conducted to investigate the mechanism of the improvement of sweep efficiency by low-salinity water flooding. The experiment results show that unlike high-salinity water flooding, low-salinity water flooding improves its sweep efficiency from wettability alteration. Specifically, in the microfluidic model, it clearly shows that the pore-scale sweep efficiency is improved by reducing the salinity of injected water. Low-salinity water can invade the pores that cannot be reached by high-salinity water and displace the remaining oil after high-salinity water flooding. In the altering water salinity contact angle experiments, the contact angles decrease from 91.05° (neutral-wet) to 64.41° (water-wet) as the water salinity decreases from 46.58 to 2.31 g/L. The wettability of the rock surface changes from oil or neutral-wet to water-wet and induces the imbibition process, during which the hydrophilic pores absorb the low-salinity water into the smaller pores where the high-salinity water cannot invade. This investigation provides a further in situ and pore-scale evidence of improved sweep efficiency and wettability alteration by low-salinity water flooding and a possible reference to solve the difficulty in upscaling fluid flow behavior from microfluidics to reservoir rocks.

Profile Control Using Fly Ash Three-Phase Foam Assisted by Microspheres with an Adhesive Coating

Foam-assisted steam flooding is a promising technique to alleviate gas channeling and enhance sweep efficiency in heterogeneous heavy-oil reservoirs. However, long-term foam stabilization remains problematic at high temperatures. Three-phase foam (TPF), containing dispersed solid particles, has been proposed to improve foam stability under harsh reservoir conditions. We fabricated a novel TPF system by adding ultrafine fly ash particles, as well as high-temperature resistant microspheres with an adhesive coating layer. This work aims at assessing the ability of the generated TPF in controlling steam channeling and enhancing oil recovery. Static and core flood tests were performed to evaluate foam strength and stability. Our results suggested a stronger foamability at a lower consolidation agent concentration, while a longer half-life period of foam and settling time of solid particles at a larger consolidation agent concentration were observed. Bubbles suspended independently in the liquid phase, with sizes varying from 10 to 100 μm, smaller than that of the conventional foam, suggesting a significant enhancement of foam dispersity and stability. The plugging rate was close to 90% when the temperature was as high as 300 °C, demonstrating a well-accepted plugging effect under high temperatures. A larger pore volume injection of TPF yielded a higher EOR in parallel cores, which substantiated the effectiveness of the three-phase foam system in sealing high-permeability channels.

Semi-Analytical Solution of Chemical Flooding in Heterogeneous Non-Communicating Layers with a Focus on Low Salinity Water Flooding

Chemical flooding has been implemented intensively for some years to enhance sweep efficiency in porous media. Low salinity water flooding (LSWF) is one such method that has become increasingly attractive. Historically, analytical solutions were developed for the flow equations for water flooding conditions, particularly for non-communicating strata. We extend these to chemical flooding, more generally, and in particular for LSWF where salinity is modeled as an active tracer and changes relative permeability. Dispersion affects the solutions, and we include this also. Using fractional flow theory, we derive a mathematical solution to the flow equations for a set of layers to predict fluid flow and solute transport. Analytical solutions tell us the location of the lead (formation) waterfront in each layer. We extend a correlation that we previously developed to predict the effects of numerical and physical dispersion. We used this correction to predict the location of the second waterfront in each layer which is induced by the chemical’s effect on mobility. We show that in multiple non-communicating layers, mass conservation can be used to deduce the interlayer relationships of the various fronts that form. This is based on similar analysis developed for water flooding although the calculations are more complex because of the development of multiple fronts. The result is a predictive tool that we compare to numerical simulations and the precision is very good. Layers with contrasting petrophysical properties and wettability are considered. We also investigate the relationship between the fractional flow, effective salinity range, salinity dispersion and salinity retardation. The recovery factor and vertical sweep efficiency are also very predictable. The work can also be applicable to other chemical EOR processes if they alter the fluid mobility. This includes polymer and surfactant flooding.

Microbially Induced Calcium Carbonate Plugging for Enhanced Oil Recovery

Plugging high-permeability zones within oil reservoirs is a straightforward approach to enhance oil recovery by diverting waterflooding fluids through the lower-permeability oil-saturated zones and thereby increase hydrocarbon displacement by improvements in sweep efficiency. Sporosarcina pasteurii (ATCC 11859) is a nitrogen-circulating bacterium capable of precipitating calcium carbonate given a calcium ion source and urea. This microbially induced carbonate precipitation (MICP) is able to infill the pore spaces of the porous medium and thus can act as a potential microbial plugging agent for enhancing sweep efficiency. The following explores the microscopic characteristics of MICP-plugging and its effectiveness in permeability reduction. We fabricate artificial rock cores composed of Ottawa sand with three separate grain-size fractions which represent large (40/60 mesh sand), intermediate (60/80 mesh sand), and small (80/120 mesh sand) pore sizes. The results indicate a significant reduction in permeability after only short periods of MICP treatment. Specifically, after eight cycles of microbial treatment (about four days), the permeability for the artificial cores representing large, intermediate, and small pore size maximally drop to 47%, 32%, and 16% of individual initial permeabilities. X-ray diffraction (XRD) indicates that most of the generated calcium carbonate crystals occur as vaterite with only a small amount of calcite. Imaging by SEM indicates that the pore wall is coated by a calcium carbonate film with crystals of vaterite and calcite scattered on the pore wall and acting to effectively plug the pore space. The distribution pattern and morphology of microbially mediated CaCO3 indicate that MICP has a higher efficiency in plugging pores compared with extracellular polymeric substances (EPSs) which are currently the primary microbial plugging agent used to enhance sweep efficiency.

Plugging High-Permeability Zones of Oil Reservoirs by Microbially Mediated Calcium Carbonate Precipitation.

Simple plugging of the high-permeability “thief zones” of oil reservoirs is the most plausible and also the most straightforwardly achievable approach to enhance sweep efficiency and oil recovery. Sporosarcina pasteurii is a representative microorganism with the ability to precipitate calcium carbonate (CaCO3) via enzymatic hydrolysis of urea in the presence of calcium ions. Microbially induced calcium carbonate precipitation (MICP) can cement and seal the granular and fractured media and thus can be used as a potential microbial plugging agent for the high-permeability zones of oil reservoirs. The following investigated the microscopic characteristics of MICP plugging and its efficacy in permeability reduction. The columns of near-spherical silica sand and angular silica sand with three separate granularities (40/60, 60/80, and 80/120 mesh) were used as artificial rock cores representing distinct pore sizes and pore characteristics to investigate the efficacy and microprocess of MICP plugging with different biotreatment periods. The results indicated that permeability is reduced significantly after only short periods of biotreatment. After eight cycles of MICP treatments, the permeability for each type of cores dropped by 54–90% of individual initial permeabilities. The measured CaCO3 content indicated that the decreasing rate in permeability with the increasing CaCO3 content experiences three contrasting stages, namely, slow decline, speedy decline, and plateauing. X-ray diffraction indicated that most of the generated CaCO3 crystals occur as vaterite with only a small amount of calcite. Imaging by scanning electron microscopy further revealed the microprocess of MICP plugging. Microorganisms first concentrate on the pore wall to secrete CaCO3, forming a thin and large uniform layer of CaCO3. Then, some nucleation sites of CaCO3 crystals will experience further preferential growth, resulting in large, dominant crystals that act as a plugging agent within the pore space. Compared to extracellular polymeric substances, which are currently the primary microbial plugging agent used to enhance sweep efficiency of oil reservoirs, bio-CaCO3 appears more effective in plugging in terms of its morphology, size, and growth characteristics.

Does Polymer's Viscoelasticity Influence Heavy-Oil Sweep Efficiency and Injectivity at 1 ft/D?

Summary For heavy-oil-recovery applications, mobility control is more important than interfacial-tension reduction, and therefore importance should be given to the recovery of remaining mobile oil by enhanced sweep efficiency. Although the relative roles of polymer viscosity and elasticity in capillary-trapped residual light-oil recovery have been studied extensively, their roles in sweeping mobile viscous oil have not been explored. Injectivity is vital for heavy-oil-recovery applications, and polymer selection is performed solely using criteria that is based on shear rheology. In this paper, the influence of viscous (shear) resistance and elastic (extensional) resistance of viscoelastic polymer on mobile-heavy-oil recovery and injectivity is investigated through the combination of bulk shear/extensional rheology and single-phase and multiphase coreflood experiments at a typical reservoir-flooding rate of 1 ft/D. Two polymer solutions with different concentrations and salinities are selected such that a polymer with low molecular weight (MW) [hydrolyzed polyacrylamide (HPAM) 3130] provides higher shear resistance than a high-MW polymer (HPAM 3630). Extensional characterization of these two polymer solutions performed using a capillary breakup extensional rheometer revealed that HPAM 3630 provided higher extensional viscosity than HPAM 3130. The results show that the behaviors of polymers in extension and shear are completely different. Two multiphase and two single-phase experiments are conducted at low flux rate to investigate the roles of extensional viscosity on mobile-heavy-oil recovery and high flux rates on injectivity. After 1 pore volume (PV) of polymer injections, higher-concentration and lower-MW HPAM 3130 contributes to approximately 17% higher incremental recovery factor vs. lower-concentration and higher-MW HPAM 3630. The core-scale pressure drop generated by HPAM 3130 is more than twice the pressure drop generated by HPAM 3630. Under low-flux-rate conditions at the core scale, shear forces dominate, and displacing fluid with higher shear viscosity contributes to better sweep. HPAM 3630 exhibits a shear-thickening phenomenon and possesses the apparent viscosity of approximately 90 cp at the flux rate of approximately 90 ft/D. In contrast, HPAM 3130 continued showing shear thinning and has the apparent viscosity of approximately 70 cp at approximately 90 ft/D. This signifies the role of extension rheology on the injectivity at higher flux rates. Results revealed that while the extensional rheological role toward sweeping the mobile heavy-oil recovery at low flux is lesser compared with the shear role, its negative role on the polymer injectivity is very significant. Polymer-selection criteria for heavy-oil-recovery applications should incorporate extensional rheological parameters.

Migration and plugging mechanisms of self-aggregated microspheres as a novel profile control

The aim of this study was to investigate the migration and blocking mechanism of self-aggregated divinylbenzene-co-acrylamide (DCA) microspheres as a novel profile control. Scanning electron microscopy (SEM) and laser diffracting measurement experiments were conducted to examine the shape and size of the microspheres. The optimal matching factor between microsphere diameter and the pore throat was from 0.15 to 0.19. The migration position of DCA microspheres in porous media was studied via SEM. The images revealed that DCA microspheres can exhibit long-distance migration. Moreover, the effects of different matching factors on oil recovery rate have been investigated by the core displacement experiments. The enhanced oil recovery was the highest when the DCA microspheres with the optimum matching factor was injected. Additionally, the oil saturation distribution demonstrates that DCA microspheres with optimal matching factors can enhance sweep efficiency by plugging high-permeability water channels.

Application and Mechanisms of Self-Generated Heat Foam for Enhanced Oil Recovery

Foams are widely used in the oil and gas industry due to their unique viscous and elastic properties. However, typical foam injection methods into reservoirs require large equipment with high injection pressure, which might not be suitable for development of offshore oilfields, deep wells, or high condensate petroleum reservoirs. Here, for the first time, we report self-generated heat foams (SGHFs) that are systematically generated and studied by combining self-generated nitrogen gas reactants (sodium nitrite and ammonium chloride) and environmentally friendly surfactants. Sandpack oil recovery flooding experiments at 60 °C and 4 MPa along with two-dimensional (2D) visualization micromodel experiments were carried out to analyze the oil displacement mechanisms. Various oil recovery aspects such as heat production, oil viscosity reduction, foam generation, profile control, and heat-foam synergistic effects were investigated. The results showed that SGHFs can increase oil recovery by 33.9% from homogeneous (permeability of ∼2 Darcy) single layer formation and by 20.4% from heterogeneous (permeability ratio >10) multilayer formation. The incremental oil recovery by SGHFs was much higher than that of conventional foam or self-generated heat (SGH) without foam. The heat produced by the SGHF chemical reaction increased the temperature of the crude oil by 13 °C, reduced the crude oil viscosity by 35%, and helped increase oil recovery by reducing the mobility ratio. Moreover, the foams generated by SGHFs had a remarkable effect on the profile (conformance) control in the presence of crude oil. The synergistic effect between the heat and the foam produced by SGHF chemical reaction can be explained by (1) The chemical reaction can produce small and uniform foam, seen by the 2D micromodel, which can block large pores in porous media and enhance sweep efficiency and (2) The uniform sweep efficiency due to the presence of foam can help distribute the heat and make the temperature rise evenly along the sandpack, which was beneficial to reduce the crude oil viscosity throughout the entire porous media and improve oil recovery.

Stabilization mechanism of CO2 foam reinforced by regenerated cellulose

CO2 foam was widely applied to enhance sweep efficiency through controlling gas breakthrough and channeling during the process of CO2 flooding. However, the poor stability of conventional foam system under the harsh reservoir conditions restricted the enhanced oil recovery (EOR) performance of CO2 foam. Therefore, the CO2 foam reinforced by anionic-nonionic surfactant SS163 and the regenerated cellulose (RC) was developed; also its stability was compared with other foams (e.g. stabilized with SiO2, Al2O3, HPAM and stabilizer-free foam). The static and dynamic foam stability were evaluated by the modified Ross-Miles method, Warning Blender method, oscillation-shear-oscillation rheology. Furthermore, the foam aging rules were investigated via the multiple light scattering method and double-layer glass model. Upon that, the stabilization mechanism by RC was proposed and elucidated by the viscosity, storage and loss modulus, morphological inspection, SEM images and their correlation with foam stability. The results demonstrated that 1% SS163 + 1% RC CO2 foam has the highest foam stability and regeneration capacity compared with other foams. The dynamic variations in the film thickness and diameter of the foam characterized four stages of RC reinforced CO2 foam. The prolonged liquid drainage was attributed to the following four RC stabilization mechanisms: increased viscosity, the stabilization mechanism of RC aggregates, the liquid film ‘skeleton’ formed by RC, and the liquid storage effect of RC. In this work, we introduce the regenerated cellulose in the application of EOR and present the unique stabilization mechanism of RC on CO2 foam. The interface stabilizing capacity, viscoelasticity, thickened behavior and sustainability of regenerated cellulose highlights the application potential in EOR.

Characteristics of waterflood at low rate in low permeability sandstones based on the CT scanning

ABSTRACTIt is reported that the flooding rate in low permeability sandstones is low and the oil recovery is hard to increase after water breakthrough. Understanding characteristics of waterflood is hence important for the recovery improvement. In this work, flooding tests on low permeability sandstones were conducted. The corresponding flooding characteristics were investigated by means of CT scanning and Nuclear Magnetic Resonance. Effects of irreducible water and different rates were also discussed in detail. Experimental results reveal a piston-like displacement at a low rate in low permeability samples. The saturation profile is steep and almost vertical to the forward direction. The results at a low rate confirm that once water broke through, increasing the flooding rate or flooding time can hardly reduce the remaining oil inside the sample. It is probably due to the high pore-throat ratio proven by rate-controlled mercury. Results also confirm that the presence of initial water enhanced sweep efficiency substantially. On one hand, because water had previously occupied the small pores, the subsequent oil can only invade relatively large pores and became more movable. On the other hand, stable collars can not form due to the steep front, which may suppress the snap-off.