Search

Despite advances in renewable energy sources, the world's current infrastructure and consumption patterns still heavily depend on crude oil. Enhanced oil recovery (EOR) is a crucial method for significantly increasing the amount of crude oil extracted from mature and declining oil fields. Nanomaterials have shown great potential in improving EOR methods due to their unique properties, such as high surface area, tunable surface chemistry, and the ability to interact at the molecular level with fluids and rock surfaces. This study examines the potential use of incorporating ethoxylated molybdenum disulfide with a unique three-dimensional flower-like morphology for overcoming the challenges associated with oil recovery from reservoirs characterized by complex pore structures and low permeability. The synthesized nanomaterial features a chemical composition that encompasses a polar ethoxy group linking molybdenum disulfide nanosheets and an alkylamine chain. The ethoxy group promotes interactions with water molecules through hydrogen bonding and electrostatic forces, disrupting the cohesive forces among water molecules and reduction surface tension at the oilewater interface. As a result, the nanomaterial achieves an ultra-low interfacial tension of 10-3 mN/m. Core flooding experiments demonstrate a significant oil recovery of approximately 70% at a concentration as low as 50 ppm. This research paves the way for the design and synthesis of advanced extended surfactant-like nanomaterials, offering a promising avenue for enhancing oil recovery efficiency. [ABSTRACT FROM AUTHOR]

This research examines the impact of wettability alteration on the end points of relative permeability, a crucial property of fluids and porous media that influences the displacement processes of immiscible fluids through such media. The estimation of the mobility ratio for oil recovery relies on these end points, which are influenced by connate water saturation and residual oil saturation. To investigate this relationship, carbonate rock is generally subjected to wettability alteration using surfactant agents, and core flooding is employed to determine the relative permeability before and after the alteration. The wettability of the rock is commonly assessed through contact angle measurements. Two surfactants, TritonX-100 (Tx-100) and Cedar, were tested in reducing the wettability of the porous media for oil. The contact angle measurements revealed that Tx-100 was more effective for this purpose than Cedar. Furthermore, the relative permeability tests indicated that both surfactants decreased residual oil saturation, but Tx-100 also improved system pressure. In contrast, Cedar reduced residual oil saturation but increased system pressure, possibly because of its high viscosity. The results also demonstrate that injecting Tx-100 leads to a 14% increase in ultimate oil recovery compared with water injection, while Cedar injection increased the recovery factor by 5%. This difference may be attributed to the incomplete coverage of the pore wall by Cedar or its weaker chemical structure than Tx-100. Notably, in carbonate cores, neither non-ionic surfactant enhanced oil recovery.

Gas injection is a well-known method for enhancing oil recovery (EOR). The utilization of greenhouse gases, such as carbon dioxide (CO2) or flue gas, offers the dual advantage of reducing greenhouse gas emissions while potentially enhancing the sweep efficiency in oil recovery. Nevertheless, one of the notable challenges encountered when using these gases is the precipitation and deposition of asphaltenes, leading to formation damage and a decrease in reservoir permeability, particularly in the case of light oil reservoirs. In this study, CO2 and flue gas were injected into an elongated core sample comprising four individual core plugs under reservoir conditions to displace the light live oil. The recovery factor and asphaltene deposition along the core holder were assessed and compared as two crucial parameters within the gas injection scenario. Our results indicate a significantly higher recovery factor of 86% achieved with CO2 injection compared to 36% with flue gas injection, attributable to differences in their interfacial tension and miscibility. However, the CO2 injection method exhibits more pronounced formation damage. Individual assessment of each core plug reveals that permeability impairment is most acute in the initial two core plugs, situated closer to the injection face of the extended core. These findings enhance our understanding of the mechanisms contributing to permeability impairment resulting from asphaltene deposition during CO2 and flue gas injection for EOR. [ABSTRACT FROM AUTHOR]

High technical and financial risks are involved in exploring and exploiting new fields; hence, greater focus has placed on the development of environmentally friendly, cost-effective, and enhanced oil recovery (EOR) options for existing fields. For reservoirs producing high-density crudes and those with high interfacial tensions, water flooding is usually less effective due to density differences—hence the advent of polymer and surfactant flooding. For cost-effective and eco-friendly EOR solutions, a biopolymer and a surfactant synthesized from Jatropha seeds are used in this study to determine their effectiveness in increasing the oil recovery during core flooding analysis. The experiment involved an initial water flooding that served as the base cases of three weight percentages of polymers and polymeric surfactant solutions. The results for the polymer flooding of 1 wt%, 1.5 wt%, and 2 wt% showed an incremental oil recovery in comparison to water flooding of 16.8%, 17%, and 26%, while the polymeric surfactant mixtures of 5 wt% of surfactant and 1 wt%, 1.5 wt%, and 2 wt% of a polymer recorded 16.5%, 22.3%, and 28.8%, and 10 wt% of surfactant and 1 wt%, 1.5 wt%, and 2 wt% of a polymer recorded incremental oil recoveries of 20%, 32.9%, and 38.8%, respectively. [ABSTRACT FROM AUTHOR]

Abstract Chemical flooding through biopolymers acquires higher attention, especially in acidic reservoirs. This research focuses on the application of biopolymers in chemical flooding for enhanced oil recovery in acidic reservoirs, with a particular emphasis on modified chitosan. The modification process involved combining chitosan with vinyl/silane monomers via emulsion polymerization, followed by an assessment of its rheological behavior under simulated reservoir conditions, including salinity, temperature, pressure, and medium pH. Laboratory-scale flooding experiments were carried out using both the original and modified chitosan at conditions of 2200 psi, 135,000 ppm salinity, and 196° temperature. The study evaluated the impact of pressure on the rheological properties of both chitosan forms, finding that the modified composite was better suited to acidic environments, showing enhanced resistance to pressure effects with a significant increase in viscosity and an 11% improvement in oil recovery over the 5% achieved with the unmodified chitosan. Advanced modeling and simulation techniques, particularly using the tNavigator Simulator on the Bahariya formations in the Western Desert, were employed to further understand the polymer solution dynamics in reservoir contexts and to predict key petroleum engineering metrics. The simulation results underscored the effectiveness of the chitosan composite in increasing oil recovery rates, with the composite outperforming both its native counterpart and traditional water flooding, achieving a recovery factor of 48%, compared to 39% and 37% for native chitosan and water flooding, thereby demonstrating the potential benefits of chitosan composites in enhancing oil recovery operations.

Abstract Biosurfactants, as microbial bioproducts, have significant potential in the field of microbial enhanced oil recovery (MEOR). Biosurfactants are microbial bioproducts with the potential to reduce the interfacial tension (IFT) between crude oil and water, thus enhancing oil recovery. This study aims to investigate the production and characterization of biosurfactants and evaluate their effectiveness in increasing oil recovery. Pseudoxanthomonas taiwanensis was cultured on SMSS medium to produce biosurfactants. Crude oil was found to be the most effective carbon source for biosurfactant production. The biosurfactants exhibited comparable activity to sodium dodecyl sulfate (SDS) at a concentration of 400 ppm in reducing IFT. It was characterized as glycolipids, showing stability in emulsions at high temperatures (up to 120 °C), pH levels ranging from 3 to 9, and NaCl concentrations up to 10% (w/v). Response surface methodology revealed the optimized conditions for the most stable biosurfactants (pH 7, temperature of 40 °C, and salinity of 2%), resulting in an EI24 value of 64.45%. Experimental evaluations included sand pack column and core flooding studies, which demonstrated additional oil recovery of 36.04% and 12.92%, respectively. These results indicate the potential application of P. taiwanensis biosurfactants as sustainable and environmentally friendly approaches to enhance oil recovery in MEOR processes.

Abstract Gas injection is a well-known method for enhancing oil recovery (EOR). The utilization of greenhouse gases, such as carbon dioxide (CO2) or flue gas, offers the dual advantage of reducing greenhouse gas emissions while potentially enhancing the sweep efficiency in oil recovery. Nevertheless, one of the notable challenges encountered when using these gases is the precipitation and deposition of asphaltenes, leading to formation damage and a decrease in reservoir permeability, particularly in the case of light oil reservoirs. In this study, CO2 and flue gas were injected into an elongated core sample comprising four individual core plugs under reservoir conditions to displace the light live oil. The recovery factor and asphaltene deposition along the core holder were assessed and compared as two crucial parameters within the gas injection scenario. Our results indicate a significantly higher recovery factor of 86% achieved with CO2 injection compared to 36% with flue gas injection, attributable to differences in their interfacial tension and miscibility. However, the CO2 injection method exhibits more pronounced formation damage. Individual assessment of each core plug reveals that permeability impairment is most acute in the initial two core plugs, situated closer to the injection face of the extended core. These findings enhance our understanding of the mechanisms contributing to permeability impairment resulting from asphaltene deposition during CO2 and flue gas injection for EOR.

The paper presents the methodology and results of core tests to assess the impact of colloid migration on apparent permeability under cyclic confining pressure. In the work, porous limestone cores were used. The research methodology differs from similar works in that the core was blown with nitrogen at a high pressure gradient between loading and unloading cycles to clean the pores. Blowings cause permeability dynamics that contradict classical theory, according to the results of multi-cycle core tests. Forward and reverse blowings disturb the porous medium's internal equilibrium, resulting in a change in apparent permeability between core test cycles. This phenomenon can only be explained by colloid migration, which provides pore throat blocking and unblocking during nitrogen injection. A visual comparison of micrographs before and after the tests revealed that the surface structure of the pores remained unchanged, but mobile particles ranging in size from several microns to 50 microns were observed in each observed pore. The proposed mechanism for changing apparent permeability during gas injection and cyclic confining pressure correlates well with the results of core tests. [ABSTRACT FROM AUTHOR]

Amphoteric nano‐ and microgels based on acrylamide (AAm), 3‐acrylamidopropyltrimethylammonium chloride (APTAC) and 2‐acrylamido‐2‐propanesulfonate sodium salt (AMPS) were prepared via inverse emulsion polymerization in the presence of crosslinking agent—N,N′‐methylenebisacrylamide (MBAA). Several polyampholyte nano‐ and microgel samples AAm‐APTAC‐AMPS with compositions (70:15:15, 80:10:10, and 90:5:5 mol%) were obtained and they were abbreviated as AAm70‐APTAC15‐AMPS15, AAm80‐APTAC10‐AMPS10 AAm90‐APTAC5‐AMPS5 (where the lower indexes indicate the molar concentration of monomers). The nano‐ and microgels were characterized by Fourier‐transform infrared spectroscopy, dynamic light scattering (DLS), transmission electron microscope (TEM), thermogravimetric analysis and interfacial tension measurements. The most attention was paid to the AAm80‐APTAC10‐AMPS10 microgel because its linear analog showed the best swelling capacity and the viscosifying effect for potential application in oil recovery. The influence of monomer concentration, surfactants, volume ratio of the water/organic phases, and the hydrophilic–lyophilic balance (HLB) on the average hydrodynamic size of the AAm80‐APTAC10‐AMPS10 nano‐ and microgels was studied. The size distribution of nano‐ and microgels derived from DLS data and TEM images was compared as a function of monomer concentration at constant surfactant concentration (6 wt%), HLB = 5.5 and mixture of water:oil = 60:40 vol%. Swelling of microgel particles in saline water due to the antipolyelectrolyte effect was observed. The applicability of amphoteric microgels AAm80‐APTAC10‐AMPS10 for oil recovery was tested on cores simulating the conditions of a model oil reservoir. The obtained results indicated that after the injection of around three pore volumes of the 2500 ppm microgel suspension into the sandstone core the permeability to brine decreased from 1.5 to 0.78 mD. For the first half of core sample the residual resistance factor was higher than the resistance factor, whereas for the second part of core sample these parameters were almost equal. Additional experiments with longer cores are needed to evaluate in‐depth propagation of microgels and permeability reduction in porous media. [ABSTRACT FROM AUTHOR]

Field‐scale observations suggest that rock heterogeneities control subsurface fluid flow, and these must be characterized for accurate predictions of fluid migration, such as during CO2 sequestration. Recent efforts characterizing multiphase flow in heterogeneous rocks have focused on simulation‐based inversion of laboratory observations with X‐ray imaging. However, models produced in this way have been limited in their predictive ability for heterogeneous rocks. We address the main challenges in this approach through an algorithm that combines new developments: a 3‐parameter capillary pressure model, spatial heterogeneity in absolute permeability, improved image processing to capture more experimental data in the calibration, and the constraint of history match iterations based on marginal error improvement. We demonstrate the improvements on two sandstones and three carbonate rocks, with varying heterogeneity, some of which could not be previously modeled. The algorithm results in physically representative models of the rock cores, reducing non‐systematic error to a level comparable to the experimental uncertainty. Plain Language Summary: Porous materials, both natural and man‐made, exhibit spatial heterogeneity ranging from rock pores to the scales of geological units. Accurately characterizing the impact of rock heterogeneity on hydrodynamic properties has been extensively studied but remains an open scientific question, particularly at the core scale of a few decimeters. This study demonstrates a new approach to effectively characterizing the flow properties of highly heterogeneous rocks, including sandstone and carbonate rocks. This approach overcomes major barriers that previously prevented the successful modeling of highly heterogeneous rocks. As a result, it is now possible to characterize multiphase flow property heterogeneity in a wide range of rock types. Key Points: This paper demonstrates a workflow for creating predictive models of heterogeneous sandstone and carbonate rocksMulti parameter fitting of capillary pressure functions and permeability‐capillary pressure correlations are introduced into an iterative modeling approachThe developments lead to major improvements in the history matching and predictive capability of models for three carbonate and two sandstone rock samples with wide‐ranging heterogeneities [ABSTRACT FROM AUTHOR]

High technical and financial risks are involved in exploring and exploiting new fields; hence, greater focus has placed on the development of environmentally friendly, cost-effective, and enhanced oil recovery (EOR) options for existing fields. For reservoirs producing high-density crudes and those with high interfacial tensions, water flooding is usually less effective due to density differences—hence the advent of polymer and surfactant flooding. For cost-effective and eco-friendly EOR solutions, a biopolymer and a surfactant synthesized from Jatropha seeds are used in this study to determine their effectiveness in increasing the oil recovery during core flooding analysis. The experiment involved an initial water flooding that served as the base cases of three weight percentages of polymers and polymeric surfactant solutions. The results for the polymer flooding of 1 wt%, 1.5 wt%, and 2 wt% showed an incremental oil recovery in comparison to water flooding of 16.8%, 17%, and 26%, while the polymeric surfactant mixtures of 5 wt% of surfactant and 1 wt%, 1.5 wt%, and 2 wt% of a polymer recorded 16.5%, 22.3%, and 28.8%, and 10 wt% of surfactant and 1 wt%, 1.5 wt%, and 2 wt% of a polymer recorded incremental oil recoveries of 20%, 32.9%, and 38.8%, respectively.

The in situ saponification of crude oil lowers the interfacial tensions of oil–water systems in chemical-enhanced oil recovery (cEOR). When the interfacial tension is sufficiently low, emulsion phases occur, and the fluid phase distribution in the pore space changes, affecting oil displacement efficiency. This change in capillarity allows the injection water to penetrate different classes of pores, which must be reflected in the distribution of fluids in the pore space. This issue still needs to be adequately researched and is not reflected in the classic analyses of oil cluster size. We have performed μCT-based coreflood experiments to study the displacement efficiency of crude oil by alkaline solutions acting as cEOR agents for in situ saponification. The measured fluid distributions were analyzed using oil-cluster size statistics. In addition, the pore classes from which the oil was preferentially displaced and the degree of displacement as a function of alkali concentration were determined. Despite ultralow interfacial tension and emulsion formation, a clear separation of the oil and aqueous phases was observed over a wide range of alkali concentrations, allowing a two-phase analysis of the microscopic fluid distribution. It was found that (a) a Lorentz analysis of the cluster volume distribution is useful to characterize the cEOR displacement efficiency. It shows the tendency of oil clusters toward a more uniform size distribution toward optimal alkali concentration. (b) the additional oil recovery toward optimal displacement conditions comes from the fraction of smaller pores; at optimal conditions, all pore classes are flooded almost equally and to a high degree, equivalent to miscible displacement, i.e., extremely low interfacial tension. [ABSTRACT FROM AUTHOR]

Matrix acidizing is usually conducted on sandstone reservoirs to increase hydrocarbon production. Mineralogy plays an important role in designing acidizing treatments to enhance the production of oil and gas from sandstone reservoirs. The most common acid in practice to acidize sandstone formation is mud acid after the pre-flush acid stage. The main aim of the pre-flush acid stage is to dissolve positive ions like calcium, potassium, sodium, etc, which can cause precipitation reactions during the mud acid stage. This research is aimed to investigate the reaction mechanism of a new pre-flush acid combination (hydrochloric acid and acetic acid) with sandstone formation. Core flooding experiments were performed to react acid with the core samples (6 in x 1.5 in) under high pressure and temperature (HPHT) conditions (80 °C and 1000 psia). Analytical techniques such as Tescan Integrated Mineral Analysis (TIMA) have been used to illustrate the effect of these acids on sandstone formation. TIMA analysis showed that the new acid combination was effective in dissolving various minerals (ankerite, magnetite) and cations (calcium, magnesium, sodium, and iron). 15% HCl proved to be more effective in the dissolution of different particles from sandstone core samples. It dissolved 32.8% of the initial number of particles present inside the sample while the dissolving power of 5% CH3COOH:10% HCl is 26.7%. Subsequently, the number of pores increased by the application of 15% HCl is 22% while that by 5%CH3COOH:10% HCl is 21.8%. Density analysis showed that both acid combinations removed heavy particles effectively, whereas 5% CH3COOH:10% HCl proved more efficient in dissolving calcium ions which is very important for pre-flush acidizing.

Electrolysis followed by underground hydrogen storage (UHS) in both salt caverns and depleted oil and gas reservoirs is widely considered as a potential option to overcome fluctuations in energy provision from intermittent renewable sources. Particularly in the case of depleted oil and gas reservoirs, a denser layer of cushion gas (N 2 , CH 4 or CO 2) can be accommodated in these storage volumes to allow for sufficient system pressure control as hydrogen is periodically injected and extracted. These gases/fluids are however fully soluble with hydrogen and thus with sufficient mixing can undesirably contaminate the extracted hydrogen product. Fluid mixing in a porous medium is typically characterized by a dispersion coefficient (K L), which is hence a critical input parameter into reservoir simulations of underground hydrogen storage. Such dispersion data is however not readily available in the literature for hydrogen at relevant storage conditions. Here we have developed and demonstrated novel methodology for the measurement of K L between hydrogen and nitrogen in a Berea sandstone at 50 bar as a function of displacement velocity (0.007–0.722 mm/s). This leverages off previous work quantifying K L between carbon dioxide and methane in rock cores relevant to enhanced gas recovery (EGR). This used infrared (IR) spectroscopy to differentiate the two fluids, hydrogen is however IR invisible. Hence the required time-resolved quantification of hydrogen concentration emerging from the rock core is uniquely performed here using bench-top nuclear magnetic resonance (NMR). The resultant hydrogen-nitrogen dispersion data as a function of displacement velocity allows for the determination of dispersivity (α = 0.31 mm). This intrinsic rock property compares favorably with previous CO 2 dispersion measurements on similar sandstones, hence validating our methodology to some extent. In addition, at very low velocities, determination of the rock core tortuosity (τ, another intrinsic rock property) produces a value (τ = 10.9) that is similar to that measurement independently using pulsed field gradient NMR methods (τ = 11.3). • Hydrogen dispersion in rock cores is obtained via a novel core flooding methodology. • Benchtop nuclear magnetic resonance is used to measure hydrogen content of effluent. • Hydrogen dispersion in nitrogen for a sandstone is measured at various velocities. • Dispersion data is validated by extraction of rock core tortuosity and dispersivity. [ABSTRACT FROM AUTHOR]

Polymer flooding is one of the enhanced oil recovery (EOR) methods that increase the macroscopic efficiency of the flooding process and enhanced crude oil recovery. In this study, the effect of silica nanoparticles (NP-SiO2) in xanthan gum (XG) solutions was investigated through the analysis of efficiency in core flooding tests. First, the viscosity profiles of two polymer solutions, XG biopolymer and synthetic hydrolyzed polyacrylamide (HPAM) polymer, were characterized individually through rheological measurements, with and without salt (NaCl). Both polymer solutions were found suitable for oil recovery at limited temperatures and salinities. Then, nanofluids composed of XG and dispersed NP-SiO2 were studied through rheological tests. The addition of nanoparticles was shown to produce a slight effect on the viscosity of the fluids, which was more remarkable over time. Interfacial tension tests were measured in water-mineral oil systems, without finding an effect on the interfacial properties with the addition of polymer or nanoparticles in the aqueous phase. Finally, three core flooding experiments were conducted using sandstone core plugs and mineral oil. The polymers solutions (XG and HPAM) with 3% NaCl recovered 6.6% and 7.5% of the residual oil from the core, respectively. In contrast, the nanofluid formulation recovered about 13% of the residual oil, which was almost double that of the original XG solution. The nanofluid was therefore more effective at boosting oil recovery in the sandstone core. [ABSTRACT FROM AUTHOR]

The use of natural alternatives as oilfield chemicals is gradually gaining attention among researchers due to their eco-friendly nature. The aim of this study was to determine the efficiency of red onion skin extract (ROSE) at recovering residual oil using the mechanism of surfactant flooding in sandstone reservoirs at reservoir conditions and compare its effectiveness in its pristine and modified state. ROSE was obtained by solvent extraction of the waste biomass (red onion skin) using acetone. The extract was chemically modified using glutaraldehyde. Phase behavior analysis in the presence of divalent ions at high temperatures (80 ˚C) and sandstone core flooding were performed to determine the fluid compatibility and displacement efficiency. Results show high compatibility and solubility of pristine (unmodified) and modified ROSE in soft and hard brine. Core flooding analysis showed a higher recovery of 32.1% and 36.5% original oil in place (OOIP) for 0.3 wt.% modified ROSE as compared to a recovery factor of 31.8% and 35.0 % OOIP for 0.5% unmodified ROSE in soft and hard brine respectively. It further reveals an increase in additional recovery at surfactant concentration in hard brine above critical micelle concentration (CMC). Results of statistical significance test showed that modified ROSE exhibited superior performance and a higher recovery relative to unmodified ROSE especially in hard brine. This is a novel work as red onion skin extract was derivatized with glutaraldehyde and successfully recovered additional residual oil under hard brine and reservoir temperature making them potential surface-active agents for chemical enhanced oil recovery.

Despite the implementation of hydraulic fracturing technologies, the oil recovery in tight oil reservoirs is still poor. In this study, cationic, anionic, and nonionic surfactants of various sorts were investigated to improve oil recovery in tight carbonate cores from the Middle Bakken Formation in the Williston Basin. Petrophysical investigations were performed on the samples prior to the imbibition and core-flooding experiments. The composition of the minerals was examined using the XRD technique. To investigate the pore-size distribution and microstructures, nitrogen adsorption and SEM techniques were applied. The next step involved brine and surfactant imbibition for six Bakken cores and two Berea sandstone cores. The core samples were completely saturated with Bakken crude oil prior to the experiments. The core plugs were then submerged into the brine and surfactant solutions. The volume of recovered oil was measured using imbibition cells as part of experiments involving brine and surfactant ingestion into oil-filled cores. According to the findings, oil recovery from brine imbibition ranges from 4.3% to 15%, whereas oil recovery from surfactant imbibition can range from 9% to 28%. According to the findings, core samples with more clay and larger pore diameters produce higher levels of oil recovery. Additionally, two tight Bakken core samples were used in core-flooding tests. Brine and a separate surfactant solution were the injected fluids. The primary oil recovery from brine flooding on core samples is between 23% and 25%, according to the results. The maximum oil recovery by second-stage surfactant flooding is approximately 33% and 35%. The anionic surfactants appear to yield a better oil recovery in tight Bakken rocks, possibly due to their higher carbonate mineral concentrations, especially clays, according to both the core-scale imbibition and flooding experiments. For studied samples with larger pore sizes, the oil recovery is higher. The knowledge of the impacts of mineral composition, pore size, and surfactant types on oil recovery in tight carbonate rocks is improved by this study. [ABSTRACT FROM AUTHOR]

This study aimed to address the challenges and strategies to determine the critical rate of CO2 injection into a carbonate depleted gas field. In this research, the critical rate is the maximum allowable injection rate before formation damage initiation. The cause of formation damage could be due to in-situ mobilization or trapping of migratory fines resulting in plugging the flow path. This study performed a thorough investigation of a different rock-fluid system to evaluate the safe injection limit, as the critical rate is different for each rock-fluid system. The geochemical effect of CO2 injection toward carbonate formation was also investigated in this research. Other than that, the porosity and permeability changes due to CO2-brine-rock multiphase flow characteristics were considered to understand the feasibility of CO2 sequestration into carbonate formation. This research discussed experimental design to mimic the CO2 injection scenario of CO2 into carbonate depleted gas field. Therefore, several core flooding experiments were conducted under reservoir conditions using representative native cores, CO2, and synthetic formation brine. Abrupt changes in differential pressure (ΔP), analysis of effluent collected after CO2 multi-rate flow, and pH reading are the key indicators to consider that the condition has reached a critical rate. The experimental result demonstrated the existence of fines migration, scale formation, and salt precipitation after the core was subjected to supercritical CO2 multi-rate flow. Considering these issues and challenges associated with injectivity, this study recommended a maximum injection rate prior to field scale injection. [ABSTRACT FROM AUTHOR]

Acidizing is one of the most used stimulation techniques in the petroleum industry. Several reports have been issued on the difficulties encountered during the stimulation operation of the Ahdeb oil field, particularly in the development of the Mishrif reservoir, including the following: (1) high injection pressures make it difficult to inject acid into the reservoir formation, and (2) only a few acid jobs have been effective in Ahdeb oil wells, while the bulk of the others has been unsuccessful. The significant failure rate of oil well stimulation in this deposit necessitates more investigations. Thus, we carried out this experimental study to systematically investigate the influence of acid treatment on the geomechanical properties of Mi4 formation of the Mishrif reservoir. The acid core-flood experiments were performed on seven core samples from the oil reservoir in central Iraq. The porosity, permeability, acoustic velocities, rock strength, and dynamic elastic parameters were computed before and after the acidizing treatment. To determine the optimal acid injection rate, different injection flow rates were used in the core-flooding experiments. The propagation of an acid-induced wormhole and its effect on the rock properties were analyzed and compared to that of intact rocks. Computed tomography (CT) scan and a 3D reconstruction technique were also conducted to establish the size and geometry of the generated wormhole. To analyze the influence of mineralogical variation and heterogeneity and confirm the consistency of the outcomes, acidizing experiments on different rock samples were conducted. The results demonstrate that for all the rock samples studied, the mechanical properties exhibit rock weakening post-acid treatment. The Young's modulus reduced by 26% to 37%, while the Poisson's ratio, the coefficient of lateral earth pressure at rest, and the material index increased by 13% to 20%, 23% to 32%, and 28% to 125%, respectively. The CT scan visually confirmed that the acid treatment effectively creates a pathway for fluid flow through the core. [ABSTRACT FROM AUTHOR]

This study aimed to address the challenges and strategies to determine the critical rate of CO2 injection into a carbonate depleted gas field. In this research, the critical rate is the maximum allowable injection rate before formation damage initiation. The cause of formation damage could be due to in-situ mobilization or trapping of migratory fines resulting in plugging the flow path. This study performed a thorough investigation of a different rock-fluid system to evaluate the safe injection limit, as the critical rate is different for each rock-fluid system. The geochemical effect of CO2 injection toward carbonate formation was also investigated in this research. Other than that, the porosity and permeability changes due to CO2-brine-rock multiphase flow characteristics were considered to understand the feasibility of CO2 sequestration into carbonate formation. This research discussed experimental design to mimic the CO2 injection scenario of CO2 into carbonate depleted gas field. Therefore, several core flooding experiments were conducted under reservoir conditions using representative native cores, CO2, and synthetic formation brine. Abrupt changes in differential pressure (ΔP), analysis of effluent collected after CO2 multi-rate flow, and pH reading are the key indicators to consider that the condition has reached a critical rate. The experimental result demonstrated the existence of fines migration, scale formation, and salt precipitation after the core was subjected to supercritical CO2 multi-rate flow. Considering these issues and challenges associated with injectivity, this study recommended a maximum injection rate prior to field scale injection.

Spontaneous imbibition and core flooding investigations were carried out on limestone core plug samples using different low salinity water (LSW) and smart brines at temperatures of 110 and 50℃, respectively. To demonstrate further the potential of low salinity water injection (LSWI) as an agent for enhanced oil recovery (EOR) studies, the interfacial tension (IFT), contact angle (CA), and zeta potential (ZP) were measured. The recovery factor values provided from spontaneous imbibition experiments investigated by formation water (FW), seawater (SW), dilution versions of SW (i.e., 1/2SW, 1/10SW) were 10.07, 15.11, 18.05, and 16.04%, respectively. However, the secondary LSW flooding produced more oil, i.e., a higher recovery factor (37.3, 55, and 61% for FW, SW, and 1/10SW, respectively). The recovery factor obtained from LSW flooding at the tertiary state for SW, 1/2SW, and 1/10SW brines increased up to 11.86, 12.67, and zero, respectively. The main conclusions of the work were as follows. (1) The results of secondary spontaneous imbibition tests showed that LSWI had a significant potential to mobilize the trapped oil. (2) During secondary and tertiary core flooding, the maximum oil recovery (78% of OOIP) was achieved during smart water flooding when the amount of SO 4 2 - ion was increased and inactive ions ( Na + and Cl - ) were eliminated. (3) LSWI and smart water showed significant effects on relative permeability curves, which are indicative of wettability alteration. (4) The main driving mechanism for oil mobilization was found to be wettability alteration, which was supported by the analyses of CA and ZP. [ABSTRACT FROM AUTHOR]

[Display omitted] The emulsification of water and crude oil is typically examined and optimized in test tubes by optical means, that is, mixed under turbulent conditions and detected outside the porous medium in equilibrium. In this study, we investigate the rather complex case of crude oil emulsification by alkaline solutions to assess whether the classical phase behavior experiments are representative of the emulsification under laminar flow conditions in porous media. We characterized the phase equilibrium in the test tubes through X-ray attenuation in micro-X-ray computed tomography (μCT). Moreover, we showed that for these systems, the conventional qualitative optical inspection leads to considerable misinterpretation. X-ray attenuation ensures a quantitative analysis directly comparable to results from μCT-based core-flood experiments, where phase mixing occurs in porous media flow. The study was complemented with microfluidic experiments providing additional high-resolution information on emulsion phases. We conclusively show that in the complex in situ saponification of crude oil by alkaline flooding, (a) the emulsifications in test tubes and in porous media flow are comparable, considering the displacement process in the latter; (b) a minimum emulsion volume with balanced compositions leads to optimal oil recovery in μCT-based and conventional core flooding and in microfluidics. [ABSTRACT FROM AUTHOR]

A common assertion is that alkaline solution aids oil mobilization by generating in situ soap, or by lowering interfacial tension (IFT) to ultra-low values in synergy with surfactants. This study takes a different approach that involves the alkaline dissolution of detrital quartz grains of sandstone reservoirs to create pathways for oil migration and accumulation. Quartz dissolution via alkaline injection will result in changes in permeability and porosity. This study performed high-pH core flooding on Berea sandstones using core displacement equipment. Silica molybdate spectrophotometry was applied to measure the amount of dissolved silica. Inlet and confining pressure variations were also observed. The molar concentration of NaOH varied at 0.5 M and 1.0 M. The results show higher initial silica dissolution for 0.5 M NaOH (˃200mg/L) compared to 1.0 M NaOH (20 mg/L), which can be attributed to the presence of pre-existing dissolved silica and precipitates in the system prior to the first injection phase. Nonetheless, a steady quartz dissolution rate of 0.4 mg/L/hr for 20 h was only achieved at 1.0 M. Conversely, an abrupt drop in quartz dissolution to below 0 mg/L was recorded for 0.5 M NaOH after 3 h of dissolution. At higher molar concentration of injected alkaline solution, both confining and inlet pressures increased from 8 and 5 bars to 12 and 11 bars as a result of the increased secondary phase of (hydr)oxides or precipitates in the pores. Thus, it can be inferred that the effect of alkaline solution on quartz dissolution is strongly dependent on molar concentration.

Polymer flooding is one of the enhanced oil recovery (EOR) methods that increase the macroscopic efficiency of the flooding process and enhanced crude oil recovery. In this study, the effect of silica nanoparticles (NP-SiO2) in xanthan gum (XG) solutions was investigated through the analysis of efficiency in core flooding tests. First, the viscosity profiles of two polymer solutions, XG biopolymer and synthetic hydrolyzed polyacrylamide (HPAM) polymer, were characterized individually through rheological measurements, with and without salt (NaCl). Both polymer solutions were found suitable for oil recovery at limited temperatures and salinities. Then, nanofluids composed of XG and dispersed NP-SiO2 were studied through rheological tests. The addition of nanoparticles was shown to produce a slight effect on the viscosity of the fluids, which was more remarkable over time. Interfacial tension tests were measured in water-mineral oil systems, without finding an effect on the interfacial properties with the addition of polymer or nanoparticles in the aqueous phase. Finally, three core flooding experiments were conducted using sandstone core plugs and mineral oil. The polymers solutions (XG and HPAM) with 3% NaCl recovered 6.6% and 7.5% of the residual oil from the core, respectively. In contrast, the nanofluid formulation recovered about 13% of the residual oil, which was almost double that of the original XG solution. The nanofluid was therefore more effective at boosting oil recovery in the sandstone core.

Polymer gel has been established as a water shut-off control agent for improved oil recovery. The role of the polymer gel in conformance control is to divert injected water from high permeability to low permeability zones of the reservoir. This paper presents a series of core flooding tests performed to investigate the propagation, blocking capability, permeability reduction and diverting performance of various mixtures of polymer gels at simulated reservoir condition. In this particular study, a core flooding scheme with crossflow effect using composite core has permeability contrast. Core flooding test with crossflow effect simulates reservoirs with communication between reservoir permeability layers. Experimental results show that PAM/PEI polymer gel reinforced with solid silica NP has been proven to provide satisfactory gel strength to divert water flow, thus recovering an additional 24% of oil. This reinforced PAM/PEI polymer gel tends to recover more trapped oil compared to weakened PAM/PEI polymer gel without solid particles. These results give better understanding and provide additional knowledge of strengthening gel by addition of solid particles, which could be the remedy for the weakened polymer gel. [ABSTRACT FROM AUTHOR]

Different methods of enhanced oil recovery have been used to produce trapped oil. One of these methods is carbonated water injection in which CO2 contained water is injected in reservoirs in order to decrease free CO2 injection mobility, increase water viscosity and store/remove produced greenhouse CO2 gas safely. Another enhanced oil recovery method is smart water injection at which the ions in brine are modified in order to make controlled reactions with distributed ions on the surface of rock to cause more hydrocarbon recovery. Therefore, combination of these two methods may also have a great effect on enhancing oil recovery or may result in recovery factor less than each method used alone. In this paper hybrid smart carbonated water injection method is investigated to study its applicability in oil recovery using core flooding setup. The experimental core flooding setup was designed to perform different types of EOR methods for the sake of recovery comparison with the new hybrid method. The effect of both brine content and volume of CO2 is determining in hybrid EOR assessment. The main findings of this work show that the hybrid smart carbonated water results in the highest recovery factor in comparison to the most well-known EOR methods for carbonate cores.

CO2 flooding is a proven enhanced oil recovery (EOR) technique and is also considered as a potential method for CO2 sequestration. Despite having successful field trials on CO2 EOR, the effects of reservoir wettability and permeability heterogeneity on the efficiency of miscible CO2 flooding are not well understood. In this work, laboratory investigations have been carried out to evaluate the influence of these properties on the miscible CO2 EOR performance. The wettability of hydrophilic Berea core samples was altered to be oil-wet by vacuum saturation of the clean and dry core samples with n-hexadecane. The permeability heterogeneity was obtained by combining two half pieces of axially split water-wet core samples of different permeabilities. Core flooding experiments were conducted for n-hexadecane - synthetic brine - CO2 systems at 1400 psig backpressure to achieve minimum miscibility pressure (MMP) of CO2 in n-hexadecane at the test temperature (24 ± 1 °C). It was found that wettability strongly influences CO2 EOR. For the alternate cases of previously brine flooded (to remaining oil saturation) oil-wet and water-wet core samples, five pore volumes (PVs) of CO2 recovered 100% and only 43% of remaining oil in place (ROIP) respectively. Three PVs of CO2 could recover only about 0-5% ROIP from the split core samples. The mechanisms underlying these results are discussed. This study sheds light on the significant influence of reservoir wettability and permeability heterogeneity on the performance of miscible CO2 EOR.

Recently, the increase in fuel oil demand was not supported by petroleum production due to the low productivity of old wells. Furthermore, an appropriate technology, such as Enhanced Oil Recovery (EOR) technology, is needed to maximize the productivity of the old well. Therefore, the purpose of this study was to synthesize a polymeric surfactant for the EOR process from sodium lignosulfonate (SLS) and polyethylene glycol (PEG) in various SLS to PEG ratios, namely 1:1 (PS1), 1:0.8 (PS2), and 1:0.5 (PS3). The surfactants were characterized using several methods, such as Fourier Transform-Infrared spectroscopy (FT-IR), compatibility, stability, viscosity, and phase behavior tests. The performance of the surfactants for the EOR process in different brine solution concentrations (16,000 ppm and 20,000 ppm) was also studied. The result showed that the introduction of the PEG molecule to the surfactant had been successfully conducted as FT-IR analysis confirmed. The surfactant's hydrophilicity increased with the introduction of PEG due to the increase of the ether group. A Winsor Type I or lower phase microemulsion was formed due to the high hydrophilicity. The highest oil yield (79 %) was obtained by PS1 surfactant, which has the highest PEG dosage, in a brine solution of 1,600 ppm. Therefore, it was concluded that the introduction of PEG could increase the hydrophilicity, viscosity, and EOR performance. [ABSTRACT FROM AUTHOR]

While the "low salinity waterflooding" (LSWF) has been praised for enhancing oil recovery from different core rocks, the performance of the technique in different wettability environments remains unclear. The consensus is that LSWF does not work well in water-wet carbonate oil reservoirs. The main research objective was to determine the effect of LSWF on the displacement efficiency (DE) in different wettability environments. Carbonate core flooding experiments on rocks with different wettabilities were performed at in-situ reservoir conditions using seawater as a "base water". Seawater was sequentially diluted 10 to 50 times and spiked 2 and 6 times with sulfate. Following sequential flooding with four different waters, the DEs were measured for different wettabilities. Five different sequential brine floodings were performed on carbonate rocks. Results indicated that optimum low salinity water is a function of system wettability. Seawater (≈ 50,000 ppm) is the optimum brine for oil-wet and intermediate-wettability systems. Sequential flooding consisting of seawater followed by diluted seawater in a water-wet system yielded the highest DE of 88%. Besides, low-salinity brine followed by sulfate performed better in a water-wet environment than in oil- and intermediate-wettability systems. [ABSTRACT FROM AUTHOR]

In this paper, the effect of temperature on low salinity brine and combined low salinity enzyme oil recovery processes in sandstone rock sample was experimentally investigated. The core flooding displacement tests were conducted with the injection of the enzyme in post-tertiary mode after secondary high salinity brine and tertiary low salinity brine injection processes. Effluents analyses of each of the flooding were carried out and used to evaluate the effect of temperature on rock-fluid interactions and enhanced oil recovery processes. The results showed that tertiary low salinity brine injection and post-tertiary enzyme injection increased recovery by 2.4-8.72% over the secondary high salinity brine flooding at 25 oC. Also, increase in oil recovery (0.57-13.18%) was observed with increase in the system temperature from 25 oC to 70 oC. Furthermore, the effluent of the 70 oC flooding was associated with the earliest low salinity brine ionic breakthrough front at 10 injected pore volume, while the 25 oC flooding breakthrough front occurred at 22 pore volume. However, no obvious effect of temperature on pH of the effluents was observed with all the floodings, but temperature effects were observed with the conductivity and ionic concentrations of all the effluents as evident by varied breakthrough times. Hence, the observed increased recovery in this study is attributable to combined effects of electric double-layer expansion, oil viscosity reduction and interfacial tension reduction. This novel study of the combined low salinity enzyme injection process is significant for the design of enzyme enhanced oil recovery processes.

Despite the implementation of hydraulic fracturing technologies, the oil recovery in tight oil reservoirs is still poor. In this study, cationic, anionic, and nonionic surfactants of various sorts were investigated to improve oil recovery in tight carbonate cores from the Middle Bakken Formation in the Williston Basin. Petrophysical investigations were performed on the samples prior to the imbibition and core-flooding experiments. The composition of the minerals was examined using the XRD technique. To investigate the pore-size distribution and microstructures, nitrogen adsorption and SEM techniques were applied. The next step involved brine and surfactant imbibition for six Bakken cores and two Berea sandstone cores. The core samples were completely saturated with Bakken crude oil prior to the experiments. The core plugs were then submerged into the brine and surfactant solutions. The volume of recovered oil was measured using imbibition cells as part of experiments involving brine and surfactant ingestion into oil-filled cores. According to the findings, oil recovery from brine imbibition ranges from 4.3% to 15%, whereas oil recovery from surfactant imbibition can range from 9% to 28%. According to the findings, core samples with more clay and larger pore diameters produce higher levels of oil recovery. Additionally, two tight Bakken core samples were used in core-flooding tests. Brine and a separate surfactant solution were the injected fluids. The primary oil recovery from brine flooding on core samples is between 23% and 25%, according to the results. The maximum oil recovery by second-stage surfactant flooding is approximately 33% and 35%. The anionic surfactants appear to yield a better oil recovery in tight Bakken rocks, possibly due to their higher carbonate mineral concentrations, especially clays, according to both the core-scale imbibition and flooding experiments. For studied samples with larger pore sizes, the oil recovery is higher. The knowledge of the impacts of mineral composition, pore size, and surfactant types on oil recovery in tight carbonate rocks is improved by this study.

The carbon dioxide (CO2) injection is the promising enhanced oil recovery technique used in low permeability reservoirs. The presence of high permeability fractures along the matrix leads to poor sweep efficiency and gas channeling effect. The CO2 responsive mobility control gels could be a potential solution to mitigate the gas channeling effects. This work showcases the straightforward method to prepare a CO2 responsive gel by mixing aqueous suspension of nanocellulose and ethylenediamine. The addition of CO2 leads to protonation of amine which enhances the ionic strength of the solution. This promotes the agglomeration of nanocellulose to form gel. The rheological properties of the gel were studied and found to have interesting mechanical property. And the micromodel is used to visualize the mobility control phenomenon of the as prepared gel. The core flooding experiment proves that the synthesized gels were effective in low permeable cores. [ABSTRACT FROM AUTHOR]

High molecular weight amphoteric terpolymer based on a nonionic monomer, acrylamide (AAm), an anionic monomer, 2-acrylamido-2-methyl-1-propanesulfonic acid sodium salt (AMPS), and a cationic monomer, (3-acrylamidopropyl) trimethylammonium chloride (APTAC), was prepared using free-radical copolymerization in an aqueous solution and characterized by 1H NMR, FTIR, GPC, DLS, zeta potential and viscometry. The polymer was shown to be viscosifying, and therefore can be utilized as a polymer flooding agent in the high salinity and temperature conditions of oil reservoirs. Injection of 0.25 wt.% of amphoteric terpolymer, dissolved in 200-300 g∙L-1 brine, into high and low permeability sand pack models demonstrated that the oil recovery factor (ORF) increases by up to 23-28% in comparison with saline water flooding. This is explained by an increase in the viscosity of brine solution due to disruption of intra- and interionic contacts between oppositely charged AMPS and APTAC moieties, demonstrating the antipolyelectrolyte effect. In high saline water, the anions and cations of salts screen the electrostatic attraction between positively and negatively charged macroions, resulting in expansion of the macromolecule. This phenomenon leads to an increase in the viscosifying effect on the brine solution, thus decreasing the mobility factor (M), which is defined as the ratio of displacing phase mobility (water) to displaced phase mobility (oil). [ABSTRACT FROM AUTHOR]

CO2 flooding is a proven enhanced oil recovery (EOR) technique and is also considered as a potential method for CO2 sequestration. Despite having successful field trials on CO2 EOR, the effects of reservoir wettability and permeability heterogeneity on the efficiency of miscible CO2 flooding are not well understood. In this work, laboratory investigations have been carried out to evaluate the influence of these properties on the miscible CO2 EOR performance. The wettability of hydrophilic Berea core samples was altered to be oil-wet by vacuum saturation of the clean and dry core samples with n-hexadecane. The permeability heterogeneity was obtained by combining two half pieces of axially split water-wet core samples of different permeabilities. Core flooding experiments were conducted for n-hexadecane - synthetic brine - CO2 systems at 1400 psig backpressure to achieve minimum miscibility pressure (MMP) of CO2 in n-hexadecane at the test temperature (24 ± 1 °C). It was found that wettability strongly influences CO2 EOR. For the alternate cases of previously brine flooded (to remaining oil saturation) oil-wet and water-wet core samples, five pore volumes (PVs) of CO2 recovered 100% and only 43% of remaining oil in place (ROIP) respectively. Three PVs of CO2 could recover only about 0-5% ROIP from the split core samples. The mechanisms underlying these results are discussed. This study sheds light on the significant influence of reservoir wettability and permeability heterogeneity on the performance of miscible CO2 EOR.

A hyperbranched carboxylate-type polymer was synthesized through esterification and carboxymethylation, and its performance on enhanced oil recovery was experimentally evaluated. The optimum condition for esterification was 8 h at 120°C, where 3% PTSA as the catalyst and 9:1 mol ratio of the AB2 intermediate and trimethylolpropane were used. The optimum condition for carboxymethylation was 4 h at 80°C. The critical micelle concentration of the hyperbranched polymer was 433.63 mg/L, the Krafft point was 5°C, and the surface tension was lowered to 28 mN/m. In the range of 400–500 mg/L concentration, the adsorption onto the oil sand surface achieved equilibrium, and micellar solubilization reached 600 ml/mol. The interfacial tension can be lowered to a level of 10−2 mN/m by the single use of the hyperbranched polymer, and the value further decreased to a level of 10−3 mN/m while being formulated with sodium dodecylsulfate or NaOH. Oil recovery of water flooding was further enhanced by the single use of a hyperbranched polymer or the combination of hyperbranched polymer/sodium dodecylsulfate. The latter exhibited more prosperous advantages in low-permeability reservoirs.

The results of the numerical study of oil recovery enhancement using nanosuspension are presented. The research was carried out using the volume of fluid method (VOF) for a 2D microporous core model. Experimentally measured values of interfacial tension (IFT) and the contact angle (CA) were used for numerical modeling. An aqueous suspension with silicon oxide nanoparticles (5 nm) is used. It was shown that when 1 wt% of nanoparticles are added to the displacing liquid, its density increases by about 1%, the viscosity increases by 10%, the IFT decreases by 10%, and the contact angle increases from 70 to 145 ∘ . The results of numerical study showed that the injection of nanoparticles has a significant effect on the displacement front movement in the microporous model. It has been shown that the nanosuspension can increase the oil recovery factor (ORF) almost twice as compared to water. To clarify the mechanisms of increasing the oil recovery during the reservoir flooding with nanofluid, a systematic study of factors affecting the displacement process efficiency was carried out. Viscosity, interfacial tension and the wetting angle of the displacing fluid were considered as such factors. As a result of systematic research, it has been shown that the main factor affecting the increase in the oil recovery flooding of nanosuspensions is a variation of wettability. [ABSTRACT FROM AUTHOR]

Challenges during CO2 flooding of oil reservoirs are mobility control and gravity override caused, respectively, by lower viscosity and density of CO2 compared with reservoir fluids. Blocking agents such as foam, cross-linked polymers and gels have been tested. However, such techniques are more effective in preventing fingering and blocking thief zones than reducing gravity override. Moreover, no foaming agent has been identified to withstand the high temperatures and salinities of some reservoirs. This experimental study investigates the use of triethyl citrate (TEC) as a densifying agent to blend with supercritical CO2 (scCO2) to minimize gravity override. High-permeability, Indiana limestone core samples saturated with either dead or live light crude oils at irreducible water saturations were flooded vertically upward at 24.132 MPa and 100 °C with about one pore volume of either pure scCO2 or a scCO2–TEC blend of 0.15 mol fraction (0.525 mass fraction) TEC. At breakthrough, scCO2 flooding of dead oil recovered 14.82% of the initial oil in place, while the blend flood recovered 31.99%. At 1 PV, the scCO2 flood recovered 60.14%, while the blend flood recovered 72.67%. The live-oil-saturated core samples produced similar results but with generally lower oil recoveries. At 1 PV of fluid injected, all floods reduced the oil saturation to levels lower than the residual oil saturation achieved with water flooding. With TEC's low solubility in both crude oil and water, blending scCO2 with TEC is, thus, a technically viable method to mitigate gravity override in CO2–EOR process. [ABSTRACT FROM AUTHOR]

Formation damage due to fines migration is among the root causes for hydrocarbon productivity decline. This occurs due to minerals dislodging when reservoir fluid flow beyond critical velocity and by poor cementation after acid stimulation activities. Conventional chemical methods have been widely used to prevent the fines migration, however, most of the chemical stabilizer is less robust, functional based on composition of exchangeable cations in rock minerals, cause temporary stabilization and are not environmentally friendly. This paper explores the potential of colloidal silica nanoparticles (C-SNPs) as new solution for fines migration control application. A series of critical velocity core flooding experiments has been carried out to determine the C-SNPs efficiency in enhancing the critical velocity at various temperatures. Berea Buff cores pre-treated with 0.05% C-SNPs (35 nm), were exposed to elevated injection rates. Synthetic formation brine was injected via alternating increasing and return to baseline rate from 0.5 to 41.5 mL/min. The stabilize pressure drops generated during brine injection after C-SNPs injection were used to establish the baseline permeability, kw. The stabilized pressure drops generated after each elevated rate were calculated to determine the permeability, k (at 0.5 mL/min) and to establish the k/kw graph plot. The critical rate's value was obtained when permeability reduction occurred in the range from 10 to 20% from the initial permeability value. Microscopic visualization using FESEM of the treated cores showed traces of nanoparticles on the core surface and surface modification by surface roughness measurement via atomic surface microscopy (AFM). The permeability of all treated cores remained constant up to 5 mL/min. At 8.3 mL/min and above, variation in permeability was observed caused by fines mobilization but with no significant permeability drops up to 41.5 mL/min. Modification of pore walls and fines surfaces by nanoparticles attachment was described by low surface roughness. The attraction of fines particles on the pore wall and within the particles themselves had strengthened surface morphology, therefore, their detachment and mobilization in porous media were not seen when exposed to high injection velocity. [ABSTRACT FROM AUTHOR]

Abstract This study investigates the sandpack displacement of low viscosity oil (1.68 cP) by brine and aqueous solutions of associative polymers. Polymer flooding has been thoroughly investigated in many laboratory and field tests. Polymer flooding is one of the most widely used enhanced oil recovery (EOR) methods. The method of polymer flooding is not used for development of oil fields with gas caps, fractured reservoirs, high permeability and active bottom-water drive. In the application of polymer flooding, coefficient of oil recovery is increased by 3–10%. Hydrolyzed polymers undergo the significant thermal and chemical degradation at high temperature and salinity. In recent years, researchers have turned their attention to associative polymers. An application of associative polymers to withstand degradation in high temperature and high salinity conditions can enhance oil recovery in high heterogeneous fields. This article presents the results of studies of oil displacement by associative polymers in a two-layer core model. In laboratory studies, the core selected from a sandy reservoir of the South Turgay Basin of the Republic of Kazakhstan was used. Solutions of the following polymers were studied: hydrolyzed polyacrylamide (HPAM) and associative polymer. The physicochemical conditions of the experiments corresponded to the reservoir conditions of the sand layer of the South Turgay Basin: temperature of 82 °C and the salinity of the brine 92,000 ppm. Experiments revealed that the associative polymer is more stable in simulated reservoir conditions than the HPAM polymer. Associative polymer flooding was recommended for pilot testing at the reservoir of the South Turgay Basin.