Oil Recovery Mechanisms Research Articles

The development of heat‐resistant and salt‐tolerant foam with betaine surfactants

AbstractA modified instrument was designed to evaluate foam properties under high temperature and pressure. The type and molar ratio of betaine surfactants were screened to develop the heat‐resistant and salt‐tolerant foam for Tahe oilfield (130°C, 220 g/L), and the effects of temperature and pressure on foam properties were also investigated. The synergism between surfactants and the enhanced oil recovery (EOR) mechanism of foam flooding in fractured‐vuggy reservoirs were studied. Experimental results showed the developed foam had excellent foaming ability and foam stability when the lauramidopropyl hydroxyl sulfobetaine (LHSB): erucic amide propyl betaine (EAB) molar ratio ranged from 1:1 to 1:2 (initial foam volume was 392 ml when the molar ratio was 1:1, drainage half‐time was 5.75 min and foam half‐time was 72 min when the molar ratio was 1:2 at 130°C and 2 MPa). The synergistic effect was found to reach its maximum when the LHSB:EAB molar ratio ranged from 1:1 to 1:2 according to interaction parameters, which agreed with the results of foam properties. Foam stability was found to considerably increase with increasing pressure, but decrease with increasing temperature. However, temperature and pressure were found to have consistent effects on foaming ability, that is, the foaming ability increased with increasing temperature and pressure. The flooding test showed foam flooding exhibited better sweep efficiency and higher recovery ratio in the fractured‐vuggy model than gas flooding and water flooding. This could be because injected foam did not channel through the top (or bottom) path due to its high viscosity and moderate density.

Imidazolium based ionic liquids for enhanced oil recovery on the carbonate reservoir

Improving the oil recovery by changing the wettability using chemicals often possess huge challenges in the harsh oil-wet carbonate reservoirs, such as chemical instability, high retention, lack of deliverability in the deep reservoir, etc. In this study, we investigated the adsorptive behavior of imidazolium-based ionic liquids (ILs) on the carbonate reservoir, and also evaluated their performance in the oil recovery using the high temperature and high pressure coreflood setup. The measured adsorption values are well within the limit of field requirements. In which, the ILs with longer alkyl chains had shown less adsorption than the shorter ones. Next, in the coreflood oil recovery studies, the injection of ILs after waterflooding increased the oil recovery by 12–26% additionally. As expected, the lengthier alkyl chain containing ILs work more effectively than the shorter chain ones. For a case of reference, we also studied a few conventional surfactants (anionic, cationic, nonionic, and zwitterionic). We also extracted the unsteady state two-phase relative permeability curves of the SW and ILs flooding coreflood experiments to understand the flow characteristics of oil and water while injecting SW, and ILs. It was observed that the ILs improved the oils’ flowability, kro, and reduced the water’s mobility, krw. All these experiments were performed at the Saudi Arabian reservoir conditions of 100 °C, and at 4500 psi confining pressure, and at high salinity (TDS = 240, 000 ppm). In addition, we also demonstrated the wettability and interfacial tension (IFT) measurements in order to analyze the oil recovery mechanism. It was noted that both the ILs and surfactants alter the rock wettability from strongly oil-wet into intermediate-wet, while in the IFT measurements, the surfactants outperformed the ILs. Hence, it can be conceded that the oil recovery with ILs was dominated by the wettability modification, and for the surfactants, it was the combined effect of both wettability alteration and interfacial tension reduction. The use of dilute concentration of ILs (10–500 ppm) can be considered as the most profitable, and the best alternative over the costlier surfactant flooding.

Fabrications and Applications of Micro/Nanofluidics in Oil and Gas Recovery: A Comprehensive Review

Understanding fluid flow characteristics in porous medium, which determines the development of oil and gas oilfields, has been a significant research subject for decades. Although using core samples is still essential, micro/nanofluidics have been attracting increasing attention in oil recovery fields since it offers direct visualization and quantification of fluid flow at the pore level. This work provides the latest techniques and development history of micro/nanofluidics in oil and gas recovery by summarizing and discussing the fabrication methods, materials and corresponding applications. Compared with other reviews of micro/nanofluidics, this comprehensive review is in the perspective of solving specific issues in oil and gas industry, including fluid characterization, multiphase fluid flow, enhanced oil recovery mechanisms, and fluid flow in nano-scale porous media of unconventional reservoirs, by covering most of the representative visible studies using micro/nanomodels. Finally, we present the challenges of applying micro/nanomodels and future research directions based on the work.

The effect of hydroxyapatite nanoparticles on wettability and brine-oil interfacial tension as enhance oil recovery mechanisms

A novel concept of utilizing nanoparticles (NPs) to boost oil recovery and reduce entrapped oil in hydrocarbon reservoirs is being explored. The use of nanofluids (NFs) flooding to change wettability and reduce interfacial tension (IFT) between oil and water has been shown to be highly effective in experiments. Preparation and modification methods influence the performance of NPs. The application of hydroxyapatite NPs (HAP) in EOR has yet to be investigated. HAP was synthesized in this study using the co-precipitation method and in-situ surface functionalization with Sodium Dodecyl Sulphate SDS to visualize it effect on IFT reduction and wettability alteration under different salinity and temperature settings. To confirm the synthesis of HAP, zeta potential (ZP), Fourier transform infrared spectroscopy (FTIR), Particle size analysis (PSA), Transmission electron microscopy (TEM), and Energy dispersive X–ray (EDX) spectra were used respectively. According to the results, HAP was produced, and the particles were finely distributed and stable in aqueous solution. When the pH was altered from 1 to 13, the particles' surface charge rose from -5mV to −27mV, showing long-term stability in EOR processes. At salinity range from 5000 ppm to 30,000 ppm, and under temperature range from 25ᵒC to 80ᵒC, the HAP NFs changed the wettability of sandstone core from oil–wet at 111.7° to water–wet at 9.0°. In addition, at 0.1 wt% HAP concentration, the IFT was lowered to 3 mN/m. As a result, the HAP NF proved very effective in reducing IFT and altering wettability under both low and high salinity environments, and it is thus suggested for EOR operations.

Effects of brine valency and concentration on oil displacement by spontaneous imbibition: An interplay between wettability alteration and reduction in the oil-brine interfacial tension

Brine fluids have recently been of high interest to enhanced oil recovery process in both academia and industry. Both diluted formation brines and specifically formulated brines were reported to improve crude oil displacement in porous rock, owing to either their bulk salinity or brine-type. Mechanisms for such an improvement were widely proposed, including microscopic interfacial phenomena: wettability alteration and reduction in the oil-brine interfacial tension (σ), although their synergistic or interlinked contributions were vaguely clarified. To elucidate insights into this “low-salinity” enhanced oil recovery, crude oil displacement by spontaneous imbibition was conducted in the current research with focus on the effects of brine valency and concentration. Monovalent (NaCl) and divalent (CaCl2) brines at elevated concentrations (10, 100, and 1000 mM) were examined as imbibing fluids. Changes in the three-phase contact angle and the crude oil-brine interfacial tension were also investigated. Imbibition results showed that NaCl brine at ‘suitable’ concentration (100 mM) displaced greater oil (95.8 %) than too-low (10 mM) or too-high (1000 mM) concentrations, and these monovalent brines displaced more effective than those of divalent CaCl2 due to an oil-wetting as a result of divalent ion bridging phenomenon. This echoes crucial influences of both brine valency and concentration. Since no direct individual contribution from either the contact angle or σ on the oil displacement was obtained, an interplay between these two parameters were thought to control. The imbibition results were a capillary-dominated process (capillary number < 2.1 × 10−6), re-confirmed by their correlations with the calculated capillary pressures and inverse Bond numbers. The findings revealed that in a given imbibition system a required σ is a wettability-dependent: water-wet system needs high σ to enhance a driving capillarity while oil-wet system prefers lower σ to weaken a resisting capillary force. Brine formula directly attributed to wettability and σ: NaCl brines secure water-wetting with high σ while CaCl2 brines reduced σ more effectively with an assured oil-wetting. Low-salinity enhanced oil recovery mechanism was thus found to be contributed from capillary effect, which was an interplay between the interfacial tension and wettability. Paring these two parameters by formulating imbibing brine to anticipate high oil recovery is crucial and of challenge.

Performance evaluation and mechanism study of a functionalized silica nanofluid for enhanced oil recovery in carbonate reservoirs

In this investigation, a functionalized SiO2 nanofluid was developed by integrating sodium oleate to mercapto-terminated nano-SiO2 via the thiol-ene “click” reaction. The developed nanofluid in the presence of higher concentrations (> 40,000 ppm) of NaCl at 70 °C was confirmed to be more stable than the original SiO2 nanofluid based on the outcomes obtained from precipitate observation, particle dimension, and zeta potential measurements. Successful integration of sodium oleate on the target nanoparticles was corroborated by a series of characterization approaches. Furthermore, the viscosity, contact angle, and interfacial tension (IFT) determinations were conducted to investigate nanofluids' potential for enhanced oil recovery (EOR). The results indicated that the viscosity of the functionalized SiO2 nanofluid (labeled FF-4) accounted for 3.48 cp after adding 40,000 ppm NaCl, while that of the original SiO2 nanofluid (labeled OF-4) was 1.15 cp. From the contact angle values, the carbonate rock surface was transformed from oil-wet (135°) to water-wet (72° and 38°) after being treated with the OF-4 and FF-4. The wettability alteration was attributed to the formation of the wedge film in the contact line area between the rock and fluids (oil sample and nanofluid). The functionalized nano-SiO2 helped to reduce IFT because of the simultaneous presence of the alkane chain (oleophilic) and carboxylate group (oleophobic) on the particle surface, making the functionalized nano-SiO2 have an amphiphilic structure. However, the original nano-SiO2 hardly changed IFT. Micro-model experiments showed that the OF-4 had a prominent oil displacement effect by changing wettability to a water-wet state and reducing the viscous fingering phenomenon. Core flooding tests demonstrated that the oil recovery factor of the FF-4 was almost 2.5 times that of the OF-4. Viscosity improvement was considered as a new oil recovery mechanism after wettability alteration and IFT reduction. This paper revealed the important properties of the functionalized nano-SiO2 and provided a novel efficient nanofluid for EOR in carbonate reservoirs.

New Insights into the Understanding of In-Situ Combustion: Important Considerations When Modeling the Process

Summary Air-injection-based enhanced oil recovery (EOR) processes have historically been of great interest due to their high recovery potential and applicability to a wide range of reservoirs where other processes are not effective or economical. However, most operators require a certain level of confidence in the potential recovery from these (or any) process before committing resources; this is commonly achieved with the support of laboratory and reservoir simulation studies. Laboratory testing, including combustion tube, ramped temperature oxidation (RTO), and accelerating rate calorimeter (ARC) tests, can supply data for simple analytical models. It can also provide important insights into potential oxidation behaviors and oil recovery mechanisms. Similarly, reservoir simulation of some of those experiments can assist in the understanding of the process and may allow for the development of kinetic models that can be used for further reservoir modeling. However, due to sample size limitation and the unscaled nature of the experiments, these tests are not ideally suited to provide detailed or unique kinetic data for direct use in numerical simulators. In fact, the oxidation reactions are sufficiently complex that, regardless of how robust a thermal reservoir simulator may be, its predictive capability strongly depends on the engineer’s understanding of the process and ability to model the most relevant oxidation behaviors of the particular hydrocarbon reservoir under study. Over the past 50 years, the In-Situ Combustion Research Group (ISCRG) at the University of Calgary has dedicated its efforts toward the advancement of this technology. Under the leadership of Professor Gordon Moore, the ISCRG has performed a large number of combustion tests, designed and carried out many novel oxidation experiments, and also made important contributions to the numerical modeling of air-injection-based processes. Nevertheless, in spite of its long research history, the group acknowledges that there is still much that needs to be learned about the process. For example, two oils with the same physical properties such as viscosity and density can have significantly different oxidation behaviors, which are difficult to predict; this is one of the reasons the group continues to perform laboratory experiments and conduct research in this area. This paper describes some of the most important conceptual contributions made by the ISCRG based on their experimental results and how they have enhanced our understanding of the process. These continue to be an important source of knowledge toward the development of predictive reservoir simulation models, as it is very difficult, if not impossible, to properly model a physical problem one does not understand well. For instance, the fundamental equations used for mathematical modeling depend on selecting of the relevant physical mechanisms and assumptions made, and these are derived from experimental work. Similarly, when using a commercial numerical simulator, the selection of fluid pseudocomponents as well as their physical properties and chemical reactions, as well as their kinetic parameters, also depend on an understanding of the process. This paper provides a summary of the relevant physical aspects to consider when modeling the in-situ combustion (ISC) process as well as new insights on its dynamics based on the laboratory experiments performed by the ISCRG.

Characteristics and mechanism of imbibition oil recovery in the ultra-low-permeability volcanic oil reservoir in the Santanghu Basin

Imbibition oil recovery (IOR) is an important method to improve the recovery factor (RF) of low-permeability reservoirs. To explore the characteristics and mechanism of IOR in ultra-low-permeability volcanic oil reservoirs (ULPVORs) in the Santanghu Basin, this study conducted various imbibition experiments under NMR monitoring using actual cores from the reservoir, including spontaneous imbibition (SI) and forced imbibition (FI) experiments involving different rock sample sizes. Further, we obtained the IOR characteristics of ultra-low-permeability volcanic rocks (ULPVRs). Meanwhile, based on the experimental test results of the pore structure and casting thin section, combined with imbibition theory, the mechanism of the IOR in ULPVRs was obtained. The results demonstrated that the IOR characteristics of the ULPVRs are significantly different from those of conventional tight sandstone and shale. Conventional tight sandstone and shale evenly produce oil on the rock surface during IOR, whereas ULPVRs exhibits extremely few and scattered oil production points on the rock surface during IOR. Unlike conventional tight sandstone and shale plunger cores where the RF of SI is generally approximately 30%, the IOR of ULPVRs is particularly poor, with RFs of SI being 4.59% and 2.70% for plunger and full-diameter cores, respectively, and the RF of FI is only 10.19% for the plunger core. In addition, ULPVRs are extremely heterogeneous, and the pore structure and production characteristics of IOR are extremely complicated. The oil produced by SI in the plunger and full-diameter cores comes from middle pores (0.01 µm<r < 0.1 µm) and large pores(r > 0.1 µm), respectively, while the oil produced by FI in the plunger core comes from large pores. Conventional tight sandstone and shale are not conducive to seepage owing to their small pore sizes, however, their compatibility between the pore and throat sizes makes them favorable for IOR. The extremely poor matching between the pore and throat sizes of the ULPVRs is unfavorable for seepage, and is primarily responsible for its poor IOR effect. For the ULPVORs in the Santanghu Basin, the key to EOR is to improve the seepage capacity of the reservoir throat, such as further large-scale volume fracturing, rather than implementing too many measures for IOR. The results of this study can provide a reference and basis for the efficient development of ULPVORs.

Surface modification of nanoparticles to improve oil recovery Mechanisms: A critical review of the methods, influencing Parameters, advances and prospects

• Surface modification of NPs can be classified as in-situ or post-synthesis. Both employ identical procedures. • Grafting-from increases grafting densities and polymer coverage of the NP surface than grafting-to. • Surface modifications can reduce particle hydrophilicity and thus particle retention on the rock surface. • In order to guide future research in this field, leading surface modification methods must be described in detail. The utilization of nanoparticles (NPs) in enhanced oil recovery (EOR) has a lot of benefits however, the usage of bare NPs still has a few drawbacks, including instability, agglomeration and aggregation, which can cause pore channel obstruction and quick sedimentation resulting in low oil recovery. Nonetheless, surface modification of NPs can circumvent these problems however, an account of leading approaches for surface modification and their effect on improving EOR effectiveness interconnected with NPs microscopic features, with the aim of providing a guide for future efforts in this area is essential. Here, a critical review on surface modification of NPs to improve oil recovery mechanisms is presented. Surface modification of NPs can be classified into two categories: in-situ surface modification and post-synthesis surface modification, both of which involve grafting, coupling, surfactant usage, and esterification to achieve the same results. Surface modifications can reduce particle hydrophilicity, reducing particle retention on rock surfaces. Depending on the NPs' surface nature, many techniques based on surface affinity for different chemical groups have been created. The study equally revealed that functionalized NPs have excellent mobility regulation, thermal stability and rheological properties, and they make oil droplets stable against coalescence. Moreover, the application of different surfaced modified NPs in EOR were reviewed. Finally, the challenges encountered were identified with proffered solutions, future trend and research opportunities were outlined. Since each modification type is tailored to the final application, there is no single best NPs surface modification technique. As a result, when it comes to specific goals, all techniques are equally weighted.

Towards prediction of oil recovery by spontaneous imbibition of modified salinity brine into limestone rocks: A scaling study

Spontaneous imbibition is a key mechanism of oil recovery in naturally fractured reservoirs. Many enhanced oil recovery techniques, such as modified salinity brine injection, have been suggested to improve spontaneous imbibition efficiency. To predict oil recovery by spontaneous imbibition process, scaling equations have been developed in the literature where almost none of them include the effect of two critical aspects. One aspect is the different ionic composition of injecting brine from connate brine. Another aspect is the effect of combination/interaction of a lower salinity imbibing (injecting) brine with connate brine. This research takes into account these two aspects to propose a new empirical scaling equation to scale oil recovery by modified salinity imbibing brines in limestone rocks. For this purpose, the results of available 59 tests from 14 references performed on various limestone rock samples collected from different formations and regions were used. The tests had been performed at high temperatures and on aged cores, which makes the proposed scaling equation more realistic and applicable to reservoir conditions. For the first time, the imbibing and connate brines ionic strengths are included in the equation due to the mechanism of the modified salinity brine injection method. In addition, the scaled spontaneous imbibition recovery data by the new equation was matched using two mathematical expressions based on the Aronofsky model and Fries and Dreyer model which can be used to derive transfer functions for simulation of spontaneous imbibition oil recovery by modified salinity brine injection in fractured limestone reservoirs.

Development of a Generalized Experimental Methodology for Investigating the Role of Steam Quality on Steamflooding Performance

Summary For steamflooding processes, steam quality plays a crucial role because it affects enhanced oil recovery mechanisms and production performance. Many numerical simulations have been performed on the role of steam quality. However, few studies have evaluated the role of steam quality on steamflooding performance by experimental measurements because of the lack of a generalized experimental methodology to accurately generate and measure steam with different qualities under reservoir conditions. The objective of this study is to propose a generalized experimental methodology for investigating the role of steam quality on steamflooding performance. A steam quality controlling box was newly designed and fabricated to generate steam with different qualities, and its reliability was verified by a novel steam quality measurement system together with a developed theoretical method. Then, a series of experiments were conducted by our designed 1D and 2D sandpack models to evaluate the steamflooding performance under different steam qualities. The results showed that the developed methodology could accurately generate and measure steam with different steam qualities. The maximum errors between desired, measured, and calculated steam qualities were 4.39% under the experimental conditions in this study. The steam quality substantially affected the steamflooding performance. A higher steam quality led to a lower water cut, a lower maximum pressure difference between the inlet and outlet of the sandpack model, a lower water/oil ratio (WOR), a lower steam/oil ratio (SOR), a higher oil recovery, and a higher oil production rate. However, there is an optimal value of steam quality from the view of heat efficiency in this study. The oil recoveries of 2D steamflooding experiments increased from 36.30 to 45.02% when the steam quality increased from 0 to 0.8. However, the optimal steam quality of 0.6 had the maximum heat efficiency at 3.16×10−5 kJ−1. This research contributes to a better understanding of steam quality on steamflooding performance and also provides a generalized methodology for other steam injection processes.

Water Imbibition and Oil Recovery in Shale: Dynamics and Mechanisms Using Integrated Centimeter-to-Nanometer-Scale Imaging

Summary Water imbibition, and the associated oil displacement, is an important process in shale oil reservoirs after hydraulic fracturing and in water-based enhanced oil recovery (EOR). Current techniques for water imbibition measurement are mostly “black-box”-type methods. A more explicit understanding of the water imbibition/oil recovery dynamics and geological controls is in demand. In this paper, a multiscale imaging technique that covers centimeter to nanometer scale (i.e., core to pore scale), integrating neutron radiography, microcomputed tomography (micro-CT), and scanning electron microscope (SEM) is applied to investigate the water imbibition depth and rate and the cause of heterogeneity of imbibition in shale samples. The dynamic processes of water imbibition in the 1-in. (25.4-mm) core sample were explicitly demonstrated, and the imbibition along the matrix and imbibition through microfractures are distinguished through neutron radiography image analysis. The causes of observed imbibition heterogeneity were further investigated through micro-CT and SEM image analysis for 1.5-mm diameter miniplug samples from different laminas of the 1-in. core samples. Imbibition depth and rate were calculated on the basis of image analysis as well. Estimation of oil recovery through water imbibition in shale matrix was performed for an example shale field. This innovative and integrated multiscale imaging technique provides a “white/gray-box” method to understand water imbibition and water-oil displacement in shale. The wide span of the length scale (from centimeter to nanometer) of this technique enables a more comprehensive, accurate, and specific understanding of both the core-scale dynamics and pore-scale mechanisms of water imbibition, oil recovery, and matrix-fracture interaction.

Enhanced oil recovery performance and mechanism of a wormlike micelles flooding system with zwitterionic-anionic surfactants

Surfactant-based wormlike micelles (WLMs) have been proven to be efficient in improving oil recovery due to their high viscosity and low oil/water interfacial tension (IFT). In this study, a novel WLMs oil displacement system was developed by mixing zwitterionic surfactant (Erucylamido propyl betaine, EAPB) and anionic surfactant (Sodium dodecylsulfate, SDS) at the mass ratio of 1.5:1. The viscosity, IFT and emulsification properties were studied by rheometry, interfacial tensiometry and bottle testing, respectively. The core and etched glass micro-model oil displacement tests were conducted to investigate the oil recovery efficiencies and the related mechanism. The results show that the EAPB-SDS combination system exhibits shear thickening compared to that of sole EAPB system due to the electrostatic attraction between SDS and EAPB. The viscosity is first increased and then decreased with the increase in pH, temperature and salinity. The IFT is decreased with pH, while it is first decreased and then increased with the increase of temperature and salinity. The EAPB-SDS combination system with mass concentration of 0.3% can enhance oil recovery by 25.91% and 19.79% after water flooding in homogeneous and heterogeneous cores, respectively. The high viscosity makes the system to exhibit good mobility control ability, while the low IFT contributes to the peeling and emulsification of residual oil, thereby significantly improving the oil displacement performance.

CO2-Enhanced Oil Recovery Mechanism in Canadian Bakken Shale

The recovery factor in unconventional reservoirs is typically 5–10%, with extensive hydraulic fracturing and infill drilling to maintain the production rate. Concurrently, the rush towards decarbonization is opening up new possibilities for CO2 utilization, enhanced oil recovery (EOR) being one example. CO2-EOR in unconventional reservoirs presents an opportunity for both financial gain through improved recovery factors, as well as reducing the carbon footprint of the produced oil. In this work, we examine the CO2-EOR potential in 4 organic-rich shale samples from the Canadian Bakken Formation. A number of characterization tests alongside CO2 extraction experiments were performed to gain insight into the controlling factors of CO2-EOR in these ultra-tight formations. The results show CO2 can penetrate the tight rock matrix and recover a substantial amount of hydrocarbon. Concentration gradient driven diffusion is the dominant form of recovery.

Controlling the Hydro-Swelling of Smectite Clay Minerals by Fe(III) Reducing Bacteria for Enhanced Oil Recovery from Low-Permeability Reservoirs

The hydro-swelling of smectite clay minerals in low-permeability reservoirs further decreases the reservoir permeability and results in low oil recovery. Currently, the traditional chemical anti-swelling agents are widely used, but most of them are only effective in the short term and are not environmentally friendly. Here, we report the use of Fe(III) reducing microorganisms (FeRM) as a novel green anti-swelling agent to enhance oil recovery from low-permeability reservoirs. The results showed that FeRM (Proteus hauserifective) inhibited/reduced the hydro-swelling of smectite clay minerals through a three-step biochemical mineralization reaction process. The structural Fe(III) reduction in minerals by FeRM can be an important driving force for illitization. The maximum inhibition efficiency (36.6%) and shrinkage efficiency (69.3%) were achieved at 35 °C and 0.1 Mpa. Furthermore, core displacement tests showed that FeRM reduced the waterflooding injection pressure by 61.1%, increased the core permeability by 49.6%, and increased the oil recovery by 8.1%. Finally, the mechanism of FeRM-enhanced oil recovery was revealed. This study demonstrates that using FeRM to inhibit/reduce the hydro-swelling of clay minerals holds great potential to enhance the oil recovery from low-permeability reservoirs.

The Impact of the Double Cross-Phase Diffusion Mechanism on Oil Recovery during CO2 Injection into Fractured Rocks: A Simulation Study.

In this research, a new diffusion mechanism called “double cross-phase diffusion” is introduced and applied to simulate the non-equilibrium gas injection process into fractured rocks. This new mechanism represents additional multicomponent gas diffusion into the crude oil through the water phase, existing in porous media as initial water saturation. Therefore, a lab-scale simulator, by implementing the generalized Fick’s law of multicomponent diffusion, is developed and used for predicting the experimental data of oil recovery during CO2 injection in chalk fractured rocks in the presence of initial water saturation. The results revealed a significant difference in the oil recovery predicted by the model when the double cross-phase diffusion mechanism is considered. The transient behavior of produced oil composition, predicted by the simulation model, is matched well with the experimental data. The portion of active oil recovery mechanisms in the system has been evaluated for the first time and it was observed that the molecular diffusion mechanism induced 75.4% of the total oil transfer rate in the initial time oil recovery, in which 23.1% of this value was supplied by the double cross-phase diffusion mechanism, which is an interesting finding. Results of sensitivity analysis showed that by increasing the initial water saturation, the impact of the double cross-phase diffusion mechanism on oil recovery increases. In contrast, the transferred rate by the diffusion mechanism decreases from 85.4% to 60.8% when matrix permeability increases from 0.1 to 10 mD. The results of this work illustrate that the double cross-phase diffusion mechanism introduced in this study plays a significant role in the simulation results since the water is responsible for accelerating the diffusivity of CO2 into the crude oil and, in consequence, increasing the oil recovery.

Enhanced Oil Recovery Mechanism and Technical Boundary of Gel Foam Profile Control System for Heterogeneous Reservoirs in Changqing.

The gel plugging and flooding system has a long history of being researched and applied, but the Changqing reservoir geological characteristics are complex, and the synergistic performance of the composite gel foam plugging system is not fully understood, resulting in poor field application. Additionally, the technique boundary chart of the heterogeneous reservoir plugging system has hardly appeared. In this work, reservoir models of porous, fracture, and pore-fracture were constructed, a composite gel foam plugging system was developed, and its static injection and dynamic profile control and oil displacement performance were evaluated. Finally, combined with the experimental studies, a technical boundary chart of plugging systems for heterogeneous reservoirs is proposed. The research results show that the adsorption effect of microspheres (WQ-100) on the surface of elastic gel particles-1 (PEG-1) is more potent than that of pre-crosslinked particle gel (PPG) and the deposition is mainly on the surface of PPG. The adsorption effect of PEG-1 on the surface of PPG is not apparent, primarily manifested as deposition stacking. The gel was synthesized with 0.2% hydrolyzed polyacrylamide (HPAM) + 0.2% organic chromium cross-linking agent, and the strength of enhanced gel with WQ-100 was higher than that of PEG-1 and PPG. The comprehensive value of WQ-100 reinforced foam is greater than that of PEG-1, and PPG reinforced foam, and the enhanced foam with gel has a thick liquid film and poor foaming effect. For the heterogeneous porous reservoir with the permeability of 5/100 mD, the enhanced foam with WQ-100 shows better performance in plugging control and flooding, and the recovery factor increases by 28.05%. The improved foam with gel enhances the fluid flow diversion ability and the recovery factor of fractured reservoirs with fracture widths of 50 μm and 180 μm increases by 29.41% and 24.39%, respectively. For pore-fractured reservoirs with a permeability of 52/167 mD, the PEG + WQ-100 microsphere and enhanced foam with WQ-100 systems show better plugging and recovering performance, and the recovery factor increases are 20.52% and 17.08%, 24.44%, and 21.43%, respectively. The smaller the particle size of the prefabricated gel, the more uniform the adsorption on the foam liquid film and the stronger the stability of the foam system. The plugging performance of the composite gel system is stronger than that of the enhanced gel with foam, but the oil displacement performance of the gel-enhanced foam is better than that of the composite gel system due to the “plug-flooding-integrated” feature of the foam. Combined with the plugging and flooding performance of each plugging system, a technique boundary chart for the plugging system was established for the coexisting porous, fracture, and pore-fracture heterogeneous reservoirs in Changqing Oilfield.

Impact of rock morphology on the dominating enhanced oil recovery mechanisms by low salinity water flooding in carbonate rocks

Because of the complex nature of carbonate reservoirs, the required conditions for effective Low Salinity Water Flooding (LSWF) in these reservoirs need further and in depth investigation. In the present study, three calcite cores, i.e. Cal-1, Cal-2, and IL, with the same chemical composition are subjected to tertiary low salinity water flooding (LSWF), while the crude oil and composition of flooding brine kept the same. The experimental results show significant difference in the amount of enhanced oil recovery, as IL had the most additional oil recovery (20.8 % of IOIP), followed by Cal-2 (10.5 % of IOIP) and Cal-1 (3.9 % of IOIP). The results of contact angle, zeta potential, and effluent pH showed that the same geochemical reaction occurred for all three cores. High-resolution FE-SEM images demonstrate that the only difference in these three cases is the rock morphology. Dynamic contact angle measurements indicate that wettability alteration depends on the dominating mechanisms (diffusion/advection) that controls the replacement of high salinity thin water film (which is flanked by crude oil and rock) with the surrounding low salinity brine. The wide pore size distribution of Cal-1 compared to Cal-2 and IL results in a more diffusion-controlled oil recovery mechanisms, which is confirmed by the late-time and the gradual response of Cal-1 to tertiary LSWF. Also, a direct relation between effluent pH and the tertiary oil recovery of Cal-1 highlighted the role of the thickness of the water film in the diffusion rate. More homogenous Cal-2 has a high early oil recovery; however, the angular shape of its particles leads to a partial diffusion-controlled regime that causes a late-time recovery. Finally, the uniform and the rounded particles of IL drift the impact of diffusion away. The results of the present is study emphasizes the role of heterogeneity and angularity on the performance of tertiary LSWF.

Molecular dynamics simulations of oil recovery from dolomite slit nanopores enhanced by CO2 and N2 injection

Shale oil reservoirs are dominated by micro-and nanopores, which greatly impede the oil recovery rates. CO2 and N2 injection have proven to be highly effective approaches to enhance oil recovery from low-permeability shale reservoirs, and also represent great potential for CO2 sequestration. Therefore, a better understanding of the mechanism of shale oil recovery enhanced by CO2 and N2 is of great importance to achieve maximum shale oil productivity. In this paper, the adsorption behavior of shale oil and the mechanism of enhancing shale oil recovery by CO2 and N2 flooding in dolomite slit pores are investigated by performing nonequilibrium molecular dynamics simulations. Considering the shale oil adsorption behavior, mass density distribution is analyzed and the results indicate that a symmetric density distribution of the oil regarding the center in the slit pore along the x-axis can be obtained. The maximum density of the adsorbed layer nearest to the slit wall is 1.310 g/cm3 for C8H18 , which is about 2.0 times of that for bulk oil density in the middle area of slit pore. The interaction energy and radial distribution functions (between oil and CO2 , and between oil and N2 ) are calculated to display the displacement behavior of CO2 and N2 flooding. It is found that CO2 and N2 play different roles: CO2 has strong solubility, diffusivity and a higher interaction energy with dolomite wall, and the oil displacement efficiency of CO2 reaches 100% after 1 ns of flooding; however, during N2 flooding, the oil displacement efficiency is 87.3% after 4 ns of flooding due to the lower interaction energy between N2 and dolomite and that between N2 and oil. Cited as: Guo, H., Wang, Z., Wang, B., Zhang, Y., Meng, H., Sui, H. Molecular dynamics simulations of oil recovery from dolomite slit nanopores enhanced by CO2 and N2 injection. Advances in Geo-Energy Research, 2022, 6(4): 306-313. https://doi.org/10.46690/ager.2022.04.05

Adsorption of Polar Species at Crude Oil-Water Interfaces: the Chemoelastic Behavior.

We investigate the formation and properties of crude oil/water interfacial films. The time evolution of interfacial tension suggests the presence of short and long timescale processes reflecting the competition between different populations of surface-active molecules. We measure both the time-dependent shear and extensional interfacial rheology moduli. Late-time interface rheology is dominated by elasticity, which results in visible wrinkles on the crude oil drop surface upon interface disturbance. We also find that the chemical composition of the interfacial films is affected by the composition of the aqueous phase that it has contacted. For example, sulfate ions promote films enriched with carboxylic groups and condensed aromatics. Finally, we perform solution exchange experiments and monitor the late-time film composition upon the exchange. We detect the film composition change upon replacing chloride solutions with sulfate-enriched ones. To the best of our knowledge, we are the first to report the composition alteration of aged crude oil films. This finding might foreshadow an essential crude oil recovery mechanism.