Microscopic Displacement Efficiency Research Articles

Monte Carlo Simulation of the CO2 Flooding Efficiency at a Core Scale for Different Oil Compositions

The evaluation of water-alternating-gas (WAG) efficiency and profitability is complicated by a large number of reservoir, operating, and economic parameters and constraints. This study aims at understanding the influence of the oil composition on different WAG injections. By employing compositional reservoir modeling and the Monte Carlo method to characterize the diversity of oils occurring in nature, we simulate the microscopic displacement efficiency of CO2 flooding when it is applied to both light- and heavy-oil reservoirs. We find that the economic performance of WAG in both miscible and immiscible scenarios is mainly characterized by the dimensionless injection rate and the oil density at surface conditions. Neither the bubble point pressure nor the minimum miscibility pressure can be used for the quantification of the optimal WAG parameters. We present our estimates of the best strategies for the miscible and immiscible injections and verify some of our previous results for randomly sampled oils. In particular, we demonstrate that CO2 flooding is better to apply at higher-dimensionless injection rates. We show that the injection of CO2 organized at a light-oil reservoir results in a higher profitability of WAG, although this comes at the cost of lower carbon storage efficiency.

Design of Janus Nanoparticles for Mobility Control in Heterogeneous Reservoirs.

Unfavorable mobility ratios in heterogeneous reservoirs have resulted in progressively poor waterflood sweep efficiency and diminishing production. In order to address this issue, our study has developed amphiphilic-structured nanoparticles aimed at enhancing the microscopic displacement capability and oil displacement efficiency. First, the transport process of Janus nanoparticles in porous media was investigated. During the water flooding, Janus nanoparticle injection, and subsequent water flooding stages, the injection pressure increased in a "stepped" pattern, reaching 0.023, 0.029, and 0.038 MPa, respectively. Second, emulsification effects and emulsion viscosity experiments demonstrated that the amphiphilic structure improved the interaction at the oil-water interface, reducing the seepage resistance of the oil phase through emulsification. In porous media, Janus nanoparticles transported with water exhibit 'self-seeking oil' behavior and interact with the oil phase, reducing the viscosity of the oil phase from 19 to 5 mPa·s at 80 °C. Finally, the core model displacement experiment verified the characteristics of Janus nanoparticles in improving the oil-water mobility ratio. Compared with the water flooding stage, the recovery percent increased by 20.8%, of which 13.7% was attributed to the subsequent water flooding stage. Utilizing the asymmetry of the Janus particle structure can provide an effective path to enhanced oil recovery in inhomogeneous reservoirs.

Study on Numerical Simulation of Gas–Water Two-Phase Micro-Seepage Considering Fluid–Solid Coupling in the Cleats of Coal Rocks

The increasing demand for natural gas energy will promote unconventional natural gas, such as coal seam gas and shale gas, to play a key role in future energy development. The mechanical properties of coal seams are weaker compared with conventional natural gas reservoirs. The fluid–solid coupling phenomenon exists widely at the pore scale and macro scale of coal seams, and runs through the whole process of coalbed gas exploitation. The objective of this study is to establish a microscale gas–water flow model for coalbed methane considering fluid structure coupling. Frist, this study used scanning electron microscopy (SEM) to obtain microscopic pore images of coal rocks. Then, we constructed a numerical model to simulate the movement of coalbed methane and water within the scale of coal cleats based on the Navier–Stokes equation, phase field method, and solid mechanics theory. Finally, we analyzed the effects of injection pressure and wettability on the microscopic two-phase seepage characteristics and displacement efficiency of coal. Our research shows that when the injection pressure is increased from 60 kPa to 120 kPa, the displacement completion time is shortened from 1.3 × 10−4 s to 7 × 10−5 s, and the time is doubled, resulting in a final gas saturation of 98%. The contact angle increases from 45° to 120°, and the final gas saturation increases from 0.871 to 0.992, an increase of 12.2%.

A comprehensive review of viscoelastic polymer flooding in sandstone and carbonate rocks

Polymer flooding is a proven chemical Enhanced Oil Recovery (cEOR) method that boosts oil production beyond waterflooding. Thorough theoretical and practical knowledge has been obtained for this technique through numerous experimental, simulation, and field works. According to the conventional belief, this technique improves macroscopic sweep efficiency due to high polymer viscosity by producing moveable oil that remains unswept after secondary recovery. However, recent studies show that in addition to viscosity, polymer viscoelasticity can be effectively utilized to increase oil recovery by mobilizing residual oil and improving microscopic displacement efficiency in addition to macroscopic sweep efficiency. The polymer flooding is frequently implemented in sandstones with limited application in carbonates. This limitation is associated with extreme reservoir conditions, such as high concentrations of monovalent and divalent ions in the formation brine and ultimate reservoir temperatures. Other complications include the high heterogeneity of tight carbonates and their mixed-to-oil wettability. To overcome the challenges related to severe reservoir conditions, novel polymers have been introduced. These new polymers have unique monomers protecting them from chemical and thermal degradations. Monomers, such as NVP (N-vinylpyrrolidone) and ATBS (2-acrylamido-2-methylpropane sulfonic acid), enhance the chemical resistance of polymers against hydrolysis, mitigating the risk of viscosity reduction or precipitation in challenging reservoir conditions. However, the viscoelasticity of these novel polymers and their corresponding impact on microscopic displacement efficiency are not well established and require further investigation in this area. In this study, we comprehensively review recent works on viscoelastic polymer flow under various reservoir conditions, including carbonates and sandstones. In addition, the paper defines various mechanisms underlying incremental oil recovery by viscoelastic polymers and extensively describes the means of controlling and improving their viscoelasticity. Furthermore, the polymer screening studies for harsh reservoir conditions are also included. Finally, the impact of viscoelastic synthetic polymers on oil mobilization, the difficulties faced during this cEOR process, and the list of field applications in carbonates and sandstones can also be found in our work. This paper may serve as a guide for commencing or performing laboratory- and field-scale projects related to viscoelastic polymer flooding.

Experimental Study on Multi-Dimensional Visualization Simulation of Gas and Gel Foam Flooding in Fractured-Vuggy Reservoirs.

Gas flooding and foam flooding are potential technologies for tertiary oil recovery in fractured-vuggy reservoirs. The development and mechanism research of fractured-vuggy reservoirs is difficult due to the complex structures and the strong heterogeneity of fractured-vuggy reservoirs. Visualization simulation is one of the effective methods to study the flow behavior of fluid in fractured-vuggy reservoirs. In this study, an upscaling method of visualization simulation from one dimension (1D) to three dimensions (3D) was established, and the physical models of fractured-vuggy reservoirs were designed and fabricated. Water flooding, gas flooding, and gel foam flooding were carried out in the models. The experimental results showed that gas flooding has a single flow channel and water flooding has multiple flow channels in fractures and vugs. Gel foam with an excellent capability of mobility control and a high microscopic displacement efficiency swept in all directions at a uniform velocity. The EOR mechanisms of gel foam in fractured-vuggy reservoirs were mainly as follows: reducing interfacial tension, increasing mobility ratio, selectively plugging high permeability channels, and discontinuous flow. In the displacement process of fractured-vuggy reservoirs, water should be injected from the well at the bottom of the reservoir, and gas should be injected from the well located in the vug at the high part of the reservoir. Gel foam with strong stability and high viscosity should be selected and injected in most kinds of injection wells in fractured-vuggy reservoirs. This study provides a complete method of visualization simulation for the study of flow behavior in fractured-vuggy reservoirs and provides theoretical support for the application of gas flooding and gel foam flooding in fractured-vuggy reservoirs.

Microscopic gas displacement efficiency of enhanced gas recovery in carbonate gas reservoirs with edge and bottom water

Carbonate gas reservoirs with edge and bottom water contain abundant reserves, making them key production targets in the Tarim Basin, Sichuan Basin, Ordos Basin, and other petroleum provinces. Water invasion may occur in the middle and late development stages of such reservoirs, leading to reduction of gas displacement efficiency and gas recovery. In this paper, a pore-scale water-gas immiscible flow model is established by coupling the fluid flow equation and the gas-water contact (GWC) tracking equation. The process of gas displacement with water is simulated in the heterogeneous porous media generated by the quartet structure generation set (QSGS). Finally, the mechanisms of remaining gas distribution and formation are analyzed, and the variation mechanism of microscopic gas displacement efficiency is discussed. The results are obtained in three aspects. First, the remaining gas is distributed at the blind end, in the pore-throat and as clusters, with their proportions and scales jointly controlled by microscopic pore structures, wettability and capillary number. The remaining gas can be further produced by changing the production pressure differential to disturb the original pressure system and gas expansion, so as to improve the microscopic gas displacement efficiency. Second, the microscopic gas displacement efficiency is closely related to the gas flow process. Formation or expansion of each water flow path may cause rapid increase of water cut and slows down the increase of gas displacement efficiency. Third, the microscopic pore structure and wettability are the inherent features of the gas reservoir, so the capillary number can be optimized to change the mode of GWC advancement, and then to effectively improve the microscopic gas displacement efficiency. It is concluded that for real gas wells, the evolution of mechanical mechanisms of GWC advancement should be revealed depending upon the microscopic pore structure and wettability of the reservoir, and then the optimal capillary number can be determined. Furthermore, clarifying the pore-scale water-gas flow characteristics and physical mechanism of microscopic gas displacement provides guidance for the planning of enhanced gas recovery.

A laboratory investigation of CO2 influence on solvent-assisted polymer flooding for improving viscous oil recovery on Alaska North Slope

In this study, the CO2 influence on enhancing Alaska North Slope (ANS) viscous oil recovery for polymer flooding with assistance of solvents is investigated. Seven coreflooding tests were conducted at reservoir conditions to evaluate ANS viscous oil recovery performance of five solvent-assisted EOR methods including LHS (light hydrocarbon solvent)-alternating-LSW (low salinity water) flooding, CO2-enriched LHS-alternating-LSW flooding, LHS-alternating-LSP (low salinity polymer) flooding, CO2-enriched LHS-alternating-LSP flooding, and CO2-enriched LHS-LSW-LSP flooding. Besides, the CO2 influence on the performance of solvent-assisted EOR methods is investigated. In addition, Constant Composition Expansion (CCE) tests were performed at reservoir temperatue of 85 °F to explore mechanisms of oil recovery improvement with solvent injection in EOR methods of this study. Moreover, water ion analyses of DI-water/natural-sand and DI-water/natural-sand/CO2 systems were carried out to discover the complex reaction between CO2, sand, and LSP solution for better understanding underlying mechanisms of solvent-assisted EOR methods. Coreflooding experiment results demonstrate that five proposed EOR methods all present remarkable production performance with recovery factor ranging from 79.73% to 92.23%. The main EOR mechanisms can be attributed to oil swelling and viscosity reduction effects resulting in the enhancement of microscopic displacement efficiency during solvent flooding and the improvement of macroscopic sweep efficiency of subsequent LSW/LSP flooding resulting from obtaining better mobility control. Considering the recovery factor from the 1st solvent flooding, no obvious improvement was observed with solvent containing CO2. However, higher oil recovery improvement was obtained from the subsequent LSW/LSP flooding of tests using solvent with CO2 than that without CO2, mainly resulting from better mobility control due to the greater viscosity reduction effect by CO2-enriched LHS. Nevertheless, a severe blockage occurred at the production end in the CO2-enriched LHS-alternating-LSP flooding test, which was likely due to the polymer precipitation. CCE test results present that more solvent could be dissolved into the ANS viscous oil by increasing the pressure of the system, which causes greater oil swelling and viscosity reduction effects. The saturation pressure was affected little by adding CO2 in LHS, while the presence of CO2 had a negative impact on oil swelling effect but a positive influence on oil viscosity reduction effect. In addition, water ion analyses results show that, after introducing CO2 to the DI-water/natural-sand system, a great amount of multivalent cations were generated probably due to the dissolution of minerals in the natural sand, which may explain the polymer precipitation. Therefore, the blockage issue at the production end could be solved by injecting LSW as a spacer between CO2-enriched LHS flooding and LSP flooding to reduce the concentration of generated cations.

Impact of clay mineralogy on the petrophysical properties of tight sandstones

A full petrographic and petrophysical characterization of tight sandstones has been conducted as part of ongoing study of Carbon Dioxide Enhanced Oil and Gas Recovery (CO2-EOR/EGR) and CO2sequestration. The main purpose of this study is to give novel perception into the interplay of the rock characteristics and fluid flow in tight formations, which are candidates for EOR/EGR processes (macroscopic sweep vs. microscopic displacement efficiency). To achieve this, several experimental techniques, including routine core analysis, X-ray diffraction (XRD), X-ray fluorescence (XRF), thin sections petrography, Scanning Electron Microscopy (SEM) and capillarity/pore size distributions by using Mercury Injection Capillary Pressure (MICP), Nuclear Magnetic Resonance (NMR), and Micro-Computed Tomography (Micro-CT), were conducted. Three tight sandstone rock samples (Bandera, Kentucky, and Scioto) were used in this work and particular attention was paid to the impact of clay content on rock's pore system and other petrophysical characteristics and hence fluids flow during production process.Results indicate that the presence of fibrous illite clay acting as pore bridging in Bandera and Kentucky samples have blocked the overall micro-pore system causing a significant reduction in the micro-pore throat system to 36% in Bandera sand and 50.9% in Kentucky sample. On the other hand, absence of fibrous illite and the presence of illite platelets in the Scioto sandstone led to a clear preservation of the sample's micro-pore throat attributing to a total of 59.1% of the total pore throat system.A new dimensionless number (dimensionless micro-pore throat modality) was established, defined as the ratio of micro-to macro-pore sizes. This shows that Scioto has the highest value of 1.44 implying that both macro- and micro-pore systems contribute to flow. Therefore, the mitigation of oil bypass from smaller pores should be a key criterion in selecting the proper recovery methods. Results show the effect of clay mineralogy on pore system considering a part of the physical and spatial properties the pore/grain framework of the tight sandstones.

A Comparison of The Performances of Conventional and Low Salinity Water Alternating Gas Injection for Displacement of Oil

This study focuses on identifying the crucial physical and chemical factors, such as gravity, initial oil phase, injection depth, vertical to horizontal permeability contrast, and salinity of injected water for improving oil recovery factor during water alternating gas (WAG) injection. The conventional WAG injection attracts interest from oil and gas industry and hence, has become one of the most reliable enhanced oil recoveries (EOR) techniques. During WAG injection, due to gravity effect, water subsides below oil layer while gas overflow above the oil layer. In fact, water sweeps bottom zones of the reservoir and gas sweep the attic oil at the upper zones of the reservoir. Although the conventional WAG does improve oil recovery factor, there still remains a substantial amount of oil in reservoir pores due to rock-fluid and fluid-fluid interfacial tensions (IFT) that leads to the capillary forces impeding the microscopic displacement efficiency. The low salinity waterflooding (LSWF) was therefore proposed to break the IFT between rock clay and fluids, and further increase oil recovery factor. Recent researches revealed that LSWF alters oil-wet reservoir to water-wet behavior. This wettability alteration is believed to be the main mechanism of LSWF to improve oil recovery. Other mechanisms of LSWF include multi-ion exchange (MIE) between rock clay minerals and injected salt water, pH increase, and fines migration. In this study, the CMG GEM simulator was used to simulate conventional WAG injection and LSWAG injection. The simulation results showed that there is an increase of oil recovery factor of about 6% for WAG injection with low salinity water of 1027ppm to sea water of 51,346 ppm. The simulations have also showed that the physical factors namely, gravity, initial oil phase, injection depth, vertical to horizontal permeability contrast are influential on the displacement efficiency and must be studied thoroughly in the design of LSWAG operations besides the salinity and chemical composition of the injection water.

Visualization of adaptive polymer flow and displacement in medium-permeable 3D core-on-a-chip

Polymer flooding has been witnessed an effective technology for enhancing oil recovery from medium-to low-permeability reservoirs; however, direct visualization of polymer solution flow in such reservoir condition is still lacking. In this work, a three-dimensional (3D) core-on-a-chip device with a permeability of around 200 mD was prepared and employed to visualize the pore-scale flow and displacement of a self-adaptive polymer (SAP, 8.7 × 106 g·mol−1)−whose microscopic association structure and macroscopic viscosity can reversibly change in response to shear action−versus partially hydrolyzed polyacrylamide (HPAM), by recording their flow curves, monitoring dynamic transportation process via particle imaging velocimetry, and building 3D structure of remaining oil. The results show that, in single-phase flow, all polymer solutions exhibit flow thinning and then thickening regions as flow rate increases, but the transition between two regimes occurs at a small Weissenberg number (10−3−10−1) in this medium-permeable condition. In contrast to HPAM-1 with close weight-average molecular weight (Mw), the adaptive character not only extends SAP's shear-govern region, allowing SAP to propagate piece by piece and achieve higher accessible pore volume, but it also enhances the elastic resistibility of polymer in the extension-dominated regime, increasing the microscopic displacement efficiency. These two effects result in 1.5–3 times more oil recovery factor for SAP than for HPAM-1. Regarding ultra-high-Mw HPAM-2 (25 × 106 g·mol−1), plugging and chain degradation do occur, thus producing lower oil recovery than SAP. This work provides a direct approach for in-situ assessment of polymer-based displacing system under a more authentic condition of practical reservoirs.

Combination of nano-bentonite stabilized foam and ultra-low IFT surfactant additives assisted steam injection to enhanced heavy oil recovery

This study presents an experimental investigation of combination of nano-bentonite stabilized foam and surfactant additives with ultra-low interfacial tension (IFT) to enhance thermal recovery of heavy oil by steam injection. The foam stability results showed that the nano-bentonite can form a three-dimensional network structure to increase the viscosity and thickness of the liquid film, and thus significantly improving the foam stability at high temperature. The foam resistance factor determination demonstrated that the nano-bentonite stabilized foam has good selective plugging ability of reducing the mobility of steam to inhibit the steam channeling. The surfactant additives prepared by the composite system of sodium dodecyl benzene sulfonate and sodium nonylphenol polyoxyethylene ether sulfonate can achieve synergistic effect of high interfacial activity and high-temperature resistance, which can reduce the oil–water interfacial tension to ultra-low level at high temperature. The heterogeneous sandpack flooding results indicated that the nano-bentonite stabilized foam can effectively block the steam channels to improve the sweep efficiency of steam injection and the ultra-low IFT surfactant additives can greatly increase the microscopic oil displacement efficiency. And thus the combination of nano-bentonite stabilized foam and the ultra-low IFT surfactant additives can significantly enhance thermal oil recovery of steam injection in heavy oil reservoirs.

The role of injection fluid elasticity in microscopic displacement efficiency of residual non-wetting phase: An in-situ experimental investigation

Polymer flooding has been employed extensively over the years as a mature enhance oil recovery (EOR) technique to improve volumetric displacement (sweep) efficiency in oil reservoirs. In the last few years, groundbreaking laboratory and pilot tests have demonstrated that the use of polymers with viscoelastic properties may potentially enhance the efficacy of polymer flooding and result in improvements in both volumetric (macroscopic) and microscopic (pore-scale) displacement efficiencies. The transport and pore-level displacement mechanisms responsible for such microscopic improvements, however, have been poorly understood. This study was thus designed to improve the current understanding of the displacement of waterflood residual oil with viscoelastic polymers in natural porous media. We performed a series of micro-scale two-phase core-flooding experiments on miniature water-wet Berea sandstone samples at elevated pressure. During the flow tests, heavy oil was displaced with two Newtonian fluids (brine and Glycerin) and a viscoelastic polymer to investigate the impact of injection fluid elasticity on mobilization of capillary-trapped oil. We purposely selected a viscoelastic polymer that had a similar viscosity, but significantly different elastic characteristics compared to those of Glycerin. The rheological behavior of the fluids was characterized using an oscillation rheometer. The flow experiments were conducted using a miniature core-flooding setup coupled with a high-resolution micro-computed tomography (µ -CT) scanner enabling us to directly visualize morphologies of oil globules in the pore space. The core sample initially saturated with brine was subjected to primary oil drainage to establish initial water saturation (Swi) and then a waterflood to establish remaining oil saturation. This process was then followed by (i) a Glycerin flood and (ii) a viscoelastic polymer flood, all under low pressure gradients (i.e., capillary numbers of approximately 1E-5). The injection of Glycerin, after the waterflood, reduced the remaining oil saturation from 45.8 to 38% due to a favorable mobility ratio, which was believed to be the reason for the improvement in volumetric sweep efficiency. Furthermore, in-situ saturation data revealed that the use of the viscoelastic polymer resulted in an additional 12% oil recovery. Since both the viscoelastic polymer and Glycerin had similar mobility ratios, their volumetric sweep efficiencies were believed to be comparable, and hence the observed incremental oil recovery was attributed to additional pore-scale oil mobilization caused by the injection of the viscoelastic polymer. This mobilization mechanism is triggered by elastic forces and is not due to dynamic effects generated usually under high capillary numbers. Moreover, investigation of pore-scale fluid occupancy maps provided clear evidence of fragmentation and mobilization of trapped oil clusters as the mechanisms responsible for the observed enhancement in recovery. The fragmentation and mobilization of the oil globules were related to high elastic properties of the viscoelastic polymer used. Finally, we present a new correlation linking the reduction in residual oil saturation to the elasticity of the injected fluid.

A Molecular Dynamics Study on Low-Pressure Carbon Dioxide in the Water/Oil Interface for Enhanced Oil Recovery

SummaryThe microscopic displacement efficiency of supercritical carbon dioxide (CO2)-based enhanced oil recovery (EOR) depends critically on the phase behavior of CO2 and residual oil. Traditionally, we assume that the main drive mechanisms of supercritical CO2 EOR are attributed to oil swelling and reduced oil viscosity, and research focuses on how the supercritical CO2 interacts with remaining oil under the reservoir conditions. However, our recent study finds that once the CO2 is introduced into the reservoir, CO2 partitions into the aqueous and oil phases, reducing the interfacial tension (IFT) between the oil and water. This is particularly important when CO2 is generated through a series of chemical reactions for in-situ CO2 EOR. In this paper, we used molecular dynamics (MD) simulations to study the interfacial properties between water and oil with different mole fractions of CO2 in pressures below the minimum miscibility pressure. Simulation results show that with the increase in CO2 mole fraction, rather than evenly distributed in phases, CO2 molecules are prone to concentrate in the water/oil interface region, which decreases IFT between the aqueous phase and oil. Furthermore, the effect of CO2 orientation on the water/oil IFT reduction was observed. The change of CO2 concentration affects CO2 orientation near the interface, which in return dominates the IFT change.

Systematic Investigation of Corner Flow Impact in Forced Imbibition

AbstractImbibition in porous media plays a crucial role in many engineering and industrial processes, such as enhanced oil recovery and groundwater contamination remediation. Due to the instabilities at the two‐phase interface, the defending fluids in these processes are often not effectively displaced. Therefore, it is of great significance to study imbibition in natural rocks at the pore scale, especially under the completely wetting and viscously unfavorable conditions due to their contribution to interfacial instability. In this work, numerical simulations of forced imbibition in three natural rocks are carried out at four different injection rates based on the color lattice Boltzmann model. The interfacial evolution and in situ fluid distribution are analyzed from several perspectives. Results show that as the capillary number, expressed in logarithms, varies from −2.5 to −4.0, the flow characteristics of the invading fluid change from leading films on the solid surface of large pores to corner flow along the pore corners of pores with different sizes, the dominant pore filling event changes from ganglion dynamics to snap‐off trapping, and the morphology of the displacement front changes from viscous fingering to a rough but uniform characteristic. These changes at the two‐phase interface determine the fluid distribution and fluid structure, controlling the microscopic displacement efficiency, interface area and fluid connectivity. This work systematically investigates for imbibition of the local and global flow physics and dynamics, the mechanical nature and the resulting effects of interfacial instability under unfavorable conditions, which help to deepen our understanding of the microscopic mechanism of forced imbibition.

Numerical approach for enhanced oil recovery with polymer flooding using CMG-STARS program

The polymer recovery efficiency of cationic polyacrylamide (PAM) has been evaluated for use as polymer flooding in the Basra oil reservoir Initially, rheological, physical and petro physical were studied. Additionally, the polymer flooding core flooding experiment has been tested to see how well PAM solutions can be recovered. The comparative study between experimental and numerical study for PAM solution has been accomplished in terms of rheological properties , relative permeability curve and oil production. The results showed that PAM solution exhibit shear thinning effect which can efficiently improve the macroscopic sweep efficiency as well as microscopic displacement efficiency, and viscosity increase with high concentration. The overall recovery efficiency of 94.61 % from sandstone was determined for 2500ppm PAM flooding. By contrast, brine water flooding was found to be 47.76%, showing that it was less effective than PAM solution. Cost analysis is another factor that affects a project's success. To support the experimental results, a simulation by the Computer Modelling Group (CMG) study has also been conducted.

Literature Review of Nanotechnology in the Enhanced Oil Recovery.

In recent studies, there has been an increasing focus on Nanoparticles Enhanced Oil Recovery (NPEOR). NPEOR is a method that was initially developed to improve microscopic and macroscopic displacement efficiency. In some recent applications NP have been assisted the conventional EOR methods such as a polymer, surfactant, and Co2 flooding, with the purpose of increasing the oil recovery. In this literature, the abilities to use NP in EOR are investigated. The function of different types of NP, different types of Dispersing agents, availability of nanomaterials in the lab, the effect of nanoparticles to change the properties, future challenges and concerns about the NP, are reviewed. However, the stability of suspensions of NP is still the most barrier to use NP in EOR. Upcoming studies are necessary to focus on the outcome of the appropriate techniques of NP to improve their stability under the worst conditions of reservoirs and investigate new types of nanoparticles.

An Extended Unified Viscoelastic Model for Predicting Polymer Apparent Viscosity at Different Shear Rates

Summary Polymer flooding is one of the most commonly used chemical enhanced oil recovery (EOR) methods. Conventionally, this technique was believed to improve macroscopic sweep efficiency by sweeping only bypassed oil. Nevertheless, recently it has been found that polymers exhibiting viscoelastic behavior in the porous medium can also improve microscopic displacement efficiency resulting in higher additional oil recovery. Therefore, an accurate prediction of the complex rheological response of polymers in porous media is crucial to obtain a proper estimation of incremental oil to polymer flooding. In this paper, a novel viscoelastic model is proposed to comprehensively analyze the polymer rheological behavior in porous media. This proposed model was developed and validated using 30 coreflooding tests obtained from the literature and further verified against a few existing viscoelastic models. The proposed viscoelastic model is considered an extension of the unified apparent viscosity model provided in the literature and is termed as extended unified viscoelastic model (E-UVM). The main advantage of the proposed model is its ability to capture the polymer mechanical degradation at ultimate shear rates primarily observed near wellbores. Moreover, the fitting parameters used in the model were correlated to rock and polymer properties using machine learning technique, significantly reducing the need for time-consuming coreflooding tests for future polymer screening works. Furthermore, the E-UVM was implemented in MATLAB Reservoir Simulation Toolbox (MRST) and verified against the original shear model existing in the simulator. It is worth mentioning that the irreversible viscosity drop for mechanical degradation regime was captured during implementing our model in the simulator. It was found that implementing the E-UVM in MRST for polymer non-Newtonian behavior might be more practical than the original method. In addition, the comparison between various viscosity models proposed earlier and E-UVM in the reservoir simulator showed that the latter model could yield more reliable oil recovery predictions as the apparent viscosity is modeled properly in the mechanical degradation regime, unlike UVM or Carreau models. This study presents a novel viscoelastic model that is more comprehensive and representative as opposed to other models in the literature. Furthermore, the need to conduct an extensive coreflooding experiment can be reduced by virtue of developed correlations that may be used to estimate model fitting parameters accounting for shear-thickening and mechanical degradation.

Quantitative study of CO2 huff-n-puff enhanced oil recovery in tight formation using online NMR technology

Recent evidence suggests that CO2 huff-n-puff can significantly enhance the oil recovery in tight/shale oil reservoirs after primary depletion. However, the key driving forces of CO2 huff-n-puff for oil displacement, especially their effect on the enhanced oil recovery are still unclear. In addition, the CO2 effective distance in matrix, which is a critical parameter impacting the performance of huff-n-puff, has not been accurately studied. In this work, to identify and quantify the contribution of the related enhanced-oil-recovery (EOR) mechanisms, an online nuclear magnetic resonance (NMR) instrument was used to monitor the real-time migration of the matrix oil at all stages of the CO2 huff-n-puff process. The experiment results show that the dissolved CO2 drive controlled by molecular diffusion is the dominant mechanism during the huff-n-puff process. This EOR mechanism mainly works on the oil stored in the macropores, while the oil stored in the micropores is hardly mobilized. Base on the dynamic oil saturation distributions converted from the 1-D NMR profiles during huff-n-puff, we designed a novel 2-D evaluation system, which focuses on microscopic displacement efficiency and CO2 effective distance, to investigate the effect of the operation parameters on oil production. We found that simply increasing the injection pressure mainly improves the displacement efficiency but has less effect on the expansion of the sweep area, which limits the CO2 huff-n-puff EOR on the reservoir scale. Lengthening the soaking period extends the effective distance significantly but delays oil production. A cyclic huff-n-puff scheme with variable soaking time was proposed to maintain a high oil production rate and a large sweep area. Periodic optimization of the soaking time in the cyclic CO2 huff-n-puff process is needed for an optimal development plan.

Technology Focus: Heavy Oil (April 2022)

Heavy oils are characterized by high density, high viscosity, and high-heavy-fraction components. Because of high viscosity and lower API gravity than conventional crude oil, primary recovery of some of these crude oil types requires thermal stimulation of the reservoirs. Most of the technologies that deal with heavy oil need to address the mobility ratio or viscous forces before any flooding. In general, poor recovery is caused by physical reasons or geological reasons. Physical reasons can be categorized as capillary forces (existence of the interfacial tension between oil and water, wettability) or viscous forces (high mobility ratio between water and oil). Geological reasons are heterogeneities in reservoir rock and exist in all petroleum oil systems. In heavy oil reservoirs, enhanced oil recovery (EOR) intends to reduce the capillary forces and interfacial tension to improve microscopic displacement efficiency or improve the sweep efficiency (macroscopic) by reducing the mobility ratio between injected fluid and displaced fluid. Improving the mobility ratio is achieved by increasing the viscosity of water using polymers or by reducing the oil viscosity using heat. In general, all technologies need to address the capillary and viscous forces to improve oil recovery. Paper SPE 207361 discusses improving of the efficiency of the flood by near-wellbore conformance and improving the vertical sweep efficiency. The use of fiber-optic sensors, as addressed in paper SPE 199023, is intended to gather better data and avoid misinterpretation during falloff tests and injectivity tests. Traditionally, for heavy oil EOR simulation, because of the addition of chemical species or heat to the flow equations as well as the need for a finer grid resolution, the use of the full-field model in most cases was limited and the use of sector models and local grid refinement to obtain a reasonable accuracy has been applied in the industry. Sector modeling conditions must be satisfied to establish the reliability and the trade-off between accuracy (sector models) and computational expediency (full-field model). Recent development of hardware and software [graphics-processing-unit (GPU) -based simulators] has provided the industry with the tools to achieve a full-field model simulation in most fields by taking advantage of GPU solvers and using a fine-grid model to predict full-field performance. Recommended additional reading at OnePetro: www.onepetro.org. SPE 200279 - Field Application of the Autonomous Inflow Control Device for Optimized Heavy Oil Production in South Sultanate of Oman by Ali Al-Jumah, Petroleum Development Oman, et al. SPE 203012 - More Oil and Less Water: Autonomous Inflow Control Devices in New and Old Producers in Heavy Oil Fields From South of Oman by Ameera Al Harrasi, Petroleum Development Oman, et al. SPE 207684 - Game Changer in Dealing With Hard Scale Using a Slickline Torque Action Debris Breaker by Mahmoud Mohamed Koriesh, Dragon Oil, et al.

THE INFLUENCE OF ALCOHOL TYPE AND CONCENTRATION ON THE PHASE BEHAVIOR AND INTERFACIAL TENSION IN OIL-SURFACTANTCOSURFACTANT-BRINE MIXTURE SYSTEM

The number of mechanism is limited for reducing the entrapment of oil in the pore space of reservoir rock and for mobilizing that residual which remains entrapped, thereby improving the microscopic displacement efficiency of a petroleum recovery process. After primary recovery by flow powered by the energy stored in the compressed fluids of reservoir, and secondary recovery by injection-pump driven water flooding, residual oil is trapped by the capillary pressure developed by interfacial tension in curved menisci between oil and water in the pore space. Figure 1.1 illustrates the interplay of capillary and viscous forces in the water flooding process. Shown in the figure is water displacing oil. The important point is that residual oil is trapped in the pore space by interfacial tension. To improve micros- copic displacement efficiency is to reduce interfacial tension between oil and water. Surfactant is surface active agent chemical that has two types of properties; lypofob (like water) and hydrofob (like oil). The value of interfacial tension between oil and water is high, when surfactant is dissolved into water and contacts with oil, so that surfactant is not only soluble in the water, but also it is soluble in the oil. By addition of surfactant into the water and contact with oil can result in interfacial tension between oil and water from high (more less 20 - 30 dyne/cm) to lower interfacial tension (10-2 dyne/cm). To change the lower interfacial tension to the lowest interfacial tension conditions (10-4dyne/cm), cosurfactant in oil-surfactant-brine mixture is used. Alcohols are widely used in micellar surfactant systems for enhanced petroleum recovery and are variously called cosurfactant or cosolvent. In general, alcohols modify the physico- chemical properties in ways that are important to the design of surfactant-based process for improving petroleum recovery. This research is focused on alcohol effects on oil-surfactant-brine phase behavior and interfacial tension of oil-surfactant-brine system.