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Understanding the CO2 displacement mechanism in ultra-low-permeability reservoirs is essential for improving oil recovery. In this research, a series of displacement experiments were conducted on sandstone core samples from the Chang 6 reservoir in the Huaziping area using a multifunctional core displacement apparatus and Nuclear Magnetic Resonance (NMR) technology. The experiments were designed under conditions of constant pressure, variable pressure, and constant effective confining stress to simulate various reservoir scenarios. The results indicated that the distribution characteristics of the pore structure in the rock samples significantly influenced the CO2 displacement efficiency. Specifically, under identical conditions, rock cores with a higher macropore ratio exhibited a significantly enhanced recovery rate, reaching 68.21%, which represents a maximum increase of 31.97% compared to cores with a lower macropore ratio. Though fractures can facilitate CO2 flowing through pores, the confining pressure applied during displacement caused a partial closure of fractures, resulting in reduced rock permeability. Based on the oil-to-gas ratio and oil recovery in the outlet section of the fractured rock samples, the CO2 displacement process exhibited five stages of no gas, a small amount of gas, gas breakthrough, large gas channeling, and gas fluctuation. Although the displacement stage of different cores varies, the breakthrough stage consistently occurs within the range of 2 PV. These insights not only enhance our understanding of CO2 displacement mechanisms in low-permeability reservoirs but also provide actionable data to inform the development of more effective CO2-EOR strategies, significantly impacting industrial practices. [ABSTRACT FROM AUTHOR]

A large volume of water is bypassing oil and comes up without being able to push it out from the reservoir after organic material adsorption. This work investigates hydrophobicity effect on rock wettability, oil recovery, and relative permeability. The μXRF was used to characterize sand cores, and a contact angle goniometer to determine fluids contact angle. Oil recovery was evaluated by measuring the incremental oil volume recovered in a glass and PVC capillary designed micromodel. Relative permeability was studied using the steady state method, and the wettability was determined by the Amott method. The results show that cores are mainly composed of quartz 86.04%. Oil recovery was 30.50% for oil-wet state; where the wettability index was −0.283. Thereafter, it has been demonstrated that the surfactant solution increases the oil recovery with 23.54 ℅. Adsorption of surfactants on functional groups of PVC change the contact angle between water and PVC's surface from 112° to 39°, decrease the IFT and restore the water-wet state. PVC debris presents efficient new method to determine the water by pass effect on oil recovery. The findings of this study help for better understanding the surfactant-oil displacements during water flooding in light oil reservoirs with impaired wettability. [ABSTRACT FROM AUTHOR]

Asphaltene precipitation in oil reservoirs, well equipment, and pipelines reduces production, causing pore blockage, wettability changes, and decreased efficiency. Asphaltenes, with their unique chemical structure, self-assemble via acid–base interactions and hydrogen bonding. Nano-inhibitors prevent asphaltene aggregation at the nanoscale under reservoir conditions. This study investigates the effect of two surface-modified nanoparticles, silica, and calcium carbonate, as asphaltene inhibitors and oil production agents. The impacts of these nano-inhibitors on asphaltene content, onset point, wettability, surface tension, and oil recovery factor were determined to understand their mechanism on asphaltene precipitation and oil production. Results demonstrate that these nano-inhibitors can significantly postpone the onset point of asphaltene precipitation, with varying performance. Calcium carbonate nano-inhibitor exhibits better efficiency at low concentrations, suspending asphaltene molecules in crude oil. In contrast, silica nano-inhibitor performs better at high concentrations. Wettability alteration and IFT reduction tests reveal that each nano-inhibitor performs optimally at specific concentrations. Silica nano-inhibitors exhibit better colloidal stability and improve oil recovery more than calcium carbonate nano-inhibitors, with maximum oil recovery factors of 33% at 0.1 wt.% for silica and 25% at 0.01 wt.% for calcium carbonate nano-inhibitors. [ABSTRACT FROM AUTHOR]

Purpose. Increasing oil recovery from deposits and reducing the water content of producing wells by providing conditions for uniform displacement of oil from the reservoir under the influence of high reservoir pressure. Methodology. The purpose of the work is achieved by conducting theoretical and experimental studies of the process of creating high elastic energy in the formation by pumping water with injection well pumps to overcome the resistance of oil and water filtration through the pores of the rock and oil rise at the mouth of producing wells. The absence of pumps from producing wells and the acceptance of equal amounts of injection and production wells over the reservoir area significantly increases the reservoir pressure above the pressure of oil saturation with gas. Due to the significant elasticity of the rock and fluids under high reservoir pressure, the oil coverage with water increases and there is no premature breakthrough of water into producing wells. The possibility of creating high elastic energy in an oil reservoir by pumping water into injection wells has been experimentally studied. Findings. It has been established that high reservoir energy in the field of elastic deformation of rock and fluids can be created mainly by pumps from injection wells, due to which oil is uniformly displaced from the reservoir along the entire front without breaking through the injected water into producing wells along the path of least resistance. The adoption of equal amounts of producing and injection wells and their sequential arrangement in rows contributes to the development of high potential energy in the reservoir and increase the pick-up rate of injection and production wells. As a result, the skeleton of the rock forming the pores expands, and the water injected into the reservoir and the displaced oil accumulate and increase reservoir energy. Originality. The effectiveness of the proposed method for maintaining high reservoir pressure is achieved as a result of creating high energy of rock and fluids in the area of their elastic deflation and increasing the coverage coefficients of oil displaced by water over the area and profile of the productive formation without the use of additional capacities and pumping units from producing wells. Practical value. The developed new technique for maintaining high elastic reservoir pressure not lower than the pressure of oil saturation with gas by pumping water into the reservoir can be carried out in oil fields using standard technological equipment and increase oil recovery to 60–70 % at its existing values of 40–45 % and reduce the water content of produced oil to 0–10 % at its existing values of 20–80 % and above. [ABSTRACT FROM AUTHOR]

In order to improve the effect of injection–production coupling development to improve crude oil recovery in complex fault-block reservoirs, we carried out a physical simulation experiment based on a sandpack model of transforming water-driven development into injection–production coupling development and quantitatively evaluated the influence of rounds of injection pressure coupling on the crude oil mobilization in reservoirs with different permeability levels and on oil recovery. Meanwhile, the characteristics of residual oil were studied via a numerical simulation method. The mechanism of increased oil production via injection–production coupling development was revealed by analyzing the water and oil contents, formation pressure, and streamline fields through the establishment of mechanism models. The results of the physical experiment show that injection–production coupling can improve the recovery effect of medium- and low-permeability reservoirs by 55.66%. With an increase in the injection pressure, the oil recovery percentage of the low-permeability sandpack model at 20 MPa is 100%, and this study finds that injection–production coupling is the main way to develop the recoverable oil in a low-permeability reservoir. The numerical simulation results show that among the four remaining oil distribution types (interwell-enriched, low-permeability zone-enriched, well network imperfection, and mismatch between injection and production), the interwell-enriched type of the remaining oil reserves accounts for the highest proportion (48.52%). The simulation results of the mechanism model show that water-driven development easily leads to streamline solidification, resulting in ineffective circulation of the injected water. Compared with conventional water-driven development, the pressure propagation range is significantly increased in injection–production coupling development. The reservoir streamline distribution is more continuous and uniform, and the flooding wave is wider in volume and range. This research provides a theoretical basis for the injection–production coupling technology policy in complex fault-block reservoirs. [ABSTRACT FROM AUTHOR]

The imbibition predicated upon the capillary pressure, can effectively produce the oil and complement the formation energy. In order to explore the relationship between the mixed wetting percentage and the imbibition recovery, as well as the imbibition law in the typical mixed wetting pore-throats, the pore scale imbibition numerical model is established based on phase field theory and Navier-Stokes equation. A series of numerical simulations of pore scale imbibition processes are conducted to analyze of the influence of different mixed wetting degrees on imbibition oil recovery. Results indicate that the imbibition recovery of core with the mixed wetting of 10% is higher than that of pure water-wetting system. For the low mixed wetting percentage, the mixed wetting pore-throats are also the main channel for imbibition oil recovery, whose imbibition effect is the similar as that of the water-wetting channel. When the mixed wetting percentage exceeds 40%, the imbibition recovery is less than 10%, resulting in the poor imbibition effect. For the high mixed wetting percentage, the well-connected and contiguous water-wetting pore-throats become the main advantageous channel for imbibition, while the continuous oil wetting pore-throats hinder the fluid flow, inducing the cessation of the imbibition. The results elucidate the imbibition mechanism and flow potential of mixed wetting degree and mixed wetting distribution, which is of great significance for improving the recovery rate of tight oil reservoirs. [ABSTRACT FROM AUTHOR]

The method of packing conventional proppant into fractures is used to maintain high liquid permeability. In this study, by coating a hydrophobic material on the surface of a proppant, the layer packed with this coated proppant was endowed with water-plugging and oil-permeability capacities. Moreover, several research experiments were carried out to verify the proposed method: a water plugging capacity (WPC) test of the coated proppant layer, compression and temperature resistance tests of the coated proppant (temperature range from 90 to 210 °C; pressure range from 5.9 to 91.4 MPa), and a 3D test of the oil recovery enhancement. The results show that the proppant coating has good compression resistance, and the proppant begins to break at 27.3 MPa. The upper limit of the temperature resistance of the coating is 170 °C. The WPC of the layer packed with coated proppant was still reliable during fracture, which was enhanced by at least 20% compared with that of the layer packed with a conventional proppant. The fracture packed with the coated proppant had superior working performance compared with that packed with a conventional proppant. It can reduce the flow capacity of the water phase breaking into the dominant flow passage so as to delay the rise in the water production of the oil well and prolong the duration of oil production. In this way, oil recovery could be increased by about 7.7%. In conclusion, the technology proposed in this paper has particular water-plugging and oil-permeating characteristics, with remarkable technical advantages, thus providing a new idea for the development of water control in fracture reservoirs. [ABSTRACT FROM AUTHOR]

Copyright of Iraqi Journal of Chemical & Petroleum Engineering is the property of Republic of Iraq Ministry of Higher Education & Scientific Research (MOHESR) and its content may not be copied or emailed to multiple sites or posted to a listserv without the copyright holder's express written permission. However, users may print, download, or email articles for individual use. This abstract may be abridged. No warranty is given about the accuracy of the copy. Users should refer to the original published version of the material for the full abstract. (Copyright applies to all Abstracts.)

Early water and gas breakthrough is a challenge for developing thin oil rim reservoirs. Secondary recovery methods such as water, gas, simultaneous water and gas (SWAG) and gravity-assisted simultaneous water and gas injection (GASWAG) methods are proven methods for developing thin oil rim reservoirs. Knowledge about a preferred technique is important to minimize cost and enhance performance. In this study, various water and gas injection scenarios applied to thin oil rim reservoirs were evaluated using reservoir simulation studies such that horizontal and vertical wells were used for production and injection respectively. The performance indicators considered include cumulative oil produced, oil production rate, and the onset of water and gas coning. Simulation results showed that injecting gas at the gas-oil contact (case 1) and at the water-oil contact (case 2) were the least favorable in improving oil recovery and in delaying gas coning and gas-cap surface production. SWAG and GASWAG resulted to an increase in production rate by 18.5% and 37.9% respectively in comparison to gas injection. Water injection at water-oil contact (case 3), SWAG and GASWAG augmented reservoir pressure with GASWAG sustaining the force balance within the reservoir much more than other methods during the simulation period. GASWAG technique also resulted to a 28% increase in cumulative oil produced in comparison to SWAG. This is because the GASWAG technique improved sweep efficiency with the downward movement of water and the upward movement of injected gas. Results from this study shows that GASWAG is a preferred method for developing thin oil rim reservoirs and should be adopted. It is however recommended to carry out an optimization study which determines the optimal input parameters for a GASWAG process that maximizes cumulative oil produced and delays water and gas breakthrough. [ABSTRACT FROM AUTHOR]

In this study, imbibition tests with and without ultrasonic radiation were performed on limestone samples obtained from the Asmari formation, which is the main Iranian oil reservoirs. The test results have shown a significant increase in the oil recovery with ultrasonic radiation. Reducing the interfacial tension (IFT) and thus reducing the capillary holding force of oil is considered a possible mechanism for increasing oil recovery from oil-wet rock. The capillary pressure curve shows that a relatively large increase in the oil recovery from oil-wet samples will occur if the IFT decreases and the gravity force becomes a dominant force. [ABSTRACT FROM AUTHOR]

In order to accurately predict geomechanical parameters of oil-bearing reservoirs and influencing factors of volumetric fracturing, a new method of geomechanical parameter prediction combining seismic inversion, well logging interpretation and production data is proposed in this paper. Herein, we present a structure model, petrophysical model and geomechanical model. Moreover, a three-dimensional geomechanical model of a typical reservoir was established and corrected using history matching. On this basis, a typical well model was established, 11 influencing factors of volume fracturing including formation parameters and fracturing parameters were analyzed and their impact were ranked, and the oil recovery rate and the accumulated oil production before and after optimal fracturing were compared. The results show that with respect to formation parameters, reservoir thickness is the main influencing factor; interlayer thickness and stress difference are the secondary influencing factors; and formation permeability, Young's modulus and Poisson's ratio are the weak influencing factors. For a pilot well of a typical reservoir, the optimized fracture increased production by 7 tons/day relative to traditional fracturing. After one year of production, the method increased production by 4 tons/day relative to traditional fracturing, showing great potential in similar oil reservoirs. [ABSTRACT FROM AUTHOR]

The ultrasound method is a low-cost, environmentally safe technology that may be utilized in the petroleum industry to boost oil recovery from the underground reservoir via enhanced oil recovery or well stimulation campaigns. The method uses a downhole instrument to propagate waves into the formation, enhancing oil recovery and/or removing formation damage around the wellbore that has caused oil flow constraints. Ultrasonic technology has piqued the interest of the petroleum industry, and as a result, research efforts are ongoing to fill up the gaps in its application. This paper discusses the most recent research on the investigation of ultrasound's applicability in underground petroleum reservoirs for improved oil recovery and formation damage remediation. New study areas and scopes were identified, and future investigations were proposed. [ABSTRACT FROM AUTHOR]

Availability of gases at the field level makes attractive to water-alternating-gas (WAG) process for low viscosity and light oils carbonate reservoir. However, impact of reservoir heterogeneity on WAG performance is crucial before field application. In general, ramp carbonates have heterogeneity due to variation of permeability and porosity. However, WAG performance significantly affected by permeability variations. This article investigates merits and demerits of WAG displacement due to permeability heterogeneities such as permeability anisotropy, high permeability streaks (HKS), matrix permeability, dolomite and thin dense stylolite layers. High-resolution compositional simulations with tuned equation of state (EoS) were carried out using 2D and 3D sector models. The study focuses on WAG performance in terms of oil recovery, vertical sweep, solvent utilization, gas oil ratio (GOR), water cut (WCT), WAG response time, gravity override, hysteresis, un-contacted oil saturation and economics. The results of simulation show that the heterogeneous reservoir provides initially faster WAG response, lower expected ultimate recovery (EUR), faster gas breakthrough, higher GOR and WCT production compared to homogeneous reservoir. The gas gravity override at smaller wells spacing is less in homogeneous reservoir as compared to heterogeneous reservoir, but it is reverse in case of larger well spacing. In heterogeneous reservoir, the HKS shows significant gas override resulting in poor vertical sweep due to capillary holding, and the high permeability dolomite layer shows early water breakthrough. This reservoir has higher solvent utilization in initial stage, and then, it becomes nearly equal to homogeneous reservoir. Simulation in both reservoirs overestimates incremental recovery of 2–3% OOIP at one pore volume injection because of not involving un-contacted oil saturation as predicted in core flood. The findings of this study will help to understand WAG performance and design in highly heterogeneous reservoirs for field applications. [ABSTRACT FROM AUTHOR]

In heavy oil reservoir, the variations of injection pressures induce asphaltene precipitation by CO2 flooding, which causes a reduction in recovery. This paper investigated the microscopic migration characteristics by CO2 flooding at different injection pressures. The results showed that the migration was unobstructed, whereas the spread scope was relatively small at 2 MPa. In case of 8 MPa, there was a mixed area of oil-gas and precipitated asphaltene. A large number of asphaltene precipitations appeared, which inhibited the migration of CO2 at 10 MPa. Additionally, the maximum recovery under 8 MPa was 58.2%, followed by 10 MPa and 2 MPa, respectively. [ABSTRACT FROM AUTHOR]

Knowing the ultimate oil production in wells is a crucial point for reservoir planning and management to anticipate value for money. Commercial reservoir simulators are able to predict production curves with high confidence, but repetitive tasks in a few cases may spend a precious time of staff as well as require a large computational effort. Although artificial intelligence (AI) is providing an alternative path to the usual workflow, many commercial simulators lack robust AI algorithms. This work introduces a methodology based on a multilayer perceptron (MLP) neural network to predict the final cumulative oil production of a reservoir at vertical wells that cross hydraulic flow units (HFUs), which are volumes endowed with good flow attributes. Each well location is attached to special spots previously determined from clustering and calculation of maximum closeness centrality points (MaxCs) within a class of HFUs. The database is divided into training, validation, and testing sets organized after processing the UNISIM-I-D synthetic model, representative of the Namorado Field, Campos Basin, Brazil. The key rationale of this paper is to use the feature of MaxCs of being drivers for well placement as knowledge base to learn the production mechanisms of the oilfield. The outcomes are presented from two perspectives: an original MLP and its post-processed version. Both are compared with reservoir simulations carried out in CMG Imex © and achieve reasonable agreement. The performance is measured by root-mean-squared error (RMSE) and mean absolute scaled error (MASE) both in original and post-processed versions. We show that average RMSE and MASE values near 0.07 and 14.00, respectively, are achieved without post-processing. With post-processing, gains of up to 43% are reported for the integral oil volume. [ABSTRACT FROM AUTHOR]

Thin oil rim reservoirs are predominantly those with pay thickness of less than 100 ft. Oil production challenges arise due to the nature of the gas cap and aquifer in such reservoirs and well placement with respect to the fluid contacts. Case studies of oil rim reservoir and operational properties from the Niger-Delta region are used to build classic synthetic oil rim models with different reservoir parameters using a design of experiment. The black oil simulation model of the ECLIPSE software is activated with additional reservoir properties and subsequently initialized to estimate initial oil and gas in place. To optimize hydrocarbon production, 2 horizontal wells are initiated, each to concurrently produce oil and gas. Well placements of (0.5 ft., 0.25 ft. and 0.75 ft.) are made with respect to the pay thickness and then to the fluid contacts. The results show that for oil rim with bigger aquifers, an oil recovery of 8.3% is expected when horizontal wells are placed at 0.75 ft. of the pay thickness away from the gas oil contact, 8.1% oil recovery in oil rims with larger gas caps with completions at 0.75 ft. of the pay zone from the gas oil contacts, 6% oil recovery with relatively small gas caps and aquifer and 9.3% from oil rims with large gas caps and aquifers, with completions at mid-stream of the pay zone. [ABSTRACT FROM AUTHOR]

In this paper, CO2 assisted steam flooding technique was proposed to further enhance heavy oil recovery after steam flooding. PVT tests and 3D model oil displacing experiment were conducted to investigate enhancing oil recovery (EOR) mechanisms and oil displacing performance. The results indicated that CO2 dissolving in heavy oil could induce oil swelling, reduce oil relative density, and reduce oil viscosity. After steam flooding, 6.8% of sweep efficiency and 8.5% of additional oil recovery were improved by implementing CO2 assisted steam flooding. The study has suggested that CO2 assisted steam flooding is a feasible technique for recovering heavy oil after steam flooding. CO2 dissolving heavy oil can swell oil volume and reduce oil viscosity dramatically. CO2 alternative steam flooding can improve injection pressure and oil–steam ratio, and reduce steam consumption. Introducing CO2 into steam flooding process can increase both oil displacement efficiency and sweep efficiency, then enhancing oil recovery. CO2 assisted steam flooding is a feasible technique for improving oil recovery in heavy oil reservoir after steam flooding. [ABSTRACT FROM AUTHOR]

Carbon dioxide (CO2) sequestration through CO2 enhanced oil recovery (EOR) in oil reservoirs is one way to reduce this gas in the atmosphere. Undesirable chemical reactions that occur during these operations can affect the reservoir structure and characteristics. In this study, the effect of CO2-water-rock interaction on the rock permeability alteration and final oil recovery has been evaluated experimentally during CO2 injection into a carbonate rock. The effect of flow rate, displacement type and pressure were investigated during CO2 EOR injection. Different scenarios of miscible/immiscible displacement, secondary/tertiary recovery has been evaluated for different levels of connate water salinity and injection rate. The results show that the severity of damage is directly related to the injection rate, however change in displacement type from miscible to immiscible reduce the intensity of chemical reactions in porous medium. Moreover, in the tertiary CO2 injection, the chemical reactions become more severe due to the higher water saturations. Interestingly, this growth in the level of chemical reactions has a negligible impact on permeability reduction, since the major volume of possible reactions occurs in coarse and high permeable pores. Results reveal that damage is more intense in the case of more saline water. [ABSTRACT FROM AUTHOR]

Asphaltene is a component of crude oil that has been reported to cause severe problems during production and transportation of the oil from the reservoir. It is a solid component of the oil that has different structures and molecular makeup which makes it one of the most complex components of the oil. This research provides a detailed review of asphaltene properties, characteristics, and previous studies to construct a guideline to asphaltene and its impact on oil recovery. The research begins with an explanation of the main components of crude oil and their relation to asphaltene. The method by which asphaltene is quantified in the crude oil is then explained. Due to its different structures, asphaltene has been modeled using different models all of which are then discussed. All chemical analysis methods that have been used to characterize and study asphaltene are then mentioned and the most commonly used method is shown. Asphaltene will pass through several phases in the reservoir beginning from its stability phase up to its deposition in the pores, wellbore, and facilities. All these phases are explained, and the reason they may occur is mentioned. Following this, the methods by which asphaltene can damage oil recovery are presented. Asphaltene rheology and flow mechanism in the reservoir are then explained in detail including asphaltene onset pressure determination and significance and the use of micro- and nanofluidics to model asphaltene. Finally, the mathematical models, previous laboratory, and oilfield studies conducted to evaluate asphaltene are discussed. This research will help increase the understanding of asphaltene and provide a guideline to properly study and model asphaltene in future studies. [ABSTRACT FROM AUTHOR]

Copyright of Petroleum Geology & Recovery Efficiency is the property of Petroleum Geology & Recovery Efficiency and its content may not be copied or emailed to multiple sites or posted to a listserv without the copyright holder's express written permission. However, users may print, download, or email articles for individual use. This abstract may be abridged. No warranty is given about the accuracy of the copy. Users should refer to the original published version of the material for the full abstract. (Copyright applies to all Abstracts.)

Spontaneous imbibition and displacement are important mechanisms in water flooding. This paper is aimed to evaluate the performance of water imbibition and injection in tight sandstone oil reservoir. Imbibition tests were first done to assess potential contributions to displacement and oil recovery. Then, a subsequent water injection at constant pressure was conducted in cores with permeability less than 0.1 mD and larger than 0.1 mD to explore the extent to which oil can be displaced and to evaluate fluid flow behavior. Finally, water injection at constant velocity was implemented to simulate displacement under reservoir condition and to analyze flow characters during injection. Results showed that water imbibition enhanced recovery more significant in cores with permeability less than 0.1 mD than that in cores with permeability larger than 0.1 mD. The recovery obtained was 19.2–26.7% and 6.7–7.6%, respectively. The subsequent water injection at constant pressure enhanced recovery further from 6.7–7.6% to 35.2–37.7% in cores with permeability larger than 0.1 mD. However, it did not make sense in cores with permeability less than 0.1 mD. There were a narrow area for oil/water co-flow and a sharp decrease in oil permeability at the initial stage. Meanwhile, the recovery during water injection at constant velocity was 57.7% and 42.9%, respectively. It presented high injection pressure in the upstream, and the quasi-threshold pressure gradient reached 80–200 MPa/m, which was hard to implement in reservoir. The injection pressure increased with the decrease in permeability. It also reveals that dominant channels exist and may lead to early water breakthrough which is negative for recovery enhancement. [ABSTRACT FROM AUTHOR]

Carbon dioxide is a major greenhouse gas that leads to global warming. Injection of CO2 into oil reservoirs not only improves oil recovery but also stores large quantities of CO2 in the reservoir. However,the limited supply of carbon dioxide often restricts the implementation of CO2 flooding projects. Carbonated water injection (CWI) can be a good alternative when carbon dioxide is inadequate. Laboratory tests revealed that CO2 effectively improved oil recovery by increasing oil volume and reducing oil viscosity. Several field cases in the USA demonstrated that CWI not only improved oil production but also enhanced water injection. [ABSTRACT FROM AUTHOR]

The technology of CO2 injection into oil reservoirs contributes to a significant increase in oil production effectively reducing greenhouse gas emissions into the atmosphere. The mechanism of enhanced oil recovery was studied on the example of large formations of the Ordos Basin. The Ordos shale oil field is characterized by low porosity, low permeability and high reservoir heterogeneity. In this paper; based on an experimental model, a mechanism of filtration of fluid in a formation rock is proposed. To verify the model, oil recovery parameters were studied experimentally during CO2 injection for the conditions of the YanChang field of the Ordos Basin. In the course of the experiments, on models of long cores of the rock, the effect of the rate and intensity of injection, the exposure time and well parameters on the displacement efficiency during cyclic injection were measured. The paper concludes that it is possible to use CO2 injection technology to improve the efficiency of oil recovery on reservoirs using the example of the YanChang field. [ABSTRACT FROM AUTHOR]

Highlights • Asphaltene wt% was quantified for all the experiments, both for the produced and bypassed oil. • The percentage of asphaltene in the recovered oil was higher for the higher CO 2 injection pressure. • Higher oil viscosity had a lager asphaltene weight percent. • Increasing the heterogeneity of shale pore structure resulted in a higher asphaltene weight percent. • Severity of asphaltene pore plugging in the smaller Nano- pores of the shale reservoirs was observed. Abstract Carbon dioxide (CO 2) injection has been shown to improve oil recovery from conventional oil reservoirs, with a relatively high rate of success. Recently, it has also been applied in unconventional shale reservoirs, with hopes that it could improve oil recovery from them as well. The process proved successful in some shale plays, but failed in others. This research investigates the CO 2 flow mechanism in nano-pores and its impact on asphaltene precipitation, which could lead to pore plugging and a reduction in oil recovery. Nano-composite filter membranes were used to conduct all experiments. The setup used was a specially designed filtration apparatus that could incorporate the nano filter membranes. The factors studied include the CO 2 injection pressure, temperature, oil viscosity, CO 2 soaking time, porous media thickness, nano-pore size, and pore size heterogeneity. Asphaltene wt% was quantified for all the experiments, both for the produced and bypassed oil. Increasing the CO 2 injection pressure resulted in a higher oil recovery and a shorter CO 2 breakthrough time. Also, the percentage of asphaltene in the recovered oil was higher for the higher CO 2 injection pressure. Results indicated that increasing the temperature also resulted in a higher oil recovery, however, the asphaltene wt% in the bypassed oil also increased with temperature due to instability of the oil stabilizing agent, resin. It was found that the higher oil viscosity had a larger asphaltene weight percent. Increasing the thickness and heterogeneity resulted in a decrease in oil recovery and also a higher asphaltene weight percent. Increasing the nano-pore size resulted in a significantly higher oil recovery, and less pore plugging. This research investigates the flow mechanism of CO 2 injection and asphaltene precipitation due to CO 2 injection in nano-pores in order to better understand the main factors that will impact the success of CO 2 injection in unconventional shale reservoirs. [ABSTRACT FROM AUTHOR]

Water injection as one of the most efficient and worldwide extensively employed approach in homogenous oil reservoirs suffers from early water breakthrough time as well as low oil sweep efficiency values in fractured oil reservoirs. This study investigates the potential application of Cr(III)-acetate based gel polymer system in a typical water injection process using one fractured micromodel. For this purpose, three sulfonated polyacrylamides, different in solfunation degree, and one hydrolyzed polyacrylamide were studied regarding gelation time, gel strength and stability to find the optimized conditions in terms of polymer type and concentration, and polymer/Cr(III)-acetate ratio, which were subsequently used for one dynamic test. Results illustrated the optimized conditions as AN 105 polymer with concentration of 5000 ppm and polymer/Cr(III) ratio of 5. Moreover, results showed that implementing such gel system yields an increased oil recovery value of 24.46% OOIP at 1.55 PV and delays the breakthrough time from 0.47 PV to 0.51 PV. [ABSTRACT FROM AUTHOR]

[Display omitted] • Chia seeds mucilage as a new natural polymer is used for enhanced oil recovery. • CSP is stable in high salinity and high temperature. • The viscosity reduction of CSP is not significantly affected by salinity and temperature. • CSP causes the wettability alteration of oil-wet sandstone rock. • Oil recovery is increased by 21.2% and 16.3% by TPC and AP slug injection %, respectively. In this research, the extracted mucilage from Chia seeds is introduced as a new natural polymer for use in polymer injection into oil reservoirs. Chia seeds polymer (CSP) is environmentally friendly, economical, efficient and available, and its industrial production and extraction are done in the world for use in various applications. Polymer fluid injection was performed under two polymer injection scenarios: taper polymer concentration (TPC) and alkali-polymer (AP) slug injection. CSP is stable up to salinity above 90,000 ppm and also maintains its performance at reservoir temperature. The viscosity changes of CSP solutions against shear rate confirm its non-Newtonian behavior, which increases in intensity with increasing CSP concentration. The CSP hydrocolloid increases the viscosity of the injection fluid at low concentrations to suitable values for EOR. In this way, the viscosity values of polymer solutions at concentrations of 200, 400, 600, 800, 1000 and 1200 ppm were equal to 27.14, 42.36, 68.11, 93.75, 125.62 and 154.51 mPa.s, respectively. Although the viscosity of CSP solutions decreases with increasing salinity and temperature, there is no sharp drop and the obtained values are suitable even at high salinity and temperature. The hydrophilicity of the sandstone reservoir rock is proportional to the increase in CSP concentration. The contact angle sizes at concentrations of 600, 800, 1000 and 1200 ppm were obtained as 84.98°, 78.04°, 70.39° and 67.69°, respectively. CSP injection under both scenarios reduces the water-cut well and oil recovery is increased by 21.2% and 16.3% by TPC and AP injection, respectively. [ABSTRACT FROM AUTHOR]

The objective of this research is to investigate the efficacy of nanoparticles in reducing the viscosity of heavy oil. In this study, three types of metal oxide nanoparticles (CuO, Fe 2 O 3 , and NiO) are employed, and their effect on heavy oil viscosity is examined at three different concentrations (0.05, 0.1, and 0.5 wt.% of oil). For all test fluids, rheological measurements were obtained at four different temperatures ranging from 27 to 71 °C. The experimental work is conducted with two extremely viscous heavy oil samples having viscosity of approximately 77 and 350 Pas at ambient temperature. This study is unprecedented in terms of viscosity of heavy oil samples investigated. The heavy oil samples used in this study are 9–40 times more viscous than those used in previous similar studies. The addition of nanoparticles resulted in a notable reduction in viscosity of both heavy oil samples. For each type of nanoparticles, 50–70% viscosity reduction was observed. The level of viscosity reduction is sensitive to the types of nanoparticles, their concentration, and fluid temperature. Moreover, the results indicate existence of an optimum concentration of nanoparticles at which maximum viscosity reduction occurs. This optimum concentration is a function of the metal type and fluid temperature. To explain observed viscosity alteration behavior, the paper provides a theoretical overview of various molecular-level physical and chemical interactions between nanoparticles and heavy oil. Additionally, the study presents a new heavy oil viscosity data and delineates some of the challenges associated with viscosity measurement of heavy oil. This research provides valuable information for future rheological and core-flooding studies involving nanoparticle stabilized solvent-based emulsions. Besides, remarkable viscosity reduction obtained in this work reinforces the industry's interest in developing an economically feasible nanoparticle-based technique and helps to solve real problems in the field. [ABSTRACT FROM AUTHOR]

A well-known complication in the oil reservoir during oil production is asphaltene deposition in and around the production wellbore. Deposition of asphaltene around the production wellbore may cause a significant pressure drop and in turn loss of efficiency in the production process. Various mechanical and chemical methods have been employed in order to reduce asphaltene formation or to eliminate the precipitate. A novel technique which presented a great potential for prevention or elimination of asphaltene is spreading out the high energy ultrasound wave within the oil reservoir. In this study, in a glass micro-model, asphaltene precipitation was first simulated in a transparent porous medium and its removal by application of high energy ultrasound wave was then investigated. To simulate asphaltene precipitation, the micro-model was first saturated with oil and then a normal-pentane was injected. This was followed by flooding the porous media with brine while propagating ultrasound waves (30 kHz and 100 W) to eliminate asphaltene precipitation. The experiment setup was equipped with a temperature controller. The results indicate a significant reduction in asphaltene precipitation in the oil reservoir may be achieved by application of ultrasound energy. Asphaltene particle deposition has been solved reversibly in the oil layer of porous medium and with the oil layering mechanism, the rate of oil production has been increased. In some spots, water/oil emulsion has been formed because of the ultrasonic vibration on the wall. Both the crude and synthetic oils were examined. [ABSTRACT FROM AUTHOR]

• The addition of nano-silica can significantly improve oil production after fracturing. • Nano-silica improved in the anti-swelling performance of the gel-breaking fluid. • Nano-silica had an excellent oil-washing effect. • Field tests showed the cumulative oil production of the test wells was significantly enhanced. Nanomaterials have the characteristics of reducing water molecular clusters and improving surface properties. Therefore, it can effectively enhance the oil displacement (or imbibition) effect while developing low permeability and unconventional reservoirs. Volume fracturing based on horizontal wells has become the primary technology in developing unconventional reservoirs. In this paper, we investigated the effect of nano-SiO 2 on the rheology, flowback, and subsequent oil displacement performance of fracturing fluid. Results showed that nano-SiO 2 had little impact on the swelling and dispersion properties of the two thickeners (i.e., guar gum and emulsion polymer). The apparent viscosity of these two thickener solutions decreased by less than 15% after aging for 24 h. Nevertheless, nano-SiO 2 particularly influenced the rheological properties of guar gum based fracturing fluid. That is to say, the increase in the amount of nano-SiO 2 gradually reduced the temperature and shear resistance of the fracturing fluid. When the concentration of nano-SiO 2 reached 5%, the temperature and shear resistance of fracturing fluid decreased by 40%–60% in the temperature range of 80 to 100 °C. However, nano-SiO 2 had little effect on the fracturing fluid's breaking time and the solution's viscosity after breaking, and the surface tension of the solution slightly increased after breaking. The fracturing fluid added with nano-SiO 2 improved the performance of inhibiting clay swelling after the gel was broken. In addition, the solution after gel breaking had an excellent demulsification effect on emulsified crude oil when the concentration of nano-SiO 2 was less than 0.2%. While the concentration of nano-SiO 2 was greater than 0.5%, the increase in nano-SiO 2 concentration gradually strengthened the emulsification between crude oil and gel-breaking fluid. Nano-SiO 2 also had an excellent oil displacement effect, and it increased the recovery efficiency of primary water flooding by 9.99–13.34 percentage points. IThe field test of nanoparticle flooding and fracturing integrated technology was carried out for two wells in the Mahu tight oil reservoir of Xinjiang Oilfield, NW China. The pilot tests of the two wells were very successful, and the cumulative oil production on the 180th day after the fracturing operation was 20–50% higher than that of the comparison well. [ABSTRACT FROM AUTHOR]

Thermal enhanced oil recovery is known to be the most effective way of heavy oil production. This article discusses the application of sinusoidal wells to improve the efficiency of thermal enhanced oil recovery methods. As a result of numerical simulation of steam-assisted gravity drainage (SAGD) process, it has been shown that the application of sinusoidal wells allowed 8990 m 3 of the incremental oil production during 10 years simulation period. However, the high cost of hot water and steam generation, as well as significant environmental impact, limit the application of thermal oil recovery methods. The article presents the concept of year-round generation of desalinated hot water and steam from sea and reservoir brine at low cost by the newly developed solar collector. The collector can be placed in the vicinity of injection wells to provide constant hot water, steam, and electrical power supply. [ABSTRACT FROM AUTHOR]

Viscoelastic solutions are notoriously sensitive to temperature and ionic strength. In order to be applicable for use in oil reservoirs, they need to be resilient to higher temperatures as well as to saline content. We define the essential characteristics required. Refractory properties obtained under Couette testing do not necessarily provide the same performance under pressure-driven flow. Nonetheless, it is possible to formulate solutions which clearly indicate that subsurface application is practicable. We show examples where salinity enables significantly enhanced viscoelasticity above ambient temperatures. [ABSTRACT FROM AUTHOR]

Counter-current imbibition is a process whereby a wetting phase spontaneously imbibes into a porous media, displacing the non-wetting phase. This process is considered an important oil recovery mechanism during water flooding in fractured oil reservoirs. In this study, the dynamic process of counter-current imbibition for a natural reservoir sandstone core with an all-face-open boundary condition was monitored using magnetic resonance imaging (MRI). A series of images and relaxation time T1 spectra were acquired. The movement of water spontaneously entering the core sample while oil escapes, the spatial distribution of oil and water, and the in situ saturation change of oil and water in porous media can be accurately detected using MRI. MRI assists the direct evaluation of the basic mechanisms of imbibitions. Experimental results suggest the remaining oil was trapped in some large pores because of the capillary pressure, and the oil recovery in some large-pore regions is lower than that in some small-pore regions at the end of imbibition. Experimental findings show a close agreement between conventional material balance and oil recovery determined from MRI. The in situ oil recovery data agree well with the empirical models. The observations from MRI images could provide test cases to enable the development of mathematical models and to facilitate the evaluation of the proposed imbibition mechanisms. Copyright © 2016 John Wiley & Sons, Ltd. [ABSTRACT FROM AUTHOR]

Added values to project economy from oil recovery process and difficulties of the oil recovery mechanism are the main differences between light oil and conventional oil reservoirs. One needs to gain distillate rate in the steam distillation technique in crude oil recovery; however, this needs particular experiments. In this research, the approach inspired a new intelligent solution named the least square support vector machine to monitor the distillate rate in the steam distillation method for oil recovery goals. The suggested low parameter model is applied to the gathered experimental data from prestigious attentions to train and develop and test the introduced approach. The predicted outcomes from the low parameter model were contrasted to the relevant measured data points and generated results of conventional and empirical correlations. A comparison between the gained solutions of our method and the alternatives proves that the proposed vector machine approach estimates the distillate rate in the steam distillation process for oil recovery more precisely in contrast with the previous and empirically applied models. [ABSTRACT FROM PUBLISHER]

Horizontal well applications have been predominant since their conception, for reasons such as effective depletion of oil reservoirs and especially in water cresting, gas cresting or water and gas cresting applications due to the casings enhanced exposure to the reservoir. Cresting is hugely dependent on oil production rate, pressure drawdown and can negatively influence the degree of depletion as well as the overall recovery efficiency of oil reservoirs. This paper presents a novel procedure of mimicking horizontal wells aimed at investigating experimentally the effect of varying inclined sections (having different vertical and horizontal displacements) of horizontal wells at low angles of inclination (15°-30°) in a homogeneous reservoir underlain by a strong bottom aquifer and overlain by a considerable gas cap drive occurring simultaneously. The results for the performance of the different horizontal well geometries in terms of cumulative oil recovery and Water-Oil-Ratio; over a fixed liquid production time were compared. From the results obtained, it was observed that the short radius well with 30° angle of inclination and ratio of vertical displacement of the inclined section to reservoir height of 0.07 resulted in the highest oil recovery of 38.73%. Using the presented procedure, 5.60% increment in oil was recovered with 11.40% reduction in cumulative produced water were observed between the best and worst cases from the same reservoir. At higher withdrawal rates and pressure drop, long radii wells are recommended due to cresting delay ability while improving oil recovery. [ABSTRACT FROM AUTHOR]

• The influence of asphaltenes on pore structure and oil recovery were studied. • The asphaltene precipitation is positively correlated with round and pressure. • The asphaltene precipitation is different in different types of samples. CO 2 huff- n -puff can store CO 2 and improve the recovery of tight oil reservoir. The asphaltene precipitation produced by the interaction of CO 2 and oil causes damage to tight oil reservoirs. Based on the FE-SEM, CST, Nano-CT, HPMI and NMR, the microscopic classification standard is established. The experiments were carried out on different types of samples to quantitatively evaluate the influence of asphaltenes on pore structure and oil recovery. The results show that the asphaltene precipitation is positively correlated with huff- n -puff rounds and injection pressure. The asphaltene precipitation in type I sample is the highest. The asphaltene precipitation in type II sample is lower. The lowest asphaltene precipitation is in type III sample. In the CO 2 immiscible state, asphaltenes are mainly deposited in larger pore throats. In the CO 2 miscible state, the CO 2 extraction effect is enhanced, the asphaltene deposits in the smaller pore throats. The overall oil recovery of the type II sample is the highest. The asphaltene precipitation, the blockage degree, the oil recovery interact and restrict each other. The oil recovery increases, the asphaltene increases, and the blockage degree of pore throats become more serious. Asphaltene precipitation causes damage to physical properties in reservoir, the porosity and permeability damage rates range from 1.35% to 3.17% and 2.17% to 8.24%, respectively. Asphaltene changes the wettability to lyophilic. The wettability reversal index ranges from 0.86% to 4.92%, which increases the seepage resistance of the oil phase. This research is novel for quantitative evaluation of reservoir microscopic pore throat characteristics and microscopic oil displacement mechanism by asphaltene precipitation formed during CO 2 huff and puff in tight oil reservoirs. Also, the research results are of significance for optimizing the field development parameters. [ABSTRACT FROM AUTHOR]

This paper applies graph centrality measures to suggest a competitive placement of perforation zones in oil reservoirs. Datasets available in an online repository are used to build a synthetic field model in which porosity and permeability are known everywhere. From this field, a reservoir associated to a central oil well chosen randomly is extracted so as to form a volume containing distinct groups of petrophysical regions. Combined with the well-known FZI/DRT (flow zone indicator/discrete rock type) techniques, which identifies hydraulic flow units by means of linear regression best-fit lines and conversion formulae, high-performance clusters, as well as their respective target zones, are identified in the reservoir. Each cluster is modelled as an irregular set of face-connected cells and additionally mapped onto undirected graphs. Individual numerical simulations of production wellbores placed at testing and target zones are performed for several clusters. We find that when the wellbores are placed exactly at those vertices whose closeness centrality measure is maximum, considerable oil recovery factors are achieved, thereby suggesting highly competitive perforation zones. We conjecture that the current approach may be used as a decision-making tool to allocate production zones and choose economically viable perforation strategies for implementation during the stages of drilling and production. [ABSTRACT FROM AUTHOR]

Steam-assisted gravity drainage (SAGD) is an important oil recovery strategy for extra heavy oil and bitumen. Operators are under pressure to improve both the environmental and economic performance of SAGD. Through direct visualization, micromodels provide insight into SAGD, but methods to date cannot fully resolve the temperature field which is essential to this thermal recovery process. In this work, infrared and optical pore-scale imaging of the SAGD process within a micromodel with reservoir-relevant pore geometries, fluids, and temperatures was performed, and both recovery and pore-scale fluid behavior was quantified for different concentrations of alkaline additive. Combined microscale flow and high-resolution temperature analysis provide insight into pore-scale phenomena, and shed light on the link between the rapid temperature drop at the steam chamber interface, drainage modes, efficiency and ultimate recovery achieved in SAGD. [ABSTRACT FROM AUTHOR]

Residual or oil reserves nonrecoverable through industrial and basic development methods reach an average of 55–75% of oil initially in place. Residual oil parameters differ from previous parameters in order that some fields of Azerbaijan are in long-term usage. When the hydrocarbon drive from porous medium is conducted by water, compressed air, water-air mixture, and, if there exist the natural emulsifiers (asphaltene, resin, paraffin, clay, different salts), in this case the oil deposited on the rock surface is in the form of emulsion. It is necessary to use special displacement agent for this type of residual oil displacement. Oil from Surakhany field of Azerbaijan Republic is given as a test subject due to enhanced oil recovery being intense in this field. Experimental studies have been conducted in laboratory conditions in order to prepare a more efficient composition system for water-oil emulsion drive. After injection of the prepared composition to the formation by the well # 1309 during 10 days as the intermediate layer of 0.8% of porosity, the compressed air (850 m3/day) is injected and moves toward the production wells. A total of 779 tons incremental oil was produced as a result of developed technological process application in IV horizon of Surakhany field. [ABSTRACT FROM AUTHOR]