An Experimental Investigation of Sequential CO2 and N2 Gas Injection as a New EOR Method

SummaryLow-salinity waterflooding and carbon dioxide (CO2) injection are enhanced oil recovery (EOR) methods that are currently increasing in use worldwide. Linking these two EOR methods is a promising approach in the exploration of mature fields and for post- and presalt basins in Brazil. Moreover, the latter reservoirs already exhibit a high CO2 content by nature. Interfacial phenomena between fluids and rock in a low-salinity water-CO2 (LSW-CO2) environment remain unclear, particularly the wettability behavior that is related to the pH of the medium, among others. This study investigates the influence of rock composition and pH of the brine on reservoir wettability through coreflooding and zeta potential experiments in LSW and determination of contact angles and interfacial tension (IFT) in the crude oil-LSW-CO2 system at reservoir conditions. Brazilian light crude oil, pure CO2, and brine solutions of different concentrations and compositions were used to represent the fluids in actual oil reservoirs. The experiments were carried out on Botucatu sandstone, Indiana limestone, and calcite crystal samples, with mineralogy determined by energy dispersive X-ray (EDX) analysis. Coreflooding experiments were conducted by the injection of 10 pore volumes (PVs) of fourfold diluted synthetic reservoir brine (SRB), followed by 10 PVs of 40-fold diluted SRB to evaluate the low-salinity effects. Interfacial properties, such as contact angle and IFT, as well as density and pH, were determined at elevated pressures to evaluate the synergistic effects between CO2 and salt content. In addition, geochemical modeling using PH REdox EQuilibrium (in C language) (PHREEQC) was performed to predict the in-situ pH and match with the experimental data. An increase in oil recovery and pH of the effluent was observed in the coreflooding experiments during diluted SRB injection. The ionic concentrations of the effluent samples also indicated illite dissolution. Furthermore, zeta potential measurements confirmed the expansion of the water film and shift from positive to negative surface charge of Botucatu sandstone for salt concentrations less than 80,000 mg/L at pH > 7, whereas in Indiana limestone, negative surface charge was only observed in deionized water at pH > 9. These observations indicate that during LSW injection alone, an increase in pH will favor a thicker water layer on the Botucatu sandstone surface that in turn increases water wettability and results in increased oil recovery. Conversely, the presence of CO2 in LSW causes a decrease in the pH of the medium, which is related to further enhancing water wettability when linking pH with contact angle measurements. It seems that a change in the pH of the brine induced by CO2 solubility in LSW enhanced interactions between the rock surface and water molecules. The respective interfacial energy then decreased, resulting in a decreasing water contact angle. It was also noticed that seawater-CO2 systems caused salt precipitation and mineralogical changes in carbonate and sandstone rock induced by calcite and kaolinite dissolution, respectively. This study contributes substantially to the understanding of interfacial properties and wettability behavior in LSW-CO2 systems, facilitating the design of LSW-CO2 EOR applications in Brazilian fields or even CO2 storage. Moreover, the study provides useful data for oil companies that have acquired mature wells and exploration blocks in Brazil, supporting them in operational and investment decisions.

SummaryWe present a comprehensive investigation of gas injection for enhanced oil recovery (EOR) in organic-rich shale using 11 coreflooding experiments in sidewall core plugs from the Wolfcamp Shale, and three additional coreflooding experiments using Berea Sandstone. Our work studies the effect of pressure, minimum miscibility pressure (MMP), soak time, injection-gas composition, and rock-transport properties on oil-recovery factor. The injection gases were carbon dioxide (CO2) and nitrogen. The core plugs were resaturated with crude oil in the laboratory, and the experiments were performed at reservoir pressure and temperature using a design that closely replicates gas injection through a hydraulic fracture, minimizes convective flow, and exaggerates the fracture to the reservoir-rock ratio. We accomplished this by surrounding the Wolfcamp reservoir-rock matrix with glass beads. Computed-tomography (CT) scanning enabled the visualization of the compositional changes with time and space during the gas-injection experiments and gas chromatography provided the overall change in composition between the crude oil injected and the oil recovered.As gas surrounds the oil-saturated sample, a peripheral, slow-kinetics vaporization/condensation process is the main production mechanism. Gas flows preferentially through the proppant because of its high permeability, avoiding the formation and displacement of a miscible front along the rock matrix to mobilize the oil. Instead, the gas surrounding the reservoir-core sample vaporizes the light and intermediate components from the crude oil, making recovery a function of the fraction of oil that can be vaporized into the volume of gas in the fracture at the prevailing thermodynamic conditions. The mass transfer between the injected gas and the crude oil is sufficiently fast to result in significant oil production during the first 24 hours, but slow enough to cause the formation of a compositional gradient within the matrix that exists even 6 days after injection has started. The peripheral and the slow-kinetics aspects of the recovery mechanism are a consequence of the low fluid-transport capacity associated with the organic-rich shale that is saturated with liquid hydrocarbons.Our results show CO2 overperforms nitrogen as an EOR injection gas in organic-rich shale, and higher injection pressure leads to higher oil recovery, even beyond the MMP. The gas-injection scheme should allow enough time for the mass transfer to occur between the injected gas and the crude oil; we achieved this in the laboratory with a huff ’n’ puff scheme. Our results advance the understanding of gas injection for EOR in organic-rich shale in a laboratory scale, but additional work is required to rigorously scale up these observations to better design field applications.

Experimental investigation of the influence of supercritical carbon dioxide and supercritical nitrogen injection on tertiary live-oil recovery

In this work, an experimental study combined with numerical simulation was conducted to investigate the potential of chemically enhanced water alternating gas (CWAG) injection as a new enhanced oil recovery method. The unique feature of this new method is that it uses alkaline, surfactant, and polymer additives as a chemical slug which is injected during the water alternating gas (WAG) process to reduce the interfacial tension (IFT) and simultaneously improve the mobility ratio. In essence, the proposed CWAG process involves a combination of chemical flooding and immiscible carbon dioxide (CO2) injection and helps in IFT reduction, water blocking reduction, mobility control, oil swelling, and oil viscosity reduction due to CO2 dissolution. Its performance was compared with the conventional immiscible water alternating gas (I-WAG) flooding. Oil recovery utilizing CWAG was better by 26 % of the remaining oil in place after waterflooding compared to the recovery using WAG conducted under similar conditions. The coreflood data (cumulative oil and water production) were history matched via a commercial simulator by adjusting the relative permeability curves and assigning the values of the rock and fluid properties such as porosity, permeability, and the experimentally determined IFT data. History matching of the coreflood model helped us optimize the experiments and was useful in determining the importance of the parameters influencing sweep efficiency in the CWAG process. The effectiveness of the CWAG process in providing enhancement of displacement efficiency is evident in the oil recovery and pressure response observed in the coreflood. The results of sensitivity analysis on CWAG slug patterns show that the alkaline–surfactant–polymer injection is more beneficial after CO2 slug injection due to oil swelling and viscosity reduction. The CO2 slug size analysis shows that there is an optimum CO2 slug size, around 25 % pore volume which leads to a maximum oil recovery in the CWAG process. This study shows that the ultralow IFT system, i.e., IFT equaling 10−2 or 10−3 mN/m, is a very important parameter in CWAG process since the water blocking effect can be minimized.

Currently, there is a great deal of interest in carbon dioxide for the recovery of both heavy and light oils. This paper deals with an investigation of the efficiency of gaseous carbon dioxide as a recovery agent for moderately viscous oils. The paper gives numerical model results, and compares and contrasts the findings with laboratory and field test observations, pointing out the range of conditions over which carbon dioxide is likely to be effective. The carbon dioxide injection simulator used simulates three- phase flow, and was checked out for numerical dispersion grid effects, material balance, etc. It was then employed for a variety of carbon dioxide injection simulations. The base cases were in qualitative agreement with the reported experimental data. It was found that over the viscosity range of J 10 1000 mPa.s, carbon dioxide was superior to natural depletion, inert gas injection or water flooding, jar oil viscosities above 70 mPa. s. The gain over water flooding was as much as 9 per cell· tiles in oil recovery, being greater for the more viscous crudes. Oil saturation was an important variable, as oil recovery decreased rapidly with a decrease in saturation. Another significant factor affecting ultimate oil recovery was the critical gas saturation. Viscous oils showed a 27% increase in recovery as the critical gas saturation varied from 0 to 10%. The blow down recovery on curtailment 0/ carbon dioxide injection was about 1 percentile; field values are as high as 4 percentiles. Reasons for this discrepancy are outlined. The amount of carbon dioxide left in the reservoir was used as a measure of the efficiency of the process; it was high for low oil saturations, especially for the more viscous oils. An economic analysis of the carbon dioxide injection process showed that the economics are tenuous; a variety of factors in addition to the oil price would determine the economic viability of the process. Introduction Although there is little debate that a significant amount of oil remains held in the ground by current technical and economic constraints, opinion is widespread as to the proper recovery technique or techniques to unlock these reserves. (Infill drilling and a handful of alternative recovery methods, such as thermal, miscible and improved mobility floods, compete for the over 52 billion cubic metres of United States and Canadian oil (<980 Kg/m3) that remains in place. Carbon dioxide injection, as one of these processes, has long been thought of as a miscible process best applied in light oils with densities less than 930 Kg/m3. However, immiscible carbon dioxide flooding as part of the suite of enhanced oil recovery methods being tested may be promising in the case of heavy, moderately viscous oils where carbon dioxide injection improves recovery by lowering oil viscosity and promoting swelling. Deposits of heavy oil total over one-half trillion metres3 in the U.S., Venezuela and Canada. In the U.S. alone, there are over 2,000 heavy oil reservoirs occurring in 1500 fields in 26 states.

Non-thermal enhanced oil recovery (EOR) techniques show a great potential for recovering oils from the thin and shaly heavy oil reservoirs of Saskatchewan. Among the non-thermal processes, immiscible carbon dioxide injection holds the most promise of accessing these reservoirs. This technique, however, is much less developed than thermal methods. The process, if proven applicable to Saskatchewan reservoirs between three and seven metres thick, will access approximately 90 percent of the total oil in- place. The paper is divided into two sections. The first deals with the characterization of a Kintfersley area heavy oil. The characterization includes analysis of: stock tank oil with and without additives, recombined reservoir fluid, and reservoir fluid plus carbon dioxide. The second section describes a scaled physical model, and two displacement experiments conducted using a Lloydminster area heavy oil. The laboratory phase behaviour data were generated to show the effect of pressure and temperature on carbon dioxide solubility, oil density and viscosity, compressibility, and swelling factors. The viscosity of the reservoir fluid at 25.5 °C was reduced from 819 mPa.s to 45 mPa.s with the addition of 73.1 sm3 m3/ of carbon dioxide al 7 MPa, an eighteenfold reduction. The same reduction in viscosity would require heating the sample to approximately 80 °C. The above oil, under similar conditions, increased in density from 963.0 kg/ m3 to 974.3 kg/ m3 and swelled approximately 15%. Two scaled model experiments (secondary displacements) were conducted using a 10-cycie water-alternating-gas (WAG) process with a WAG ratio of4:1. In each run, the total mass of carbon dioxide injected was 1.41 g-mol (0.53 PV at 25 MPa, 0.30 PV at 4.1 MPa). The scaled model displacements indicated the immiscible carbon dioxide WAG process to be partially sensitive to the operating pressure in the range of study. More important is the relative volume of carbon dioxide, at experimental conditions, which dictates overall performance. Introduction Carbon dioxide flooding appears to be the only non-thermal recovery process that holds promise of allowing access to the typically-thin reservoirs in which most of Saskatchewan's heavy oil is found. Thermal methods are often inefficient and uneconomical due to excessive vertical heat losses, because of thin pay zones, and steam scavenging by bottom water zones. Carbon dioxide may behave as a miscible or immiscible fluid when contacted with oil at reservoir conditions. Holm1 defines miscibility as follows: "For petroleum reservoirs, miscibility is defined as that physical condition between two or more fluids that will permit them to mix in all proportions without the existence of an interface. If two, or more, fluid phases form after some amount of one fluid is added to others; the fluids are considered immiscible and an interfacial tension exists between the phases." Moderately viscous heavy oils (10–15 °API) lack the necessary extractable hydrocarbons (C5-C30) for miscible conditions to be economically attained. In some cases, moderately light oils (25–35 °API) are being displaced immiscibly because the pressures required to achieve miscible conditions would severely fracture the formation.

A gravity-stable miscible CO2-solvent flood is underway in the Bay St. Elaine Field, South Louisiana. A 33% pore volume CO2-solvent slug was injected into a dipping water drive reservoir and is being pushed downdip by the injection of nitrogen gas. The CO2-solvent selected for this tertiary flood was tailored by the addition of methane and n-butane to the carbon dioxide. This CO2-solvent provides the density difference required to complete a gravity-stable flood within the desired time period and also satisfies the minimum miscibility pressure requirements at reservoir conditions. The paper presents laboratory experimental work performed and process design work required to undertake this type of enhanced recovery project. The results obtained from slim tube tests to determine the CO2-solvent composition are presented as well as results of 12-foot sand pack displacement tests to evaluate the recovery efficiency of the selected CO2-solvent. Procedures used to determine the mixing zone lengths needed for CO2-solvent slug design are discussed along with the method of calculating critical velocity. Pressure pulse tests conducted to improve reservoir definition within the project area are reviewed. In situ residual oil saturations for the unconsolidated sand determined from pressure cores, log-inject-log water flood tests, single well partitioning tracer tests, and open hole well logs are presented. Field injection and current production data are also analyzed. The methods presented are being used to design CO2-solvent floods for reservoirs previously thought to be unsuited for conventional miscible CO2 flooding. The procedures and concepts discussed can be applied to flood design for numerous secondary and tertiary miscible CO2 projects.

Enhanced oil recovery (EOR) plays a vital role in maximizing oil production from depleting reservoirs. As EOR technologies advance, updating screening criteria is essential to evaluate and recommend suitable EOR methods for target reservoirs. This study aims to establish updated screening criteria to identify the most effective EOR methods based on specific reservoir characteristics. A structured selection approach facilitates the evaluation of advanced EOR technologies to ensure the suitability for particular reservoirs while optimizing recovery processes and improving overall efficiency. To demonstrate this approach in practice, we present a case study using field data collected from the T oilfield in Mongolia. The estimated recovery factor based on primary and secondary recovery is in the range of 10% to 17%. Therefore, the field development plan considers the application of EOR to the T oilfield. An integrated methodology that combines EOR screening with score assignment is applied to provide a comprehensive evaluation of potential EOR technologies. The results show that the miscible carbon dioxide (CO2) injection, miscible hydrocarbon (HC) injection, and immiscible nitrogen (N2) injection methods have the highest scores without any violation of criteria. This approach ensures a thorough selection process by considering various technical factors relevant to reservoir characteristics and aligning with the study’s objective. The case study demonstrates the effectiveness of the proposed screening criteria in real-world scenarios and offers valuable insights for operators selecting EOR methods under similar conditions.

Uganda is naturally endowed with vast resources ranging from oil to precious stones including diamond among others. Venturing into exploration and development of these resources has recently taken a center stage. Currently, the Ugandan oil reservoir located in the Albertine region, Western Uganda has only been appraised and production has not begun. This study uses standard correlation equations, field analogs, and compares with existing literature to predict the future oil recovery potential of the Albertine reservoir using water flooding and water-alternating gas (WAG) as the enhanced oil recovery methods using Carbon dioxide as the injection gas. Field analogue results indicate that the oil recovery factor during primary production is 8% to 15% while the oil recovery factor during secondary production ranges from 18.2% to 62%. Simulation results show an oil recovery factor of 9.81% and 36.85% during primary and secondary production respectively. The optimum well location is 800ft from the producer with an oil recovery factor of 36.85%. Well location has an effect on over all oil recovery factor and higher recovery factor is achieved when the injection well is 800 ft from the producer. Water flooding yields 31.67% of the original oil in place (OOIP) while Carbon dioxide yields 62.30% of OOIP. When WAG injection process is preceded by waterflooding, the oil recovery factor is 5.57% higher than when WAG process is preceded by Carbon dioxide injection.

The immiscible carbon dioxide flooding process has considerable potential for the recovery of moderately viscous oils, which are unsuited for the application of thermal recovery techniques. Approximately 95% of Saskatchewan's heavy oil formations are less than 10m thick, and often have an underlying water sand. Under these conditions, thermal methods are inefficient and uneconomical due to excessive vertical heat loss and steam scavenging by the bottom water. This provides the motivation for searching an alternative to thermal recovery techniques for thin, moderately heavy oils. Laboratory research conducted in the 1950s identified several aspects of carbon dioxide flooding such as viscosity reduction, oil swelling, miscibility effects, and solution gas drive. Both laboratory and field studies have been conducted to determine the effectiveness of the carbon dioxide process for heavy oil recovery. This paper concentrates on the laboratory and field studies conducted in the past as well as the future of the immiscible carbon dioxide flooding process for the recovery of heavy oils. Introduction Moderately viscous heavy oils lack the necessary extractable hydrocarbons [C5 - C30 ] for miscible conditions with carbon dioxide to be economically attained. In some cases, moderately light oils [25–35 °API] are displaced immiscibly because the high pressures required to achieve miscibility with carbon dioxide would lead to formation fracturing. This is undesirable in that it leads to gas channeling and early carbon dioxide breakthrough. Both laboratory and field studies have been conducted to determine the effectiveness of the immiscible carbon dioxide process. Laboratory studies are used to determine and optimize the recovery process mechanisms. Field studies, both pilot and conventional, have been conducted in two modes, namely: primary and tertiary. Primary recovery methods have been the most successful to date while tertiary methods have helped greatly in reducing water and gas cuts in late flood life projects1. The objectives of this paper are to give a resume of the dominant mechanisms in the immiscible carbon dioxide displacement process, and to analyze field data in order to develop the minimum criteria for process selection. Transport of Carbon Dioxide in Heavy Oil and Reservoir Water How does the carbon dioxide mix with the reservoir fluids, namely: oil and water? Three mass transfer mechanisms are discussed in this section. Solubility is the most important mechanism of carbon dioxide transport in the reservoir. Diffusion and dispersion also affect, to a lesser extent, the transport of carbon dioxide. The most important property of heavy oil-carbon dioxide, systems is carbon dioxide solubility. "Solubility of one substance in another depends fundamentally upon the ease with which the two: molecular species are able to mix. 2 Klins3 stated: that for low pressure application [<7 MPa), the major effect would be the solubility of carbon dioxide in crude oil. The solubility of pure carbon dioxide in Lloydminster Aberfeldy 115-l7 °API] oil at 5.5 MPa and 20.6 °C is approximately 70 sm3/sm3 of oil. Solubility is a strong function of pressure, and to a lesser degree, temperature and oil composition. Solubility increases with pressure and decreases with temperature and reduced API gravity.

Application of carbon dioxide injection in shale oil reservoirs for increasing oil recovery and carbon dioxide storage

In recent years, several innovative techniques that seek to maximize total reservoir recovery have gained great interest and attention worldwide. Nanoparticles have been developed for various applications in reservoir engineering and EOR fields. Using nanoparticles for these applications refers to their small size compared to the pore throat sizes; therefore they could easily move into porous rocks without severe influence on permeability. Nanofluids; Nanoparticles Colloidal Dispersions, have been investigated as an enhanced oil recovery method. The nanoparticles, present in the three phase contact region of rock, hydrocarbon and the nanofluid, tend to form a self-assembled wedge-shaped film and force themselves between the discontinuous phase and the substrate. This wedge film acts to remove the hydrocarbon from the formation surface, which results in increasing the recovered oil much more than other conventional EOR methods. Although most of recent studies concluded that using silica nanoparticles dispersed in water results in decreased residual oil saturation after water-flooding and subsequently incremental ultimate oil recovery, the oil displacement mechanism using nanoparticles is not clearly understood yet. The focus of this study is to investigate the probable mechanism of nanoparticles dispersions to improve the recovery. In this study, silica nanoparticles dispersions were used in core flooding experiments using plugs from Bahariya formation; Egyptian sandstone formation, to evaluate the effect of four different sizes of hydrophilic silica nanoparticles with diameters range from 5 to 60 nm and concentrations range from 0.01 wt.% to 3 wt.%. Results obtained from the experiments indicate that 15–20 nm silica particles 3% wt. dispersions are highly recommended to be used as advanced EOR method as the recovered oil was more than 65% of the IOIP, just at the breakthrough point, compared with 36% recovered by water flooding. Unlike the traditional displacement mechanisms, focus on three forces: capillary, viscous and gravity, nanotechnology focuses on nano-scale forces such as disjoining force. Analysis and interpretation of the results showed that the main energies, driving the disjoining pressure mechanism, are Brownian motion and electrostatic repulsion between the nanoparticles. Particle size affects the strength of this disjoining force: the smaller the particle size, the higher the charge density, and the larger the electrostatic repulsion between particles. When this force is confined to the vertex of the discontinuous phases, displacement occurs in an attempt to regain equilibrium. These results indicate that nanofluids are expected as a future promising EOR method. This paper also summarizes the mechanism of preparing the nanofluids and the ability of exploiting Egyptian resources of pure silica sand to produce nanosilica particles with a simple and cheap method. Trial experiments have been done to prepare the nanosilica particles mechanically and the results are illustrated.

Non-thermal enhanced oil recovery (EOR) techniques show good potential for recovering oils from the thin and shaly heavy oil reservoirs of Saskatchewan. Among the non-thermal processes, immiscible carbon dioxide injection holds the most promise of accessing these reservoirs. This technique, however, is much less developed than thermal methods. The process, if proven applicable to Saskatchewan reservoirs between three and seven metres thick, will access approximately 90% of the total oil-in-place. Considering the above, a multi-client experimental research program was initiated at the Saskatchewan Research Council. The objective of this research program is to evaluate various solvents in the context of the heavy oil resource and to investigate displacement mechanisms associated with immiscible gas injection processes. This paper is divided into two sections. The first deals with the characterization of a Kindersley area heavy oil The characterization includes analysis of stock-tank oil with and without additives, recombined reservoir fluid, and reservoir fluid plus carbon dioxide. The second section describes a scaled physical model and two displacement experiments conducted using a Lloydminster area heavy oil. The laboratory phase behavior data were generated to show the effect of pressure and temperature on carbon dioxide solubility, oil density and viscosity, compressibility, and swelling factors. The addition of 73.1 sm3/m3 of carbon dioxide at 7 MPa reduced the viscosity of the reservoir fluid at 25.5 °C from 819 mPa •s to 45 mPa •s, an eighteen-fold reduction. The same reduction in viscosity by thermal methods would require healing the sample to approximately 80 °C. The above oil under similar conditions, increased in density from 963.0 kg/m3 to 974.3 kg/m3 and swelled approximately 15%. Two scaled model experiments (secondary displacements) were conducted using a 10-cycle water-alternating-gas (WAG) process with a WAG ratio of 4: 1. In each run, the total mass of carbon dioxide injected was1.41 g •mole (0.53 PV at 2.5 MPa, 0.30 PV at 4. 1 MPa). These displacements indicated the immiscible carbon dioxide WAG process to be partially sensitive to the operating pressure in the range of study. More important is the relative volume of carbon dioxide, at experimental conditions, which dictates overall performance. Introduction Carbon dioxide flooding to be the primary non-thermal recovery process that hold promise of allowing access to the typically thin reservoirs in which most of Saskatchewan's heavy oil is found. Thermal methods are often inefficient and uneconomical because of excessive vertical heat losses, due to thin pay zones, and steam-scavenging by bottom water zones. Carbon dioxide may behave as a miscible or immiscible fluid when contacted with oil at reservoir conditions. For petroleum reservoirs, Holm(1) defines miscibility as that physical condition between two or more fluids that will permit them to mix in all proportions without the existence of an interface. If two or more fluid phases form after some amount of one fluid is added to others, the fluids are considered immiscible and an interfacial tension exists between the phases. Therefore, miscible displacement may not be applicable to all reservoir fluids.

In this study, we experimentally investigated the effects of chemically enhanced oil recovery methods containing hydrolyzed polyacrylamide (HPAM), surfactant–hydrolyzed polyacrylamide (SHPAM), surfactant nanofluids (SNF), that is, coupled with carbon dioxide (CO2) and water chase injection to measure enhanced oil recovery methods in a sandstone reservoir. To proceed with the experiments, we performed four flooding tests at the simulated reservoir temperature of 70 °C. The sand packs were saturated with oil to establish the irreducible water saturation (Swr). Then, the fluid flow in sand packs remained undistributed for about 5 days to obtain the 1.5 pore volume (PV). We observed that the pressure drop had small fluctuations when there was waterflooding (until 1.5 PV), and after injecting the chemical agents, the pressure drop had a sharp rise. It is indicated that the chemical solution has implemented higher pressure drops (significant energy efficiency) to displace the oil instead of water. The maximum oil recovery factor was about 53% and 59% when HPAM and SHPAM solution displaced oil after waterflooding, respectively; however, it is observed that water chase flooding recovered about 8% and 14% of remaining oil in place while CO2 has increased only 3% and 5%, respectively. SNF solution can provide more oil recovery factors. It is about 72% (SNF with 0.5 wt%) and 67% (SNF with 1 wt%). We observed that water chase flooding recovered about 20% of oil in place while CO2 increased by only 8%. It was concluded that the SNF solution with 0.5 wt% tends to adhere to the water–CO2 and causes to improve oil recovery factor after SNF injection. Therefore, SNF is the optimum enhanced oil recovery method among other chemical agents. On the other hand, with the decrease in CO2 flow rate and increase in silica nanoparticles slug size, pressure drop has started to decrease in higher pore volume injections, indicating that larger volumes of CO2 can be stored in sand packs. However, by increasing the CO2 flow rate and decreasing silica nanoparticles slug size, CO2 can escape easily from the sand pack.

This work addresses the pressure transient behavior of horizontal gas injection well in low permeable reservoirs. Low permeable reservoirs such as shale oil reservoirs have been receiving great attentions lately which normally require hydraulic fracturing and horizontal well development to maximize the oil production. However, the primary recovery factor of shale oil reservoirs is still low and has been estimated to be below 10–15% due to tight nature of the shale formations. Enhanced oil recovery method such as miscible carbon dioxide (CO2) injection is said to be one of the most efficient and effective methods used to increase the oil recovery factor of a low permeable shale oil reservoir. The objective of this paper is to study the pressure transient behavior of the horizontal gas injection well in low permeable shale oil reservoirs using numerical simulator, CMG-GEM. Flow regimes and its significant reservoir parameters are investigated from the log-log plot of pressure-derivatives. It is found that a unit-slope line is developed on pressure-derivative log-log plot at early time due to the gas compressibility effect, followed by early radial flow and early linear flow regimes. The effect of various parameters such as gas injection rate, duration of gas injection, well location and well perforation length are studied and analyzed on the changes of pressure transient characteristics. It is identified that gas injection rate affects the pressure-derivative response significantly at middle time due to gas mobility and viscosity; whereas well location and well perforation length affect the late time pressure-derivative response which relate to dominant boundary effect; however, duration of gas injection is not able to show or prove any impacts on the pressure-derivative behavior due to numerical instability issue. Reservoir characteristics such as average permeability and skin can be identified from the flow regimes equations similar to the horizontal production well.