Experimental Investigation of Injection Pressure and Permeability Effect on CO2 EOR for Light Oil Reservoirs

The concern over fossil energy shortage for the next decade leads to the extensive research activities in the area of enhanced oil recovery. Steam injection as one of well known EOR process has been used for about five decades to improve the oil production rate and recovery efficiency. Steam flooding is applied to heavy and extra-heavy oil reservoirs; however it could be used in light oil reservoirs in which water injection do not work effectively. Regardless of different performances, this method is an efficient EOR process for both heavy and light oil reservoirs. In this work, two separate numerical models were prepared to investigate steam flooding performance for the recovery of light and heavy oil. The heavy oil model is a Cartesian hypothesis model with properties of Cold Lake heavy oil reservoir in Canada and light oil model is a sector of an Iranian fractured light oil reservoir. For this purpose, steam flooding was implemented in these two models separately. Then according to software options, all possible recovery mechanisms (viscosity reduction, steam distillation, thermal oil expansion and others) were simulated individually to measure the effectiveness of each recovery mechanism in total recovery of heavy and light oil during steam flooding. Also, operational parameters such as steam quality, steam flow rate and well perforation were optimized for both reservoirs. Results show that steam flooding performances in heavy and light oil reservoirs are different. Heavy oil reservoirs do not response fast to steam compared to the light oil reservoirs. Furthermore, viscosity reduction is a main recovery mechanism in recovery of heavy oil and contribute to 80% of total recovery, while in recovery of light oil all three main recovery mechanisms have the same contribution to total recovery. It was also found that the optimized operational parameters are different for each reservoir.

The miscible gas injection has been a successful technique to overcome the low oil recovery by improving the oil mobility due to viscosity reduction. While many experimental studies defined the fundamentals of gas injection in heavy oil reservoirs, experimental studies of gas injection into condensate oil reservoirs are scarce. Therefore, this study provides a comprehensive investigation of the impact of the injection pressure and reservoir permeability on the efficiency of CO2 to improve oil recovery from oil condensate reservoirs. The efficiency of the injected gas at different injection pressure into different permeability rocks is evaluated as a function of the recovery factor and the viscosity reduction experimentally. Miscible gas injection experiments of different shale rock samples with different permeabilities saturated with condensate oil were conducted at 5 different injection pressures. The recovery factor will be used to investigate the effect of injection pressure in two distinctly saturated rock samples. These samples are saturated with condensate oil from the Eagle Ford formation. The Minimum Miscible Pressure is predicted from the compositions of the fluids, which is determined using gas chromatography. The gas is injected at different pressures, and the recovery factor is calculated at the gas breakthrough, the end of the injection (Injecting 3 PV), and at the abandonment pressure (100 psi). The viscosity of the collected oil at the end of each run is measured to determine the viscosity reduction value. The experimental results proved the success of CO2 injection in improving condensate oil production. A proportional relationship between the injection pressure and the recovery factor was observed. Moreover, a proportional relation was observed between the production and the permeability. However, the permeability and the viscosity reduction were observed to be inversely proportional. This observation was extended to the immiscible injection, where the oil viscosity was reduced by a small percentage. This reduction is translated to an existence of some level of miscibility within the pores of the lower permeability sample. This phenomenon could be caused due to the higher nanopore confinement pressure in the lower permeability samples.

High-pressure air injection (HPAI) is an enhanced oil recovery (EOR) process in which compressed air is injected into a deep, light-oil reservoir, with the expectation that the oxygen in the injected air will react with a fraction of the reservoir oil at an elevated temperature to produce carbon dioxide. Over the years, HPAI has been considered a simple flue-gas flood, giving little credit to the thermal drive as a production mechanism. The truth is that, although early production during a HPAI process is mainly due to re-pressurization and gasflood effects, once a pore volume of air has been injected the combustion front becomes the main driving mechanism. This paper presents laboratory and field evidence of the presence of a thermal front during HPAI operations, and of its beneficial impact on oil production. Production and injection data from the Buffalo Field, which comprises the oldest HPAI projects currently in operation, were gathered and analyzed for this purpose. These HPAI projects definitely do not behave as simple immiscible gasfloods. This study shows that a HPAI project has the potential to yield higher recoveries than a simple immiscible gasflood. Furthermore, it gives recommendations about how to operate the process to take advantage of its full capabilities. Introduction High-Pressure Air Injection (HPAI) is an emerging technology for the enhanced oil recovery (EOR) of light oils that has proven to be a valuable process, especially in deep, thin, low-permeability reservoirs(1-7). A number of successful high-pressure air injection projects in light oil reservoirs have been documented in the literature(8-10). Most of these projects have been operating for many years, attesting to their technical and economic success. The improvement in recovery of light oil by HPAI involves a combination of complex processes, each contributing to the overall recovery. These processes include flue gas sweeping, field re-pressurization, oil swelling, viscosity reduction, stripping of the lighter components of the oil, and thermal effects. Early production during the HPAI process is related to re-pressurization and gasflood effects; hence, the influence of the thermal zone is secondary during the early life of an injector. The oil displaced directly by the thermal front will depend on the effectiveness of the generated flue gas on oil displacement from outside the thermal region.

Aim: Polymer flooding is a promising chemical enhanced oil recovery. Originally it was thought that polymer flooding was not economical. The polymer flooding in Daqing field China has proved otherwise. After that, it was thought that polymer flooding could only be successful in light oil reservoirs, but then polymer flooding was implemented in Pelican field in Canada on a large scale and recorded success.
 Methodology: The methodology employed was to review polymer flooding from inception, beginning from the work of Kingsley Detling in 1944 who got a patent in the USA to late 1970’s, thus early history of polymer flooding was a good insight for this paper. The mechanism of polymer flooding was also captured; improving the mobility ratio of water with a water soluble polymer is what helps for better sweep efficiency. The successful polymer flooding in Daqing field China has made many companies to understand this technology and go for polymer flooding. Polymer flooding of Daqing field has helped China’s oil and gas industry. Polymer flooding is now used to recover heavy oil especially for deep reservoirs with thin pay zone. Pelican field in Canada has carried out the largest polymer flooding implementation in the world and has proven that polymer flooding can be used for heavy oil and given a new screening parameter for polymer flooding. 
 Results: This review has captured the critical aspects of polymer flooding both in light oil reservoirs-Daqing field, China and heavy oil reservoirs-Pelican field, Canada.
 Conclusion: This review has proven that polymer flooding is a promising Chemical Enhanced Oil Recovery technology in both light oil and heavy oil reservoirs and it is used to increase the ultimate recovery of some fields and could help any country to remain relevant in the oil and gas sector. Using polymer flooding to recover heavy oil proves more efficient and more economical. Because, polymer flooding does not require a lot of heat as in thermal flooding, there is reduction in global green house gas effect.
 Recommendation: It is recommended that companies use polymer flooding to recover their oil from light oil reservoirs and most importantly increase production and recovery in heavy oil fields.

A new air injection technique, low temperature oxidation (LTO) process for residual light oil recovery, is described. Improved oil recovery from deep, light oil reservoirs is achieved by removing the oxygen in the injected air by LTO reactions with the residual oil in the reservoir. The product of the LTO reactions is a "flue gas", which displaces the oil. Preliminary results of LTO reaction kinetics and oil recovery have been obtained using four North Sea light oils. THAI - "Toe-to-Heel" Air Injection, is a new EOR process, which integrates advanced reservoir technology and horizontal well concepts, to achieve potentially very high recovery of heavy oil. It can also realise very substantial in situ upgrading by thermal cracking, producing upgraded oil to the surface. The process operates in a gravity stabilised manner by restricting drainage to a narrow mobile zone. This causes the flow of mobilised fluids to enter directly into the exposed section of a horizontal production well. The process can be operated on primary production, as a new technology, as a follow-up to existing technologies, or as a co-process where the advantages of high thermal efficiency are required. This is achieved by concentrating the energy required for oil mobilisation, recovery and thermal upgrading in the reservoir. Combined with clean technology design, THAI offers a pathway to future economic success for the heavy oil industry.

This paper describes a steam-distillation drive pilot project being conducted in the Shiells Canyon Field to determine the effectiveness of steamflooding a light-oil reservoir. Overall oil recovery for the project has been good, with a reduction in oil saturation from a preflood value of 45% to less than 5% in the steam-swept zone. Introduction Thermal recovery techniques normally are applied to heavy-oil or tar-sand reservoirs in an effort to reduce viscosity and mobilize oil; however, steamflooding also can be an effective recovery technique for light-oil reservoirs. In this application, steam distillation of crude oil in the steam zone becomes an important recovery mechanism. In addition, the solvent generated in the steam zone will condense ahead of the steam front and enhance other recovery mechanisms. The application of this process to light-oil reservoirs commonly is referred to as the "steam-distillation drive process" because of the large amount of solvent generated by steam distillation in the steam zone. However, crude oil of original gravity is produced during the major portion of the flood life, and produced during the major portion of the flood life, and solvent production occurs only during the time just before steam breakthrough in the producing wells.Steam distillation has been recognized in the literature as a major recovery mechanism during steamflooding of light- and heavy-oil reservoirs. Farouq Ali estimated that 10% of the heavy oil recovered by steamflooding can be attributed to steam distillation and that as much as 60% of the light-oil recovery with steamflooding can be attributed to the same mechanism. Wu and Brown showed that up to 65% of some light oils could be recovered by steam distillation. In a field test of the steam-distillation drive process in a light-oil (0.910 g/cm3 or 24 degrees API) reservoir, Volek and Pryor reported residual oil saturations in the steam-swept zone of less than 8%. Encouraged by the potential of the steam-distillation drive process, a pilot project was initiated on March 3, 1973, in Zone 203 of the Shiells Canyon Field, Ventura County, CA. The Shiells Canyon Field was selected for application of this process because of the volatile (0.855 g/cm3 or 34 degrees API) nature and low viscosity (0.006 Pa s or 6 cp) of the crude oil. In addition, the 35 degree dip of the formation is ideal for an expanding steam-vapor/gas-cap recovery mechanism. Here, experimental laboratory work used for designing the process is presented with the design and evaluation of the field pilot. Process Process The steam-distillation drive process has been characterized in the literature as four fluid regions progressing radially from the injection well. Oil saturation progressing radially from the injection well. Oil saturation and displacement mechanisms are characteristically different in each zone (Fig. 1). In the formation fluid bank, saturation approaches the initial oil saturation. In the cold-condensate zone, displacement is representative of a waterflood; however, oil saturation in this zone is greater than the initial oil saturation because of the amount of oil displaced from the hot-condensate and steam zones. In the hot-condensate zone, waterflood recovery improves because of thermal swelling, viscosity reduction, and solvent extraction. JPT P. 546

High-Pressure Air Injection (HPAI) is an EOR process in which compressed air is injected into a deep, light-oil reservoir, with the expectation that the oxygen in the injected air will react with a fraction of the reservoir oil at an elevated temperature to produce carbon dioxide. Over the years, HPAI has been considered as a simple fluegas flood, giving little credit to the thermal drive as a production mechanism. The truth is that, although early production during a HPAI process is mainly due to repressurization and gasflood effects, once a pore volume of air has been injected the combustion front becomes the main driving mechanism. This paper presents laboratory and field evidence of the presence of a thermal front during HPAI operations, and its beneficial impact on oil production. Production and injection data from the Buffalo Field, which comprises the oldest HPAI projects currently in operation, were gathered and analyzed for this purpose. These HPAI projects are definitely not behaving as simple immiscible gasfloods. This study shows that a HPAI project has the potential to yield higher recoveries than a simple immiscible gasflood. Furthermore, it gives recommendations on how to operate the process to take advantage of its full capabilities. Introduction High-Pressure Air Injection (HPAI) is an emerging technology for the enhanced oil recovery of light oils that has proven to be a valuable process especially in deep, thin, low permeability reservoirs 1 -7. A number of successful high-pressure air injection projects in light oil reservoirs have been documented in the literature 8–10. Most of these projects have been operating for many years, attesting to their technical and economic success. The improvement in recovery of light oil by HPAI involves a combination of complex processes, each contributing to the overall recovery. These processes include: flue gas sweeping, field re-pressurization, oil swelling, viscosity reduction, stripping of the lighter components of the oil, and thermal effects. Early production during the HPAI process is related to re-pressurization and gasflood effects; hence, the influence of the thermal zone is secondary during the early life of an injector. The oil displaced directly by the combustion front will depend on the effectiveness of the generated flue gas on oil displacement from outside the thermal region. For many years, there has been some discussion regarding the effective driving mechanisms associated with the HPAI process; some authors have assumed it is essentially attributable to the in-situ generated flue gas displacement and consequently the process is analogous to a flue-gas injection, while others recognize the thermal nature of the process. Clara et al.11, explained the air injection technique applied to light-oil reservoirs, and proposed a laboratory strategy for evaluation of an air injection project. It was stated that regardless of the oxidation zones, the air injection process in a light oil reservoir is comparable to a flue-gas injection process. Hunedi et al.12, presented results of an exhaustive EOR screening based on successful field trials and physics of the oil recovery mechanisms for each method; with the possibility to be applied in eight oil fields (30.2 to 41.3 ° API) in the Euphrates Graben.

Since 1950s In-Situ Combustion (ISC) has been applied to mainly heavy-oil reservoirs. In recent years, High Pressure Air Injection (HPAI) which is a displacement process categorized as ISC, is applied to light-oil reservoirs. And it has proven to be a valuable Enhanced Oil Recovery (EOR). Reduction of oil viscosity is very important for ISC process. In contrast, it is not so essential for HPAI because original viscosity of light-oil is not as high as that of heavy oil. HPAI is considered as flue gas injection, since a flue gas sweep is one of the most important recovery factors of HPAI. However a flue gas sweep recovery factor is not effective for highly water saturated light-oil reservoirs, while thermal effects become an important recovery mechanism. This paper discribed the feasibility study of HPAI for watered out light-oil reservoirs, oil recovery mechanism and several simulation studies to establish maximum oil recovery factor. For the feasibility study, Combustion Tube tests (CT tests) and simulation studies were conducted. The oil recovery was observed in the CT test with crushed core which was flooded out by water. This result suggests that HPAI can be applied to highly water saturated light-oil reservoir. The results of simulation studies also indicate its feasibility. They also made clear that distillation process that was one of thermal effects of HPAI was a main recovery factor for a HPAI in this case. In order to maximize the oil recovery, controlling a channeling of injected air is important because early breakthrough of the air reduces oil production period significantly. The results of our studies show that not only a design of well completion but also an adjustment of air injection rate enable to increase vertical sweep efficiency and that line drive injection is effective to increase areal sweep efficiency.

Recently, carbon capture, utilization, and storage (CCUS) with enhanced oil recovery (EOR) have gained a significant traction in an attempt to reduce greenhouse gas emissions. Information on pore-scale CO2 fluid behavior is vital for efficient geo-sequestration and EOR. This study scrutinizes the behavior of supercritical CO2 (sc-CO2) under different reservoir temperature and pressure conditions through computational fluid dynamics (CFD) analysis, applying it to light and heavy crude oil reservoirs. The effects of reservoir pressure (20 MPa and 40 MPa), reservoir temperature (323 K and 353 K), injection velocities (0.005 m/s, 0.001 m/s, and 0.0005 m/s), and in situ oil properties (835.3 kg/m3 and 984 kg/m3) have been considered as control variables. This study couples the Helmholtz free energy equation (equation of state) to consider the changes in physical properties of sc-CO2 owing to variations in reservoir pressure and temperature conditions. It has been found that the sc-CO2 sequestration is more efficient in the case of light oil than heavy oil reservoirs. Notably, an increase in temperature and pressure does not affect the trend of sc-CO2 breakthrough or oil recovery in the case of a reservoir bearing light oil. For heavy oil reservoirs with high pressures, sc-CO2 sequestration or oil recovery was higher due to the significant increase in density and viscosity of sc-CO2. Quantitative analysis showed that the stabilizing factor (ε) appreciably varies for light oil at low velocities while higher sensitivity was displayed for heavy oil at high velocities.

Experimental evaluation of the performance of carbonated water injection (CWI) under various operating conditions in light oil systems

This paper discusses the reduction of heavy oil viscosity by carbon dioxide injection for improved oil recovery (IOR). Carbon dioxide injection is recognized as a viable injection gas for reservoir stimulation in light oil (30° API or higher) reservoirs. Carbon dioxide is also applicable in heavy oil (10 to 25° API) reservoirs since it lowers oil viscosity, swells the oil, provides component extraction, and is soluble in both oil and water. Carbon dioxide sources include natural reservoirs, extraction of carbon dioxide from industrial processes, generation by oxygen combustion in reservoirs, and thermo-converter generation at the surface. The surface-combustor provides Carbon Dioxide in areas which lack sufficient supplies and require the transportation of Carbon Dioxide by pipeline or high pressure trucks. Research and development of this versatile surface and downhole combustors continue today at several U.S. Universities. IOR benefits. The benefits of using Carbon Dioxide include crude oil and water swelling, component extraction, oil viscosity reduction, and reservoir pressuring. An article by Simon and Graue(1) in 1965 indicates that carbon dioxide solution in crude oil lowers the viscosity to approximately 0.02 to 0.12 of the oil's original viscosity at 120°F. They studied 5 oils which were below 20°API and had viscosities from 58.6 to 1300 cp at 120°F. The result of their study indicates viscosity reductions from 0.025 to 0.115 at a pressure of 1000 psia. A 1986 topical report by Chung (2) reported on the viscosity reduction in 7 heavy oils which ranged from 10°API to 21.6°API. The oil viscosities ranged from 49 to 1484 cp at various temperatures (75 to 200°F). Chung observed viscosity reductions from 0.03 to 0.15 of the original oil viscosity.

Steamflooding has been widely applied as an effective way to improve oil recovery not only in heavy oil reservoirs, but also in light oil reservoirs. Its efficiency comes from its influential rule to enhance oil displacement by flourishing the reservoir and fluid properties. Also, it has been investigated that Steamflooding is a good way to handle the formation's heterogeneity by decrease the degree of fluid spread and distortion. The reservoir under study is a sandstone formation in South Rumaila oil field located in Iraq. This field, with a 59-years production history, has 40 production wells and is surrounded by an infinite active edge water aquifer from the east and the west flanks. The east flank is much less effective than the west one because there are some discontinuous amounts of bitumen close to the oil-water contact that impedes the aquifer water approaching into the reservoir. The formation depth is 10350 ft. sub-sea with a maximum vertical oil column of 350 ft. The average bubble point pressure is 2660 psi and the average reservoir temperature is 210°F while oil density is 34°API. In this study, a comparative thermodynamic simulation study has been conducted to investigate the feasibility of Steamflooding to extract the bitumen and improve oil recovery and also to determine the optimal future reservoir performance with comparative designs of experiments considering the recovery factor as a response function. Firstly, the thermodynamic reservoir simulator (CMG-STARS) has been used to figure out the feasibility of steam flooding to increase the recovery factor by the end of 12 years future prediction period in comparison with the base case of primary production. Then, nine different experiments within three-levels & four-factors have been set within the orthogonal arrays design (OAD) to get some idea about the factors controlling the reservoir performance. The factors are steam injection rate, steam quality, steam temperature, and number of steam injectors. The regression model of Orthogonal Arrays Design (OAD) has shown that the recovery factor is sensitive only to steam injection rate and number of injectors and the optimal scenario has the highest steam injection rate and the lowest injectors to get the highest recovery factor. Then, the Full Factorial Design (FFD) has been adopted for the same factors, but with distinct levels to formulate 36 high dispersion experiments. The levels of injectors have been selected based on the high connectivity with the producers based on the streamlines-based simulation results after construction such a connectivity matrix between the injectors and producers. The regression analysis of FFD has shown that all the four factors and some interaction among them have a significant effect on the response and the optimal scenario that has the highest recovery factor, has the same levels of the four parameters as what has been obtained from the OAD approach. This reflects the feasibility of Orthogonal Arrays Design to handle the Steamflooding process and determine the optimal future reservoir performance with optimal scenario at small number of experiments.

A new air injection technique, low temperature oxidation (LTO) process, is described. Improved oil recovery from deep, light oil reservoirs is achieved by removing the oxygen in the injected air by LTO reactions with the residual oil in the reservoir. The product of the LTO reactions is a "flue gas," which displaces the oil. Preliminary results of LTO reaction kinetics and oil recovery have been obtained using four North Sea light oils. The paper also contains some discussion of the safety issues related to air injection offshore. Introduction Gas injection into light oil reservoirs is a proven improved oil recovery IOR technique. The IOR potential for gas injection in the United Kingdom Continental Shelf (UKCS) has been estimated at 1.4 bSTB(1). However, the application of gas injection is limited by gas availability and cost, particularly for many mature fields, with the prospect of abandonment unless economic methods can be developed to extend the field life. Therefore, there is now growing interest in air injection because of its availability. Air injection has been widely used in the past for production of viscous heavy oils, where the heat generated by in situ combustion is a necessary part of the recovery process. Air injection can also be used for the recovery of light oils, but in this case, heat generation is not necessary for the displacement. Some form of oxidation is only required in order to remove the oxygen from the air and prevent it from reaching the production wells. Yannimaras et al.(2) have discussed the benefits of air injection for IOR from deep, light oil reservoirs, wherein the principle objective was to generate flue gas (85﹪ N2, 15﹪ CO2) by in situ combustion. There are a number of ongoing successful air injection field projects, notably in the West Hackberry Field, Louisiana [Amoco(3)]; in Medicine Pole Hills Unit, North Dakota; Buffalo, South Dakota [Koch(4)]; most recently, in the Horse Creek Field, North Dakota [Total(5)]; and Total's proposed LTO pilot test in the H Field in Indonesia(6). In the latter case, core flooding studies were undertaken to investigate the effect of various parameters on oxygen uptake by the oil. Previous field projects and simulation studies have considered that high temperature oxidation (HTO, or in situ combustion) is needed to remove the oxygen and enhance oil recovery. Christopher(7) [see also Yannimaras et al.(8)] used an accelerating rate calorimeter (ARC) to screen light reservoir oils for continuous exothermicity. For light oils they found that about 20﹪ were good candidates for propagating full in situ combustion. This suggests that perhaps a majority of light oils will sustain only low temperature oxidation (LTO). Thus, when the primary objective is only to generate nitrogen and carbon dioxide in situ, then a less intensive oxidation process, without combustion, is sufficient. The focus is therefore on a spontaneous LTO process, which can be applied in all light oil reservoirs with sufficiently high reactivity to react with (and consume) oxygen in the injected air.

Production from tight formation resources leads the growth in U.S. crude oil production. Compared with chemical flooding and water flooding, gas injection is a promising EOR approach in shale reservoirs. A limited number of experimental studies concerning gas flooding in the literature focus on unconventional plays. This study is a laboratory investigation of gas flooding to recover light crude oil from nano-permeable shale reservoirs. In this work, the N2 flooding process was applied to Eagle Ford core plugs saturated with dead oil. To investigate the effects of flooding time and injection pressure on the recovery factor, two groups of core-flood tests were performed. In group one, flooding time ranged from 1 to 5 days in increments of 1 day; in the other group, the injection pressure ranged from 1,000 psi to 5,000 psi in increments of 1,000 psi. The experimental setup was monitored using X-ray CT that helped to visualize phase flow and estimate the recovery efficiency during the test. The potential of N2 flooding for improving oil recovery from shale core plugs was examined, and the recovery factor (RF) of each case was presented. The results from group one showed that more oil was produced with a longer flooding time. However, the incremental RF decreased with the increase of flooding time. The oil recovery was significant at the initial period of the recovery process, and a longer flooding time had less effect on extracting more oil. With flooding time constant in 1-day, the results from the second group indicated that RF increased with injection pressure, especially rising pressure, from 1,000 psi to 2,000 psi. The gas breakthrough time became shorter with the increase of injection pressure. The analysis of the CT number showed that the oil recovery process mainly occurred before the gas breakthrough. Once a fluid flow path was established, the injected gas flowed through the limited communication channels; thus, no extra oil could be extracted without increasing the injection pressure. This experimental study illustrates that gas flooding has liquid oil production potential in shale reservoirs.

Combined benefits of capillary barrier and injection pressure control to improve fluid recovery at breakthrough upon gas injection: An experimental study