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The gas assisted gravity drainage process is designed to take advantage of gravity between the injected gas and reservoir crude oil due to the difference in their densities. In this experimental study, a 2-D Hele-Shaw physical model with dimensions of 15 × 66 × 3 cm was packed with uniform and different sand packs to conduct visual experiments of C...
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... though gravity segregation has been understood for a long time, the new GAGD process involves injecting the gas, preferably CO 2 , from vertical wells at the top of the payzone and producing oil from a horizontal well located at the bottom of the payzone (Rao, 2001). Figure 1 shows a schematic of the GAGD process. ...
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Modeling experiments of oil charging were conducted to find out patterns and affecting factors of oil migration and seepage in tight reservoirs, and analyze oil migration and accumulation and low limit conditions of tight oil accumulation using core samples from tight reservoir beds of the Permian Lucaogou Formation in the Jimsar Sag of the Junggar...
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... The GOC can move down steadily and expand horizontally, and the oil is pushed to the horizontal well above the GOC. 5 Theoretical research and eld practice has demonstrated that GAGD can inhibit viscous ngering and increase swept volume and ultimate recovery factor. [6][7][8][9] GAGD is inuenced by many factors, [10][11][12][13] including heterogeneity, wettability, and water saturation of the reservoir, uid property, gas injection rate, and oil recovery factor. Dominant seepage zones or dominant seepage paths frequently occur in the reservoirs with high heterogeneity, leading to early gas breakthrough and sweep efficiency reduction during CGI or WAG. ...
Gas-assisted gravity drainage (GAGD) is an effective method for oil recovery. Gravity increases the stability of the Gas-Oil Contact (GOC), thus delaying gas breakthrough and promoting crude oil production. Studying the effects of fluid and reservoir parameters on the stability of GOC could help understand the mechanism of GAGD. In this study, a series of high-pressure GAGD tests were conducted on a 3D heterogeneous scaled model established according to the heterogeneity of the oil reservoir. During the tests, GOC was monitored with electrical resistivity tomography (ERT) to study the effects of gas injection rate, gas type, and gas injection direction on GOC and oil recovery factor (RF). The results showed that N2-GAGD achieved the most stable GOC, the largest sweep volume but a poor RF. CO2-GAGD achieved the best RF of 63.33% at the injection rate of 0.15 m d-1 under 15 MPa. CO2 and CH4 could interact with crude oil and reduce the advancing rate and transverse swept area of GOC. CO2 and CH4 could lead to a higher RF as they reduce the viscosity of crude oil, cause swelling when dissolved, and have low tension. Therefore, the effects of gas dissolution, swelling, and viscosity reduction must be considered in addition to those of gravity, viscous force, and the capillary force so that RF could be increased while ensuring the stability of the displacement front. Accordingly, a new non-dimensional number N new was proposed with comprehensive considerations of gravity, viscous force, capillary force, gas-oil viscosity ratio, the viscosity reduction by gas, and reservoir properties. Finally, a prediction model was proposed, which could accurately predict the RF of heterogeneous reservoirs applying GAGD.
... Major results reported by researchers in this field could be classified into two general categories: first, increasing the model height and decreasing capillary pressure improve the process efficiency; second, the presence of a driving viscous force leads to earlier breakthrough and can improve the ultimate recovery factor (i.e., forced gravity drainage). Notably, lower recovery factor by increasing the gas injection rate is also reported after a critical gas injection rate (Rostami et al. 2010;Akhlaghi et al. 2012;Saedi et al. 2015;Zobeidi et al. 2016). Firoozabadi and Markeset (1992) and Firoozabadi and Markeset (1994) used spacers of different thicknesses (up to 1.2 mm) as horizontal fractures in a multi-stack block system. ...
Gravity drainage is known as the controlling mechanism of oil recovery in naturally fractured reservoirs. The efficiency of this mechanism is controlled by block to block interactions through capillary continuity and/or reinfiltration processes. In this study, at first, several free-fall gravity drainage experiments were conducted on a well-designed three-block apparatus and the role of tilt angle, spacers’ permeability, wettability and effective contact area (representing a different status of the block to block interactions between matrix blocks) on the recovery efficiency were investigated. Then, an experimental-based numerical model of free-fall gravity drainage process was developed, validated and used for monitoring the saturation profiles along with the matrix blocks. Results showed that gas wetting condition of horizontal fracture weakens the capillary continuity and in consequence decreases the recovery factor in comparison to the original liquid wetting condition. Moreover, higher spacers’ permeability increases oil recovery at early times; while, it decreases the ultimate recovery factor. Tilt angle from the vertical axis decreases recovery factor, due to greater connectivity of matrix blocks to vertical fracture and consequent channelling. Decreasing horizontal fracture aperture decreases recovery at early times but increases the ultimate recovery due to a greater extent of capillary continuity between the adjacent blocks. Well-matched observed between the numerical model results and the experimental data of oil recovery make the COMSOL multi-physics model attractive for application in multi-blocks fractured systems considering block to block interactions. The findings of this research improve our understanding of the role of different fracture properties on the block to block interactions and how they change the ultimate recovery of a multi-block system.
... This residual oil remains in reservoirs' porous medium due to the capillary trapping mechanism in the rock. IFT is one of the effective parameters on capillary pressure and surfactants are the most effect on these parameters [1][2][3][4][5]. ...
Since most of the world's oil reservoirs are in the second half lifetime, the use of Enhanced Oil Recovery (EOR) methods is inevitable. Interfacial Tension (IFT) is one of the effective parameters on EOR can be changed by surfactants. But surfactant injection is one of the costly methods and chemistry of the surfactant solutions such as salinity (one and two valance ions) and pH should be engineered. Furthermore, the temperature is an effective parameter affecting on IFT.
In this study, the effect of salinity, especially hard salinity, temperature and pH on IFT between Triton X-100 surfactant and an Iranian oil sample has been investigated.
In order to, evaluate the effect of salinity, different concentrations of NaCl, CaCl2, MgCl2, and Na2SO4 salts (0, 0.1, 0.5, and 1 wt.%) were used in different concentrations of surfactant. IFT results showed that magnesium and calcium divalent cations had a greater effect on IFT reduction than monovalent sodium cation. Also, all the studied cations were more effective than sulfate as a divalent anion. The ionic strength of the solutions was inversely proportional to the IFT amounts. Less value of IFT in the presence of magnesium ions than calcium ions was due to the higher ionic strength of solutions containing magnesium compared with calcium.
IFT results at three temperatures (20, 40, and 60 °C) proved that by increasing temperature IFT increased.
Also, the effect of pH on IFT in three pHs including acidic, almost neutral and alkaline in the presence of surfactant was studied. Results indicated that IFT decreased with increasing pH, especially in concentrations lower than critical micelle concentration (CMC).
... During the years, CO 2 injection has considered an efficient tool particularly for light crude oils (Akhlaghi, Kharrat, and Mahdavi 2012;Idem and Ibrahim 2002). Unfortunately, besides the effectiveness of such an injection for the production of more oil from the depleted reservoirs, CO 2 injection introduces some drawbacks such as asphaltenes precipitation which faced the petroleum men with a serious problem during oil production (Cao and Gu 2013;Srivastava, Huang, and Dong 1999). ...
Pendant drop method is employed to investigate interfacial tension, bond number, and swelling behavior of crude oil in the presence of brine solutions comprised of MgSO4 and its solution saturated with carbon dioxide (CO2) (i.e. carbonated MgSO4 solution) in different temperatures and pressures, up to 80°C and 4000 psi. The results reveal that as the temperature increases, the measured dynamic IFT values getting more close to each other. In detail, the measured dynamic IFT values for the temperature of 30°C are wider than those measured for the temperature of 80°C. Besides, the results demonstrated that not only the dissolution of brine in carbonated brine can reduce the swelling factor which means a barrier against the better dissolution of carbon dioxide into the drop phase but also this salt dissolution can shift the crossover pressure toward the lower values of around 1000 psi from its original value of around 2000 psi. Moreover, examining the effect of pH reveal that at low pH value (i.e., 3.5), a reduction of about 7.6 mN/m in IFT values can be obtained. In sum up, it was deduced that the addition of CO2 which reduced the acidity of the aqueous phase due to the formation of carbonic acid caused the interruption of ionization of basic natural surfactants, consequently causing a significant diminish of IFT reduction compared to IFT of crude oil/brine solution. In addition, at a constant temperature, the presence of more CO2 to the aqueous phase at higher pressures leads to IFT reduction as a function of pressure. Moreover, the results confirm that at pressures lower than the crossover point, the effect of temperature variation on the swelling is insignificant but at pressures higher than crossover point swelling factor increases as a function of temperature. Furthermore, the results reveal that the dissolution of salt into the carbonated water reduces the crossover pressure. As the last point, the measured swelling factor revealed that the presence of CO2 combined with the effect of temperature may lead to an ultimate swelling factor of about 1.32 which means 32% enhancement in the initial volume of the drop oil as it is contacted to the carbonated brine under the temperature of 80°C.
... The gravity drainage theory was put forward by Cardwell and Parsons (1949). Sharm (2008) and Akhlaghi et al. (2012) conducted 2D visual experiments to simulate the dimensionless parameters used in field projects. They found that the gravity number, the bond number and dimensionless time had great influences on GAGD performance. ...
Many factors will affect the result of nitrogen-assisted gravity drainage (NAGD). In this work, sandpack and 2-dimensional (2D) visual plate model were employed to investigate the influence factors of NAGD, such as gas cap volume, formation dip angle, and back pressure. Nitrogen foam was also studied to improve the gas channeling and breakthrough. The experimental results indicated that the gas cap volume was the most significant influence factor on the oil recovery. With the increase of the gas cap volume, the oil recovery increased first and then decreased, and finally increased. The NAGD had a better performance in big dip angle of formation. There was a critical value of back pressure to obtain the maximum oil recovery. However, the gas channeling was intensely observed by experiments of both sandpack and 2D visual plate model. Fortunately, nitrogen foam could effectively inhibit the gas channeling and improve the result of NAGD.
... GAGD using CO2 gas, in addition to improving the oil recovery, is applicable for sequestration of carbon dioxide, which gains to less CO2 emission into the atmosphere and helps to decrease the global warming. Unfortunately, CO2 sequestration is not commercialized yet, because of the high costs of CO2 gas extraction from flue gas of power plants [90]. Most of the CO2 that is used in EOR projects is from natural sources such as the natural CO2 reservoirs in Colorado, United States, from where the CO2 gas is being piped to West Texas. ...
Since developing the first discovered reservoirs in the United States with sucker rod pumps to the modern deep-water oil production in frozen arctic areas, we concern the improvement of hydrocarbon recovery. Improved Hydrocarbon Recovery is not a new concept while it is studied in the present book through a new point of view. Instead of classic presentation of different methods and treatments useful for improvement of oil and gas recovery, practical aspects of these approaches are discussed through numerous case studies provided in the book. In fact, there are many simple and effective methods to increase the recovery of crude oil with low capital costs and short payback period. As a rule of thumb, higher first stage recovery leads to higher recovery factor in the secondary and tertiary phases of production. So, early implementation of IOR methods and new production technologies will considerably boost the ultimate recovery of the reservoir.
... Schematic of (GAGD) process[9] ISSN 2229-5518 Corresponding Author, E-Mail: a.pourabdol@gmail.com (Arash Pourabdol Shahrekordi) 1 Islamic Azad University, Fars Science and Research Branch, Department of Petroleum Engineering, Shiraz, Iran. 2 Iranian Central Oil Fields Company IJSER © 2014 http://www.ijser.org ...
... E Fig. 1. Schematic of gas assisted gravity drainage (GAGD) process [9] Along with edge water drive and solution gas drive, gravity drainage has long been recognized as one of the three important natural drive mechanism for expelling oil from the reservoir rock. However, the quantification of oil recovery due to drainage has long been a concern. ...
This paper presents a reservoir modeling study about positioning horizontal wells to optimize carbon sequestration and oil recovery simultaneously in the Wasson field, which is one of the largest reservoirs in the Permian Basin with 6 billion barrels of original oil in place. A significant portion of this field has been under CO2 injection for enhanced oil recovery for decades, so the CO2 gathering, processing, and distribution network in the area makes the Wasson area extremely cost-competitive as a CO2 storage site. Transitioning the source of CO2 injected in the Wasson area from natural to anthropogenic has the potential to sequester hundreds of millions of metric tons of carbon in the coming decades. Although the traditional development strategy has achieved attractive economic returns in the better-quality rock, novel well configurations are needed to be economically successful as development is expanded to areas with lower rock quality.
We used a compositional, history-matched reservoir model to perform a sensitivity study of lateral section length, horizontal orientation, spacing, and vertical placement for both production and injection wells. We also studied the vertical placement of the wells with respect to the main oil column (MOC) and the residual oil zone (ROZ), a distinctive characteristic of the Permian Basin. In all the scenarios, the MOC is to be co-developed with the ROZ. Since our focus was on the lower-quality rock areas, we selected horizontal wells due to their success in the cost-effective development of tight reservoir rocks. The significant remaining greenfield potential in the Wasson area offers an opportunity for a complete revolution of the development strategy from vertical to horizontal wells.
The most important finding of this study is that the vertical placement of the horizontal injector has a significant effect on oil recovery and lifecycle CO2 retention. Placing the injector close to the bottom of the ROZ and the producers in the MOC resulted in the highest carbon sequestration. The optimized case improved CO2 sequestration by 40% over the base case. The absence of significant vertical flow barriers in the area, along with our prior understanding of the reservoir heterogeneity and CO2 phase behavior, enabled us to optimize well placement to take advantage of gravity drainage. This configuration exposed a larger section of the reservoir volume to the injectant, resulting in a higher sweep efficiency.
Our work provides relevant guidance on the design of future developments using horizontal wells to optimize carbon sequestration and incremental oil recovery simultaneously during CO2 EOR and carbon capture, use, and storage (CCUS) projects. These findings are likely to lead to technical and economic success, even in the poor rock quality areas in the Wasson reservoir, significantly increasing the sequestration and oil recovery potential of this field.
In this paper, we attempted to analyze the experimental results about different CO2 injection rates affect the oil recovery and pressure gradient in low permeability dip reservoirs. For these experiments, a special core holder was designed to load a core of 100 cm long and 2.5 cm in diameter; furthermore, it could have different dip angles to simulate gravity segregation condition. Different CO2 injection rate was chosen to analyze how affect the frontal speed of CO2 plume, oil recovery, and CO2 sequestration. The results show CO2 storage efficiency could be greatly enhanced about 20% by decreasing the injection rates from 0.4 to 0.05 mL/min in dip system. Nevertheless, the ultimate oil recovery will achieve to be 63% when CO2 injection rate drop to 0.1 mL/min, further reduction of injection rate to 0.05 mL/min will lead to lower recovery 58.1% and higher CO2 storage efficiency 64.7%. We found there was a huge pressure loss in the middle of core when injection rate is too slow, it is beneficial to CO2 storage efficiency. The dimensionless number Nvp that we proposed take pressure changes and displacing front velocity into account, which has a better correlation with oil recovery compared to capillary and gravity dimensionless numbers. Analyzing the results suggest that conducting reasonable CO2 injection rate, monitoring pressure changes along with flooding process may be dominated factors to CO2-assisted gravity drainage in low permeability dip reservoirs.
