From Coreflooding and Scaled Physical Model Experiments to Field

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From Coreflooding and Scaled Physical Model Experiments to Field-Scale EOR Evaluations: Comprehensive Review of the Gas-Assisted Gravity Drainage (GAGD) Process Dr. Watheq J. J. Al-Mudhafar Energy Fuels, Just Accepted Manuscript • DOI: 10.1021/acs.energyfuels.8b01023 • Publication Date (Web): 25 Sep 2018 Downloaded from http://pubs.acs.org on September 29, 2018

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From Coreflooding and Scaled Physical Model Experiments to Field-Scale EOR Evaluations: Comprehensive Review of the Gas-Assisted Gravity Drainage (GAGD) Process Watheq J. Al-Mudhafar1,∗ Center for Petroleum and Geosystems Engineering, The University of Texas at Austin

Abstract The Gas-Assisted Gravity Drainage (GAGD) process has been suggested to improve oil recovery in both secondary and tertiary stages through immiscible and miscible injection modes. In contrast to Continuous Gas Injection (CGI) and Water-Alternative Gas (WAG), the GAGD process takes advantage of the natural segregation of reservoir fluids to provide gravity-stable oil displacement, and improve oil recovery. In the GAGD process, the gas is injected through vertical wells at the top of reservoir to formulate a gas cap that allows oil and water to drain downwards to the reservoir bottom where horizontal producer(s) are placed. Extensive experimental works and limited reservoir-scale evaluation studies have been conducted to test the effectiveness of the GAGD process performance. In this paper, a comprehensive literature review is presented to summarize all the references about concepts, principles, and field-scale evaluations of the GAGD process. Particularly, this paper presents an introduction to the mechanisms of CO2 -rock-fluid interactions, gas-EOR injection approaches, the GAGD process physical model, the factors influencing the GAGD process, and a review of all the previous field-scale evaluation studies. Furthermore, the validation of the GAGD process in reservoir-scale applications is fully discussed by focusing on its weaknesses with respect to the optimal implementation design for achieving maximum oil recovery. Keywords: GAGD Process, Coreflooding Experiments, Scaled Physical Model, Gas-EOR Projects, Comprehensive Review

∗ Corresponding

author Email address: [email protected], Tel:+1-225-715-2578, ORCID:0000-0002-5327-8300 (Watheq J. Al-Mudhafar) 1 Researcher, The University of Texas at Austin

Preprint submitted to Energy & Fuels

September 8, 2018

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1. Introduction The exploitation of fossil fuels has attracted attention worldwide as increasing CO2 concentration in the atmosphere may be influencing climate changes, commonly known as global warming (Lindeberg and Holt , 1994). There are many possible options to minimize the effects of global 5

warming, such as using renewable energy, and improving system efficiency in industry (You et al. , 2014). Although there is decades of experience implementing CO2 injection techniques in a few specific basins and geological environments, the need for reduced CO2 emission on a worldwide scale requires that CO2 injection into the subsurface be undertaken in new environments, and at greater volumes than have thus far been attempted (Hurter et al. , 2007). Gas and oil reservoirs are con-

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sidered safe CO2 storage sites due to their historic record of trapping buoyant fluids for millions of years (Akervoll and Bergmo , 2010). When the primary recovery period is over, a significant amount of oil is left behind. This “trapped” oil remaining in the pore space of the reservoir can sometimes reach 80-90 percent of the total volume of oil in the reservoir (Melzer , 2012). Secondary production is used to increase the

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percentage of recovered oil. Water and gas injection (also known as flooding) are common secondary recovery techniques, wherein the injected fluid is used to sweep the trapped oil through pressure maintenance and displace it towards the producing wells. However, sometimes a partial sweep event will occur as a result of the injected fluid bypassing the oil in the formation because no interaction or mixing is taking place, meaning that even a successful flooding project can leave 50-70 percent of

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the reservoir initial oil in place (IOIP) (Melzer , 2012). All these factors, in addition to the possible environmental benefits and the continuous developments made to the CO2 gas injection method, has added to its increased use compared to other methods, especially compared to the first years of usage (Koottungal , 2007). Figure 1 shows the U.S. oil production in barrels per day associated with various enhanced oil recovery (EOR) projects.

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Figure 1: The Recent US Enhanced Oil Recovery Production (Koottungal , 2007, Verma , 2015)

The CO2 enhanced oil recovery (EOR) process has become a major technique to produce some of the remaining oil, and for storing CO2 to minimize greenhouse gas emission into the atmosphere 2 ACS Paragon Plus Environment

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(Chen et al. , 2007). Underground storage of CO2 in depleted petroleum reservoirs and aquifers offers high storage capacity, and EOR presents opportunity for large-scale use where CO2 adds value. 30

Due to the combined benefits of CO2 injection for EOR and sequestration, the various injection processes of Continuous Gas Injection (CGI), Water-Alternating-Gas (WAG), and Gas-Assisted Gravity Drainage (GAGD) have gained increasing interests in the oil field development projects. Previous works showed, for instance, that the overall heavy oil recovery from water flooding can be improved by cyclic injection of water after injecting CO2 , both in specific rates and periods, like the WAG

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flooding process (Derakhshanfar et al. , 2010, Srivastava et al. , 1994, Zhang et al. , 2002). In addition, the Gas-Assisted Gravity Drainage (GAGD) process has been patented to enhance the recovery of bypassed oil through both immiscible and miscible injection modes (Rao et al. , 2004). The GAGD process proposes placing a horizontal producer at the bottom of the payzone above the oil-water contact, and injecting the gas as either immiscible or miscible in a gravity-stable

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mode through the vertical wells from the top of the formation (Rao et al. , 2004). Figure 2 depicts the schematic drawing of the GAGD process.

Figure 2: Schematic of GAGD process (Al-Mudhafar et al. , 2018a)

Through the GAGD process, the fluids gravity segregation and the oil drainage towards the payzone bottom lead to better sweep efficiency and higher oil recovery. The CO2 usage is preferred for 45

injection because it attains high volumetric sweep efficiency with high microscopic displacement efficiency, especially in the miscible injection mode. Additionally, the high volumetric sweep efficiency delays CO2 breakthrough into the producer (Rao et al. , 2006). Delaying or eliminating the CO2 breakthrough increases the gas injectivity and maintains the injection pressure by diminishing the concurrent gas-liquid flow mechanisms. The CO2 used in this process can be obtained from natural

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or common sources, such as: associated gas production from oil fields, and captured from large stations like refineries and power plants. Fundamental understanding and application of these processes in numerical simulation at the field scale is still a major challenge. Gas-Assisted Gravity Drainage process has been well studied, and has proved effectiveness in many complex reservoir problems to enhance the recovery of bypassed oil through experimental and reservoir-scale simulation.

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2. Mechanism of CO2 -Rock-Fluid Interaction Gas injection for EOR aims to recover residual oil remaining after a water flooding event, either by improving macroscopic sweep efficiency or microscopic sweep efficiency. Macroscopic sweep is how much of the reservoir volume (areal and vertical extent) can be swept by the solvent. Microscopic sweep explains how much remaining oil is contacted by the solvent. Solvent in EOR application

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refers to gas, which is typically CO2 since it is in fluid or dense phase when injected in supercritical condition (Green and Willhite , 1998). Gas injection alone generally improves microscopic efficiency, particularly when it is operated in miscible mode. This is the condition when CO2 and oil are soluble in all proportion to become single phase. At this condition the interfacial tension between gas and oil disappears, the oil swells and its viscosity decreases. The swelled oil with reduced viscosity

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joins other oil droplets to form an oil bank, which is then displaced to the producer (Green and Willhite , 1998). Although gas EOR improves the microscopic efficiency, the process suffers because of the poor macroscopic sweep. Since CO2 has a lighter density than oil, it tends to move upwards in the reservoir and sweep the oil in that part. This tendency for gas to segregate is known as gravity segregation or gravity override. Moreover, when there is high vertical communication in the

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reservoir, the gas preferentially sweeps the high permeability layer. Further, since CO2 has lower viscosity than oil, its mobility, which is the ratio of gas effective permeability of its viscosity, is higher, while the oil mobility is lower. Thus, the mobility ratio is higher than unity, which means the solvent front is not displacing oil uniformly. There will be pockets of residual oil uncontacted by the solvent. This problem becomes worse when the reservoir heterogeneity is high (Green and

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Willhite , 1998). CO2 is used in EOR for the combined effects of solution gas drive, reduce in viscosity, oil swelling and effect of miscibility due to the reaction with hydrocarbons. CO2 is very soluble in hydrocarbons and this phenomenon causes the swelling of the oil, but on the other hand, for reservoirs holding methane, less carbon dioxide could be dissolved in the oil which outcomes less swelling in the oil.

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When the oil in the reservoir is saturated with CO2 at high pressure, the viscosity of the oil will be reduced. The water in the reservoir also has a reaction with CO2 , which causes some expansions and the density would be decreased, so both the density of water and oil become closer to each other which decreases the influence of gravity segregation. Several reasons like the swelling of oil, oil viscosity reduction, blow down effect, and increased injectivity all assist oil recovery in the immiscible

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CO2 injection. The mechanisms of CO2 -rock-fluid interactions can be summarized by the following points (Mathiassen , 2003, Holm and Josendal , 1982): • Oil Swelling: Solubility of CO2 in hydrocarbons is affected by saturation pressure, composition of the oil, and reservoir temperature. When CO2 is dissolved in oil, the volume of the oil is increased. This causes a reduction in residual oil and increased recovery.

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• Oil Viscosity Reduction: In miscible injection, as the oil is saturated with CO2 , the viscosity of the oil decreases. This increases recoverable oil more than a situation in which the oil is not saturated with CO2 . • Blow Down Recovery: This mechanism is multifaceted. As the reservoir pressure reduces with 4 ACS Paragon Plus Environment

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the production (flooding termination), CO2 becomes immiscible and comes out of the solution 95

while sweeping the oil to the production well. • Increased Injectivity by Increasing Permeability: A reaction between CO2 and water creates an acidic solution that reacts with the carbonate portions of the reservoir, thereby dissolving part of the rock matrix. This can have the positive effect of increasing permeability, but may also cause pore throat plugging. Pore throat plugging occurs when the acids that dissolve

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the rock matrix interact with asphaltene, which would ultimately decrease permeability. More studies are needed to compare these processes and their overall effects on permeability. The miscibility status of CO2 in the reservoir depends on three factors: reservoir pressure, temperature, and oil properties. Generally, the miscible CO2 operations are achieving higher recoveries than immiscible CO2 operations. The minimum miscibility pressure (MMP) is the borderline for the

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miscible state of the CO2 , and is the minimum pressure value at which miscible state occurs (Verma , 2015). Holm and Josendal (1982) described the MMP as the pressure at which more than 80 percent of oil-in-place (OIP) is recovered at CO2 breakthrough. Still, different measures have been established for the characterization of the MMP. Yellig and Metcalfe (1980) used the oil recovery of at least 90% at 1.2 HCPV (hydrocarbon pore volume) of CO2 injected to estimate the MMP.

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Miscibility directly affects oil recovery. Therefore, recovery increases dramatically with increasing pressure below the MMP (in the immiscible case), but is constant at and after the pressure reaches MMP value (miscible state). Figure 3 below displays the phenomenon.

Figure 3: Slim-tube Oil Recoveries at Increasing Pressures for Fixed Oil Composition and Temperatures (Yellig and Metcalfe , 1980)

There is a complex phase behavior of CO2 when it is in contact with both rocks and reservoir 115

fluids. The effect of these interactions is contingent upon the types of rocks and fluids, and also reservoir conditions such as pressure and temperature. Wettability is one of the factors that needs to be considered not only for a successful GAGD process, but also in the selection of any EOR process. As stated by Dixit et al.

(1996) the wettability of rocks and fluids impacts the petrophysical 5 ACS Paragon Plus Environment

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parameters, such as relative permeability and capillary pressure. Additionally, the wettability plays a 120

significant role to produce the remaining oil left behind after the secondary recovery. Wettability has been classified into different “Regimes” for further analysis. It has been observed that the wettability alteration in core floods and capillary tube cell tests confirm the irregularity in wettability due to CO2 miscible flooding. Experimental work indicates the effect of CO2 on brine PH reduction, a concept which is supported by a field data study that also shows a direct effect of CO2 floods in wettability

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behavior. The laboratory model of Jackson et al. (1985) demonstrates that the detrimental effect on enhanced oil recovery of miscible CO2 floods is due to gravity tonguing in water, which is wet and viscous fingering in oil wet tertiary flooding. The type of wettability found to be in favor of one type of flooding over the other, as in water wet projects with continuous CO2 injection, which showed that the maximum recovery when oil wet flooding gave the maximum recovery using WAG ratio of

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1:1. Rogers and Grigg (2000) findings also match the results of Jackson et al.

(1985) that the

water-wet environment favors a continuous gas injection, whereas oil wet environment favor WAG process with ideal 1:1 ratio. Furthermore, in a mixed wet environment, the maximum recovery is a function of slug size (Mathiassen , 2003). Other studies have shown that the immiscible CO2 -assisted water flooding process is affected by the CO2 slug size, number of slugs, and the injection rates of 135

water and CO2 in water alternating gas-CO2 (WAG) injection (Srivastava et al. , 1994). PVT conditions have a higher degree of complexity in a CO2 flood situation than other types of floods (HC flood as an example). The behavior of the phase is difficult to measure or predict. In miscible mode, mass transfer between oil and CO2 allow these two phases to become completely miscible without any boundary and transition zone initiated (Jarrell , 2002). In the immiscible

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case and below the MMP, the oil in the reservoir with unfavorable composition does not allow CO2 and oil to form a single phase. Still, the CO2 will dissolve in oil. As a result, the oil will swell, resulting in viscosity reduction, progress sweep efficiency, and additional oil recovery (Martin and Taber , 1992). Research by Grigg and Siagian (1998) explores PVT for a four-phase flow in low temperature CO2 floods. Their findings include the presence of up to five phases coexisting in a sole

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CO2 flood. Four of these phases are fluid phases that will flow with sufficient saturation: aqueous, liquid hydrocarbon, liquid CO2 , and gaseous CO2 . The other is a solid phase that can migrate asphaletene precipitate. The number of these phases that can coexist at a time depend on pressure, temperature, and composition. Compared to other solvents, Carbon Dioxide has been recognized as more efficient due to its

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numerous advantages. One advantage is that CO2 is soluble in both oil and water, and solubility in oil results in oil swelling, extracting the heavy components of oil, and reducing oil viscosity. Another advantage is the ability of CO2 to increase oil density and decrease water density, thereby reducing the difference between oil and water densities and ultimately leading to reduced gravity segregation. The reduction in gravity segregation leads to more effective displacement due to a reduction in the

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surface tension between oil and water (Mathiassen , 2003). Nevertheless, the high mobility of CO2 has its drawbacks in regards to attaining profitable flooding. The relatively low density and viscosity of CO2 are responsible for gravity tonguing and viscous fingering. These issues are more severe in CO2 floods compared to water floods. However, many corrective steps can be adopted to recover


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the sweep efficiency, such as using additives with the CO2 , alternating the CO2 flood with water 160

injection, and design specific techniques in production (Mathiassen , 2003). In the GAGD process, a gravity stable gas front movement helps to increase volumetric sweep efficiency, and if this process is combined with miscible gas flooding, which aims to reduce microscopic displacement efficiency, very high recoveries can be obtained. Impetus to use this process, instead of conventional continuous gas injection (CGI) or water-alternating-gas (WAG) processes, lies in

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very low recovery efficiency associated with those processes. In the majority of gas flooding projects reviewed (Christensen et al. , 1998), incremental oil recovery was in the range of 5-10%, with an average incremental recovery of 9% for the miscible WAG process. This low incremental recovery can be attributed to gravity over-ride.

3. EOR Gas Injection Methods 170

3.1. General Overview Natural drive mechanisms include: solution gas drive, water drive, gas cap drive, and gravity segregation. The end of primary recovery is achieved by reaching a very low reservoir pressure or a high gas oil ratio (GOR). The water flooding process is the most common secondary recovery mechanism. After that, the oil left behind can be produced through injection of external solvents

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such as gas, heat (thermal), and other chemicals, all of which can increase the oil recovery. The stage when these processes are applied is called Enhanced or Tertiary Oil Recovery (EOR). Specifically, EOR uses external materials, such as steam, nitrogen, carbon dioxide, and polymer for injection into oil reservoirs in order to thrive rock-fluid interaction, increase oil mobility, and then extract certain volumes of remaining oil (Ahmed , 2006). The main influential role of EOR methods is either to

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reduce the oil mobility ratio or increase the capillary number (Farouq and Thomas , 1996). The gas injection process reduces the interfacial tension (IFT), and decreases the oil viscosity, striving for high oil mobility towards the wellbore areas and incremental recovery of about (5-15)% of IOIP (Lake et al. , 1992). The selection criterion of gas injection type depends on whether it is miscible or immiscible, as

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well as the depth, pressure, and temperature of the formation, and oil compositions. The selection process also considers the availability of specific gas for injection. CO2 is more favorable in injection than other gases because of its lower minimum miscibility pressure and lower compression cost. The CO2 and hydrocarbon gases have been used in approximately 90% of EOR projects worldwide (Mathiassen , 2003).

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Selecting CO2 according to whether it is miscible or immiscible depends on the depth of the formation, oil compositions, and rock wettability (Kuo and Eliot , 2001). CO2 has many advantages that make it very effective in enhanced oil recovery projects. Because of its higher viscosity, lower mobility ratio, closer density of the light oil in its miscible condition; CO2 has lower injection problems than other gas types. In addition, CO2 has higher gravity segregation in the high water

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saturation zones of the reservoir and this leads to efficient oil displacement. CO2 can be economically obtained from natural earth sources, thermal power plants, or refineries. It has been selected for the GAGD process because it has better sweep efficiency than other solvents (Kulkarni and Rao , 2005). 7 ACS Paragon Plus Environment

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However, there are factors that impede its performance in oil reservoirs such as reservoir description in terms of: areal and vertical permeability distribution, fractures and faults, and barriers and 200

continuity. Moreover, gravity forces, viscous fingering, and the mobility ratio further affect CO2 sweep efficiency. The carbon dioxide or any other gas types is being injected for EOR operations in three distinct processes: Continuous Gas Injection (CGI), Water Alternating Gas (WAG), and finally through the Gas-Assisted Gravity Drainage (GAGD) process. 3.2. Continuous Gas Injection

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The conventional continuous gas injection has been used since the 1920’s for secondary and tertiary recovery modes to inject 100% carbon dioxide (no water) to lower the interfacial tension between the injected gas and the reservoir oil, leading to increased displacement efficiency and higher oil recovery (Hinderaker et al. , 1996, Kulkarni , 2003). For most of the previous CGI projects, the incremental recovery was around 5% of Initial Oil in Place (IOIP). The CGI is preferred to be

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adopted in water-wet reservoirs within the immiscible mode (Rogers and Grigg , 2000). 3.3. Water Alternating Gas The Water Alternating Gas injection (WAG) process was first proposed in 1958 to improve miscible displacement efficiency by using water slugs after the CO2 . However, the incremental oil recovery from 59 WAG projects was 5-10% of the IOIP (Christensen et al. , 1998). he Miscible WAG projects

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have led to average incremental recovery of 9.7% of IOIP, while immiscible WAG Projects accounted for only 6.4% incremental recovery (Caudle and Dyes , 1958). Compared to CGI, WAG provides better mobility control and higher CO2 exploitation efficiency (Mahmoud and Rao , 2007). Two important issues must be accounted for in any CO2 -EOR operation: flood injection design, and flood implementation. TThere exist numerous CO2 injection designs such as: continuous CO2

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injection, continuous CO2 injection with water, conventional water alternating CO2 (WAG) with water, tapered water alternating CO2 (WAG), and water alternating CO2 (WAG) with gas. Another important parameter, in addition to injection design, is flood implementation, which varies depending on gas composition, degree of miscibility and timing relative to water flooding (Jarrell , 2002). CO2 flooding in contrast to waterflooding increases microscopic displacement rather than

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macroscopic sweep efficiency, which results in unfavorable displacement efficiency (e.g. gravity instability, channeling) and thus poor sweep efficiency (Jafari and Faltinson , 2009). The schematic of various carbon dioxide (CO2 ) flood-injection designs in oil reservoirs was depicted in Figure 4. 3.4. Gas-Assisted Gravity Drainage According to the WAG process, WAG does not take into consideration the gravity-stable mode

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or water saturation increases in the reservoir for the purposes of diminished gas injectivity and increased fluid competition towards the wellbore. Consequently, and in order to overcome all other limitations for both WAG and CGI, a new process of Gas Assisted Gravity Drainage (GAGD) has been recently introduced. This potent alternative to WAG takes advantage of the natural segregation of injected gas and crude oil in the reservoir, caused by their distinct fluid densities (Kulkarni and

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Rao , 2005, Mahmoud and Rao , 2007, Rao et al. , 2006). Additionally, the literature from both 8 ACS Paragon Plus Environment

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Figure 4: Schematic of Various Carbon Dioxide (CO2 ) Flood-Injection Designs in Oil Reservoirs (Jarrell , 2002). Cont.= continuous; Cont./Wtr = continuous CO2 chased with water; WAG/Wtr = conventional water alternatinggas (WAG) CO2 flood-chased with water; TWAG/Wtr = tapered water-alternating-gas CO2 flood-chased with water; WAG/Gas = conventional WAG chased with gas (Verma , 2015)

laboratory and field studies shows that the GAGD process improves oil recovery to almost 100% in laboratory tests, and 87-95% in field-scale applications (Kulkarni and Rao , 2006a). Due to the gravity segregation resulting from the distinct reservoir fluid densities at reservoir conditions, the injected gas accumulates at the top of the reservoir providing gravity stable oil displacement that 240

drains towards the horizontal producer at the bottom of the payzone (Mahmoud and Rao , 2007).

4. GAGD Process Physical Model The main GAGD process, as introduced by Rao et al.

(2004), involves placing a horizontal

production well at the bottom of the payzone, exactly above the oil-water contact. The gas is then injected through the existing vertical wells (henceforth referred to as vertical injectors or just in245

jectors). This can be done in two applicable modes, either immiscible or miscible (Kulkarni and Rao , 2006a). In immiscible mode, the gas accumulates at the top of the reservoir forming a gas cap, and the higher density fluids drain down towards the horizontal producer (Rao et al. , 2004). Rao et al. (2004) have constructed an experimental work-based scaled physical model in order to study the GAGD process effectiveness, and to understand the mutual action and reaction of capil-

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lary, gravitational, and viscous forces. This scaled physical model has been utilized to investigate the most influential factors affecting the GAGD process, including but not limited to: miscibility/immiscibility flooding, wettability, and heterogeneity. Additionally, the scaled physical model has demonstrated the feasibility of GAGD in comparison with CGI and WAG in both secondary and tertiary recovery. Although it has been concluded that incremental recovery through miscible WAG

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is higher than the miscible CGI in tertiary mode, miscible CGI has better incremental recovery than a miscible WAG in secondary mode. Furthermore, the miscible WAG has more distinguished incremental recovery than its immiscible case in both secondary and tertiary modes, and GAGD has demonstrated better incremental recovery through immiscible mode than both immiscible WAG and CGI processes (Rao et al. , 2004).

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The effective comparison between WAG and GAGD processes has been efficiently investigated through the dimensional analysis approach that was used for nine gravity stable and eight miscible and immiscible WAG field applications in the world (Kulkarni and Rao , 2006b). This study has been conducted to understand the feasibility of gravity drainage of oil to horizontal produc265

ers through vertical well-based gas injection. Petrophysical dimensionless numbers of Bond (NB), Dombrowski-Brownell (ND), and Grattoni et al.’s (N), with the operational numbers of Capillary (NC) and Gravity (NG), Capillary (NC) and Bond (NB) have been calculated for the mentioned field projects. The numbers from these groups have been considered for coupling with the Microscopic Bond Number to characterize the flow regimes and the controlling forces of gravity, viscosity, and

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capillary action in the field and laboratory displacements. After implementing these calculations, the gravity stable gas injection demonstrated much better production rates and recovery factors than both miscible and immiscible WAG processes (Kulkarni and Rao , 2006a). To capture the multiphase mechanisms and fluid dynamics of gravity drainage forces through the GAGD process that cannot be characterized by the existing models of Buckley-Leverett and

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gravity-drainage theories, a new gravity-drainage mechanism has been proposed and validated with two analytical and empirical free-gravity-drainage models (Kulkarni and Rao , 2006a). The analytical model, which was introduced by Richardson and Blackwell (1971), was employed to predict oil recoveries for 1D and 2D laboratory GAGD floods within 6.4% error, and the Li and Horne empirical model was used to overpredict the GAGD oil recoveries, and to predict the oil production rates by

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incorporating capillary pressure data in order to improve gravity drainage recovery predictions. The Richardson and Blackwell model has been used on different GAGD experiments of secondary mode such as gravity and non-gravity stable displacement through immiscible and miscible GAGD flood. This model has been validated against the Hawkins Dexter field data, and the ultimate oil recovery was under-predicted by 5.2% IOIP. Overcoming limitations of the Richardson and Blackwell model

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led to investigation into the Li and Horne’ empirical model (Li and Horne , 2002) in order to overpredict the oil production rates through 1D GAGD core floods and 2D physical models, but only in the case of free-gravity-drainage floods (Kulkarni and Rao , 2006b, Richardson and Blackwell , 1971). To investigate the feasibility of the GAGD process for improving oil recovery in secondary and

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tertiary modes, a physical model of two parallel glass plates confining a sand-pack was constructed for implementing envisioned experiments (Mahmoud and Rao , 2007). This visual model has also been used to figure out the most influential factors affecting the GAGD performance regarding the gas injection design, such as: depth, injection rate, and methods. It has been found that injection rate has a direct effect on increasing the oil recovery with effectiveness of depth. Similarly, there

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has also been investigation into the feasibility of GAGD to improve oil recovery in both successive secondary and tertiary immiscible modes; the oil recovery in immiscible secondary modes was 83% IOIP because of the near perfect volumetric sweep efficiency, while in the immiscible tertiary mode it was 54% IOIP. Therefore, the microscopic sweep efficiency has reached to 100% in miscible secondary and tertiary modes (Mahmoud and Rao , 2007). As mentioned previously, Carbon Dioxide

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has been chosen as the injection gas for this study because of the ability of its dissolved phase to


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swell oil and form a CO2 chamber at the top of the payzone, and now we can conclude that the free gravity drainage, and the hydrostatic head of fluid in place, represent the dominant mechanisms prior to the gas breakthrough (Mahmoud and Rao , 2007). Sharma and Rao (2008) have used a visual glass bead-packed system for implementing a scaled 305

physical model in order to discover the effects of scaled dimensionless numbers of capillary, bond, and gravity on GAGD performance (Sharma and Rao , 2008). The data obtained shows that the oil recovery has increased to 80% of IOIP in secondary GAGD mode. Moreover, the recoveries have demonstrated a semilogarithmic relationship with the ratio of gravity to viscous forces (Gravity number) in high pressure GAGD core-floods. Furthermore, the ratio of gravity to capillary forces

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(Bond number) is more influential on the GAGD performance than other parameters. This outcome has been obtained using multiple linear regression that has been fitted to the laboratory and field data for immiscible GAGD mode. The miscible performance can be predicted by extrapolating the fitted regression line of the immiscible case. Sharma and Rao (2008) have also implemented various other GAGD scenarios with respect to the operative design parameters, some examples being

315

injection rate and pressure using either CO2 or N2 as injection gases. The authors of this paper have found that the GAGD performance has the same oil recovery history for both CO2 and N2 at constant gas injection pressure in immiscible mode. Additionally, the incremental recovery with time at constant pressure case is faster with higher values of capillary numbers than the scenario of constant rate. The main important outcome of all these experiments was that the GAGD process

320

improves fast oil recovery early after time of implementation. The physical model described previously has also been used to provide visual and quantitative representation of the GAGD process, revealing the various modes of operability of GAGD in fractured reservoirs, oil-wet reservoirs, and heavy oil reservoirs (Mahmoud and Rao , 2008). They found that the volumes of oil recovered by using the GAGD process were higher than either the CGI or

325

WAG processes in all the fractured reservoir types, and in both secondary and tertiary modes. This physical model has also been utilized to identify the impact of gas injection rate, depth, huff-andpuff, toe-to-heel, oil viscosity and wettability through the GAGD process in comparison to WAG and CGI processes. The oil recoveries have ranged from 54% to 83% IOIP in all the mentioned operations except the toe-to-heel (Mahmoud and Rao , 2008). An interesting discovery made during

330

these operations is that, although higher rates of gas injection leads to higher oil recovery, the depth of the injection intervals has no effect on the recovery incremental (Mahmoud and Rao , 2008). By altering the model and creating two inclined fractures in the experimental medium, they found that incremental recovery in immiscible mode with high injection rates was better and faster than with low injection rates. Therefore, GAGD in immiscible mode has been proven as a viable option for

335

fractured reservoirs. The huff-and-puff GAGD operation showed positive results for the oil recovery incremental, but they were still lower than a conventional GAGD operation. Finally, throughout these various operations, it was also concluded that the oil recovery in oil-wet carbonate media is higher than in water-wet carbonate media, despite the fact that both of them exhibited high flow rates in response to the GAGD process, and all the previous outcomes have better positive incre-

340

mental recoveries than the CGI and WAG processes.


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For tertiary GAGD mode, an experimental study using a different physical model was adopted to visualize the fluid-solid interaction mechanisms at the pore scale in order to determine a critical range of controlling fluid and porous media factors for a stable gravity dominated process (Mohiuddin and Haghighi , 2011). This physical model, a glass micro-model, to inject CO2 and displace 345

water at various rates under different gravity conditions, made it possible to experimentally determine the relationship between porous media characteristics, such as dip angle and heterogeneity, in the GAGD process at the pore scale. The dimensionless Darcy Rayleigh number and mobility ratio were used for scaling the experiments into larger scales and for using different fluids. Nine experiments were conducted considering three values of injection rates and three sets of reservoir

350

dips in order to study the effect of dipping conditions on the CO2 displacement, and investigate the impact of the dimensionless Darcy Rayleigh number on oil recovery. It was found that the Darcy Rayleigh number has a non-significant impact on oil recovery in dipped reservoirs, as there was a non-considerable increment in oil recovery during the experiments. Furthermore, although the Darcy Rayleigh number is not proportional to the oil recovery in thin sections, it is highly affected in

355

the normally distributed model. Figure 5 illustrates a summery of the GAGD scaled physical models.

5. Factors Affecting GAGD Process Various parameters have been investigated to find their influential roles on the performance of the GAGD process. All the following summaries are based on experimental work only. Although there 360

have been other sensitivity analysis studies conducted on reservoir-scale simulations, the following studies have been reviewed and therefore, included in this section. The following three subsections represent the effect of three different categories on the GAGD process: 5.1. Effect of Wettability Wettability in porous media is the tendency of a fluid (wetting phase) to adhere to reservoir

365

rock surface in the presence of other immiscible fluids. Either water or oil is the wetting phase; gas is always a non-wetting phase (Peters , 2001). The effects of wettability (oil wet/water wet) and injection mode (secondary/tertiary) have been experimentally examined through the GAGD process on vertical fracture-based porous medium (Paidin et al. , 2007). It has been determined that oil recovery in water wet is better and higher than the oil wet in both secondary and tertiary

370

immiscible GAGD modes, in both bead and sand pack experiments. Moreover, the GAGD process has surprisingly exhibited the ability to change the wettability from oil wet to water wet with significant improvement in oil recovery. Furthermore, the presence of vertical fractures in both oil wet and water wet porous media has increased oil recovery by 7.8% IOIP higher than the nonfractured media.

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5.2. Effect of Gravity The most recent experimental GAGD efficiency investigations presented the effects of gravity stable and unstable CO2 fronts under immiscible, near miscible, and miscible displacements of crude


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Figure 5: Review of the GAGD Process Physical Model

oil by CO2 . Slim tube experiments, core floods, and bead packed tube experiments have all been used to simulate the GAGD process in porous media. Carbon Dioxide was injected into these systems, 380

all of which were first flooded with three crude oils, and each crude oil had a different minimum miscibility pressure (MMP) value. It was determined that the gravity drainage mechanism is more


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influential on oil recovery volumes than either phase behavior or the miscibility alone. Additionally, the miscible injection had a higher recovery in vertical stable flooding than in horizontal flooding. Finally, both immiscible and near miscible displacements have led to significant improvement in oil 385

recovery in the vertical gravity stable floods with about 90% recovery factor at 250 psi below the MMP, compared to only 33% in horizontal floods (Adel et al. , 2018). 5.3. Effect of Reservoir and Fluid Parameters Since the immiscible gas-driven gravity drainage process involves many reservoir and fluid parameters in both static and dynamic states, a sensitivity analysis study was conducted to understand

390

their relative dominance during gas-oil gravity drainage process and also to demonstrate their effect on oil recovery (Jadhawar and Sarma , 2008). The parameters investigated include, but are not limited to: viscous, capillary, and gravity forces, the rate of gas injection and oil production, the difference of oil and gas density, oil relative permeability, and oil viscosity. Also, the interaction terms between these factors have been considered. The laboratory core flooding experiments have been

395

scaled in the dimensionless analysis in order to study the effect of the aforementioned parameters on the GAGD process performance in field-scale evaluations. The core-scale compositional simulation of the GAGD process illustrates that there are small changes of residual oil saturation that might lead to an effect on the GAGD performance. Further, the pressure-based gravity number is more dominant in scaling GAGD than gas injection rate-based gravity number. Finally, the scaling anal-

400

ysis for group parameters in GAGD EOR has proven validity, especially in non-dipped reservoirs. Application of the GAGD process in naturally fractured reservoirs has been also conducted through an experimental model of a naturally fractured reservoir in a Brazilian offshore oil field (Silva and Maini , 2016). Rectangular Berea sandstone blocks were utilized in the model, and these blocks represent the matrix rock. The blocks were separated by small gaps in the horizontal and

405

vertical directions using metal spacers, and these gaps were used to simulate the fractures in the vertical and horizontal directions. A 100% CO2 gas was injected into the model at a constant rate. Two different injection rates were used for two different runs. The first run used a low gas rate injection, and the horizontal fracture permeability was higher than the vertical fracture permeability. The second run used a higher gas injection rate, but the fracture horizontal permeability was lower

410

than the fracture vertical permeability. Data from the experiment was then history matched using a commercial reservoir simulator. The model investigated the effect of gas injection on oil flow rate. The results showed that a high recovery factor of 40% of IOIP can be obtained from the GAGD process in naturally fractured reservoirs and the recovery factor increases under high gas injection rates.

415

6. GAGD Reservoir-Scale Applications In this section, a review of GAGD literature about reservoir-scale applications was divided based on the lithology of the reservoir. Many studies have been conducted on sandstone reservoirs (clastic), and others on limestone (carbonate).


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6.1. Clastic Reservoirs 420

Clastic sediments are composed of sand and some shale minerals. The mineralogy of the shale minerals has a great impact on the pore size, porosity, and permeability of sand rocks (Neasham , 1977). The GAGD process has been studied on limited real oil fields and tested for its feasibility to enhance oil recovery, especially in clastic reservoirs. The GAGD process has been evaluated for its

425

effectiveness to enhance the recovery of oil through compositional reservoir simulation in Wasson oil field, located in West Texas. Reservoir and fluid data have been obtained from the fifth SPE Comparative Solution Project: Evaluation of Miscible Flood Simulators (Al-Mudhafar , 2015, Killough and Kossack , 1987). A five-spot pattern with four vertical injectors and one horizontal producer has been considered for regular CO2 injection and GAGD process. The Experimental Design was

430

used to generate multiple simulation runs in order to obtain the most influential factors affecting the flow responses and the optimum GAGD scenario. It was found that GAGD is more efficient at increasing the recovery factor than regular CO2 injection. The minimum bottom hole pressure in the production well and the maximum bottom hole pressure in the injectors were the most influential factors impacting the GAGD process performance.

435

The CO2 GAGD process has been also applied in North Louisiana field to predict the optimal field development performance through an economic analysis (Paidin et al. , 2010). Optimizing the net present value (NPV) and rate of return was done by coupling the compositional reservoir simulator with the economic model, with consideration for approximate oil prices, capital (CAPEX), and operational (OPEX) expenditures in this field. The operational decisions that were investigated

440

for their possible influence on performance optimization are: varying numbers of injector-producer well pairs, difference locations for well pairs, difference locations of the horizontal producer above the oil-water contact, the CO2 injection rate, production rates, and the lag time between the start of injection and production. It has been concluded that of all the operational decisions that could impact GAGD performance, the gas injection rate has a direct effect as the recovery factor increases

445

with higher injection rates. The most influential economic factor affecting the NPV is the oil price, but the capital expenditure (CAPEX) has non-considerable negative effect on the economic response with approximately neglected impacts for other factors (Paidin et al. , 2010). Consequently, the high incremental of oil recovery through CO2 GAGD process has led to high NPV. Another investigation of the GAGD process was conducted on a hypothetical field via 3D compo-

450

sitional reservoir modeling of both immiscible and miscible secondary recovery modes. The purpose was to identify the mechanistic benefits of production strategy on gravity drainage oil recovery (Jadhawar and Sarma , 2010a). This also tested the effects of irregular and regular well patterns with consideration to not only vertical gas injectors, but also horizontal gas injectors, under the conditions of voidage balance, constant injection and production pressure, and injection rates below the

455

critical rate. The regular well pattern has led to longer oil production time at a constant rate prior to CO2 breakthrough than the irregular well pattern. The investigation has also shown that there is no significant difference between considering either vertical or horizontal gas injection wells because cumulative oil recovery through immiscible and miscible modes have the same gravity drainage oil


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recovery when using horizontal injection and production wells in the regular well pattern. The well 460

patterns and gas injection rates are other factors that play a major role in the GAGD performance. Both immiscible and miscible secondary recovery modes have yielded to identical incremental oil recovery because of the homogeneous-anisotropic system of the selected reservoir model. Another hypothetical reservoir model was considered to study the effect of gas injection rate, oil production, grid size, and reservoir heterogeneity on the immiscible GAGD performance, but

465

in a 3D black oil reservoir model with an EOS-based property simulator (Jadhawar and Sarma , 2010b). Simulations indicate that gas injection rates and oil production are the most dominant factors affecting the incremental oil recovery in the GAGD process. The gravity drainage mechanism was not affected by the type of injection wells; there was identical GAGD performances through each of them with respect to the cumulative oil production water-oil ration, and gas-oil ratio. The

470

sweep efficiency has higher oil recovery in lower connate water saturation. Finally, the non-dipped horizontal reservoir had approximately 85% IOIP. The GAGD process has been adopted to improve oil recovery through high quality compositional reservoir simulation, applied on the main pay of South Rumaila oil field, located in Iraq (Al-Mudhafar and Rao , 2017a, 2015a). Field-scale application requires wide investigation for all the decision fac-

475

tors that have impacts on the flow response. Therefore, the first task was to investigate different reservoir, flooding, and horizontal well design parameters through performing compositional reservoir simulation in order to find out the key factors that help to reach the maximum oil recovery. The composition reservoir simulation was performed in conjunction with design of experiments in order to better understand the potential of CO2 in enhancing oil recovery based on the concept

480

of the GAGD process (Al-Mudhafar , 2016). Furthermore, the GAGD process was then tested in comparison with Continuous Gas Injection (CGI) and Water-Alternating Gas (WAG) methods to evaluate CO2 flooding in an immiscible mode, also on South Rumaila oil field (Al-Mudhafar et al. , 2017a). The study was conducted using an EOS compositional reservoir model to test the efficiency of these methods in increasing recovery factor. Results of this study show higher recovery factor

485

were obtained using the GAGD process (RF= 32.72%) compared to the CGI and WAG processes where the recovery factors were 12.35% and 11.37% respectively. Therefore, the GAGD process is considered to be more efficient than CGI and WAG for increasing recovery factor because it improves the sweep efficiency by taking gravity segregation into account. Furthermore, Al-Mudhafar and Rao (2015b) conducted an investigation of CO2 injection in both

490

miscible and immiscible modes through the GAGD process in the upper sandstone reservoir in the South Rumaila oil field. The aim was to improve the oil recovery and to find the optimum future performance scenario. The study was performed through the integration of compositional reservoir simulation and Design of Experiment to optimize the best case for increasing the recovery factor and to determine the most influential production controls through the GAGD process. The production

495

controls were as follows: maximum oil production, the minimum bottom hole pressure, skin factor, and the maximum water cut in the producers. In terms of the injectors, the maximum injection pressure and the maximum injection rate have been also included. The maximum bottom hole pressure for injectors was the most influential factor through GAGD process. The cumulative pro-


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duction rate has increased by 200 million bbls in the optimized immiscible CO2 injection compared 500

to the base case of immiscible CO2 injection. This increase was more in a miscible CO2 mode where the cumulative oil production was about 400 million bbls more than the immiscible base case. A related study was conducted on the same reservoir using different mixtures of gas for the immiscible GAGD process evaluation. It has been concluded that the associated gas has a slightly higher oil recovery than other gas mixtures including CO2 , because of the compatibility of the associated gas

505

with the existing reservoir and fluid properties Al-Mudhafar et al. (2018a). Application on South Rumaila oil field has been extended to include sensitivity analysis, production optimization, and uncertainty assessment (Al-Mudhafar , 2016). In sensitivity analysis, the reservoir parameters play a key role in understanding the efficiency of EOR process. Bayesian Model Averaging (BMA) was introduced to study the effect of the most influential parameters on

510

the GAGD process performance in a multilayer heterogeneous sandstone oil reservoir (Al-Mudhafar and Rao , 2018). These factors included reservoir horizontal permeability, anisotropy ratio (Kv /Kh ) and porosity. The study was conducted using compositional flow simulation were the reservoir layers were sub-classified into four groups; injection, transition (between injection and production), production, and bottom (below production) layers. The BMA was then adopted as a stochastic

515

statistical approach to find the best model fit through Bayes’ theorem and posterior probability. The horizontal permeability had more effect on the GAGD process than the anisotropy ratio in the layers of injection, below production and transition, whereas the anisotropy was influential in production and under production layers. The most affecting factors were then changed in the simulation model to test their impact on the cumulative oil production. Modeling the affecting factors through

520

BMA has found that the heterogeneity has a vital impact on the GAGD process performance in heterogeneous reservoirs (Al-Mudhafar and Rao , 2018). An optimization study used Design of Experiment (DoE) and Proxy modeling to optimize the GAGD process in a sector model for the Zubair formation in the South Rumaila oil field, in order to increase the recovery factor for this field (Al-Mudhafar and Rao , 2017b). Six main operational

525

decision factors that could have influenced the GAGD process were investigated. These factors are: maximum oil production rate, minimum bottom hole pressure, maximum water cut and skin factor for production wells, maximum injection bottom hole pressure, and maximum CO2 injection rate for injection wells. The designs of experimental and proxy modeling were combined to form a simplified approach (metamodel) alternative to the compositional reservoir simulation. The most influential

530

factors based on this model were minimum bottom hole pressure in production wells and maximum bottom hole pressure in injection wells, as these factors constrain the gas injection and the oil production through the reservoir (Al-Mudhafar and Rao , 2017b). Another optimization workflow under geological uncertainties has been adopted through the cyclic CO2 -GAGD process in a heterogeneous sandstone oil reservoir (Al-Mudhafar et al. , 2018b).

535

The optimization of cyclic-GAGD process was implemented based on nominal and robust optimization approaches. Both approaches included sampling the cyclic parameters of gas injection, soaking, production periods, and the number of cycles in addition to the minimum bottom hole pressure. Several stochastic reservoir models for the permeability and porosity distributions were generated to


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select the P10, P50 and P90 that represent the geologic uncertainty. After that, many training sim540

ulation runs were generated, including the durations and geological uncertainty parameters through Latin Hypercube Design. The cyclic optimization through the GAGD process led to increase the oil recovery factor from 71.5% (RF=71.5% in the base case of GAGD) to 75.5%. Uncertainty quantification workflow was likewise adopted using the integration of Design of Experiment, proxy modeling, and Monte-Carlo simulation for quantifying uncertainty regarding the ge-

545

ological and production parameters through the cyclic-GAGD process in a heterogeneous sandstone oil reservoir (Al-Mudhafar and Rao , 2016). First, many stochastic reservoir models for horizontal permeability and anisotropy ratio were generated for geological uncertainties and the P10, P50 and P90 were selected. Next, the most likely reservoir model was chosen for production data uncertainty, where the decision parameters of cyclic-GAGD were considered. These parameters were durations of

550

injection, soaking, the production rate as well as the minimum bottom hole pressure for producers. The proxy based Box-Behnken design and Monte-Carlo simulation was used to create and evaluate many training jobs through the compositional reservoir simulation for obtaining the optimal case for the cyclic-GAGD process. The determined optimal case of cyclic–GAGD process resulted in an increase of the cumulative oil production of about 6.53 million bbls higher than the base case

555

solution (Al-Mudhafar et al. , 2018e). The effects of reservoir heterogeneity and anisotropy were also quantified through the cyclic Gas-Assisted Gravity Drainage (GAGD) process performance in South Rumaila oil field. More specifically, the heterogeneity and anisotropy effects were assessed in terms of reservoir horizontal permeability and anisotropy ratio, respectively. It was concluded that the impact of permeability

560

anisotropy on the GAGD process is higher than heterogeneity, as the GAGD process adopts vertical fluid movements from the top reservoir to the horizontal producers (Al-Mudhafar et al. , 2018c). The efficiency of the GAGD process reduces in reservoirs with high tendencies and high water cuts. Therefore, downhole water sink technology has been integrated into the GAGD process to overcome the limitations of GAGD in these reservoirs. The hybrid integration of gas and Downhole

565

Water Sink-Assisted Gravity Drainage (GDWS-AGD) has been adopted to improve oil recovery at the upper sandstone member/South Rumaila oil field (Al-Mudhafar et al. , 2017b). The Rumaila field has an infinite active aquifer with strong edge and bottom water drives. A 7 inches casing was dual completed for two 2-3/8 inches horizontal tubings: one above the oil-water contact for oil production and one underneath for water sink. The two completions were hydraulically isolated

570

inside the well by a packer. The bottom (water sink) completion employs a submersible pump and water-drainage perforations. A Reservoir simulation model was conducted to find the optimal setting of these combined processes in terms of oil and water production and pressure of gas injection. The injection pressure was periodically decreased to ensure immiscibility of CO2 flooding. The produced water through the GDWS-AGD process not only reduced water cut and coning, but

575

also significantly reduced the reservoir pressure, resulting in improved gas injectivity. The results show that the GDWS-AGD process increased the oil recovery from 71% to 85% and the water cut decreased from 98% to less than 5% in all the horizontal oil producers (Al-Mudhafar et al. , 2018d). Figure 6 illustrates a summery of the GAGD reservoir-scale applications in sandstone reservoirs.


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580

Figure 6: Review of the GAGD Reservoir-Scale Applications in Clastic Formations

6.2. Carbonate Reservoirs 585

Natural fractures are commonly recognized in carbonate reservoirs and they are usually caused by mechanical rock failures or geological stresses from various sources, such as faults, folds, and fluid pressure (Peters , 2001). Fractures may be perpendicular to the fault or there may be two orthogonal directions. They may be a hair-width or reach to few millimeters (Crain , 2015). Fractures may appear as microfissures with an extension of only several micrometers, or as continental fractures with

590

an extension of several thousand kilometers. They also may be limited to a single rock formation or layer, or extended through multiple layers (Tiab and Donaldson , 2004, Milad et al. , 2018). The GAGD process has also been tested in a naturally fractured carbonate reservoir, consisting of a multitude of micro-fractures with a distinct difference in permeability from the matrix rock. For this case, GAGD was applied as both immiscible and miscible modes. It was discerned that the oil

595

recovery using miscible GAGD is higher than with immiscible injection (Kasiri and Bashiri , 2009). In a fractured limestone reservoir, the GAGD process was tested using a compositional reservoir simulation on a gas condensate/oil field located in North Western Pakistan. In this study, the GAGD performance was compared to primary production, Continuous Gas Injection (CGI), and Water Alternating Gas (WAG). In the GAGD case, the horizontal producer configurations were optimized to

600

delay the gas breakthrough in order to achieve a 53% increase in oil recovery compared to the 26% for the base case development scenario (Munawar et al. , 2017). The most recent GAGD application 19 ACS Paragon Plus Environment

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was conducted by Dinh et al. (2017) through huff-n-puff pilot project to improve oil recovery in a fractured basement reservoir in Cuu Long Basin, offshore Vietnam. This project consisted of four cycles of dry gas and periodic injection. With this particular huff-n-puff type of GAGD, it was 605

found that gas injection volume and the gravity-drainage mechanism are the most influential factors affecting the increment in oil recovery. It was also found that the final incremental oil recovery of each cycle depended upon the duration of gas injection and soaking periods as well (Dinh et al. , 2017). Another recent GAGD study was conducted using a 3D compositional reservoir simulation to

610

identify the impact of heterogeneity, injection rate, and aquifer water influx on the GAGD-EOR performance. This study, conducted on a naturally fractured reservoir in one of the western Iranian oil fields (Delalat and Kharrat , 2013), used generated maps of permeability and porosity to separately simulate both homogeneous and heterogeneous fractures. This study concluded that the performance of the GAGD process in homogeneous fracture reservoirs has higher efficiency than

615

the heterogeneous fractured reservoirs, and the oil recovery in homogeneously fractures reservoirs is higher. However, the gas-oil ratio (GOR) is lower in the highly heterogeneous fracture systems than the homogeneous ones. Therefore, it is safe to conclude that the efficiency of the GAGD process is proportional to the high gas injection rates in heterogeneous fractures, since the flow of fluids is highly affected by complex geosystems, such as barriers and spatial permeability variations. Finally,

620

Delalat and Kharrat (2013) have concluded that the performance of Gas-Assisted Gravity Drainage process in the reservoirs with finite active aquifers is more effective than in the reservoirs of infinite aquifers because strong water drive affects the gravity drainage mechanisms. Table 1 summarize the most influential parameters that impact the performance of the GAGD Process Application for Enhanced Oil Recovery in Clastic and Carbonate Reservoirs.

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Table 1: Summery of the Most Influential Parameters Affecting the GAGD Process Application in Clastic and Carbonate Reservoirs

Clastic Reservoirs Field

Dominant Parameter (s)

South Rumaila(Al-Mudhafar and Rao , 2018)

Horizontal permeability in gas injection zones Anisotropy in oil production zones

South Rumaila(Al-Mudhafar et al. , 2018c)

permeability anisotropy for the entire reservoir

South Rumaila(Al-Mudhafar and Rao , 2017b)

minimum bottom hole pressure in production wells maximum bottom hole pressure in injection wells

Carbonate Reservoirs Cuu Long Basin/offshore Vietnam(Dinh et al. , 2017)

gas injection volume and gravity-drainage mechanism

A western Iranian oil fields(Delalat and Kharrat , 2013)

gas injection rates


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7. Conclusions In this paper, a comprehensive literature review was presented to summarize all the studies that have been conducted about the Gas Assisted Gravity Drainage (GAGD) process with respect to the concepts, principles, and reservoir-scale evaluations conducted to enhance the recovery of oil. Par630

ticularly, this paper presents an introduction about the mechanisms of CO2 -rock-fluid interactions, gas injection approaches for enhanced oil recovery, description of the GAGD physical modeling, factors influencing the GAGD process, and the review of reservoir-scale evaluation studies. What’s important to take away from this review is that while all reservoir-scale applications of the GAGD process have been conducted on various reservoir lithology types, especially clastic and carbonates,

635

all experimental and simulation studies point towards the same conclusion: the GAGD process consistently obtains higher volumes of oil recovery than other secondary and tertiary recovery processes like Continuous Gas Injection (CGI), or Water Alternative Gas (WAG), especially in immiscible injection modes.

Nomenclatures and Abbreviations 640

• BMA: Bayesian Model Averaging • CAPEX: Capital Expenditures • CGI: Continuous Gas Injection • CO2 : Carbon Dioxide • DoE: Design of Experiments

645

• EOR: Enhanced Oil Recovery • EOS: Equation of State • GAGD: Gas-Assisted Gravity Draiange Process • GDWS-AGD: Gas and Downhole Water Sink-Assisted Gravity Draiange • HCPV: Hydrocarbon Pore Volume

650

• IOIP: Initial Oil in Place • Kv /Kh : Anisotropy Ratio • MMP: Minimum Miscibility Pressure • N: Grattoni et al.’s Number • NB: Bond Number

655

• NC: Capillary Number • ND: Dombrowski-Brownell Number


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• NG: Gravity Number • NPV: Net Present Value • OAPEX: Operational Expenditures 660

• RF: Recovery Factor • TWAG: Tapered Water-Alteranting-Gas • WAG: Water-Alternating-Gas • WTr: Water

References 665

Adel, I. A., Zhang, F., Bhatnagar, N., and Schechter, D. S. The Impact of Gas-Assisted Gravity Drainage on Operating Pressure in a Miscible CO2 Flood. SPE Improved Oil Recovery Conference, Tulsa, Oklahoma, USA (2018). https://doi.org/10.2118/190183-MS Ahmed, T. H. Reservoir Engineering Handbook: Gulf Professional Publishing (2006). Akervoll, I., Bergmo, P. E. S. CO2 EOR from Representative North Sea Oil Reservoirs. SPE In-

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ternational Conference on CO2 Capture, Storage, and Utilization, New Orleans, Louisiana, USA (2010). https://doi.org/10.2118/139765-MS Al-Mudhafar, W. J. Statistical Reservoir Characterization, Simulation, and Optimization Of Field Scale-Gas Assisted Gravity Drainage (GAGD) Process with Uncertainty Assessments. PhD Dissertation. Louisiana State University (2016). https://digitalcommons.lsu.edu/gradschool_

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dissertations/3097 Al-Mudhafar, W. J. M. Efficient Experimental Design for Optimal Oil Recovery through Field Scale– Gas Assisted Gravity Drainage (GAGD) Process. The 77th EAGE Conference and Exhibition, Madrid, Spain (2015). http://dx.doi.org/10.3997/2214-4609.201412722 Al-Mudhafar, W. J., Rao, D. N. Integrating Designed Simulations for Bayesian Identification of

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Geological Controls on the Performance of a Multilayer Heterogeneous Sandstone Oil Reservoir: Applied on the CO2 -Assisted Gravity Drainage Process. SPE Western Regional Meeting, Garden Grove, California, USA (2018). https://doi.org/10.2118/190109-MS Al-Mudhafar, W. J., Rao, D. N. Lessons Learned from the Field-Scale Simulation of the GasAssisted Gravity Drainage (GAGD) Process in Heterogeneous Sandstone Oil Reservoirs. SPE

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From Coreflooding and Scaled Physical Model Experiments to Field

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