Gas Assisted Gravity Drainage Research Articles

Deterministic tools to predict gas assisted gravity drainage recovery factor

Naturally fractured rocks contain most of the world's petroleum reserves. This significant amount of oil can be recovered efficiently by gas assisted gravity drainage (GAGD). Although, GAGD is known as one of the most effective recovery methods in reservoir engineering, the lack of available simulation and mathematical models is considerable in these kinds of reservoirs. The main goal of this study is to provide efficient and accurate methods for predicting the GAGD recovery factor using data driven techniques. The proposed models are developed to relate GAGD recovery factor to the various parameters including model height, matrix porosity and permeability, fracture porosity and permeability, dip angle, viscosity and density of wet and non-wet phases, injection rate, and production time. In this investigation, by considering the effective parameters on GAGD recovery factor, three different efficient, smart, and fast models including artificial neural network (ANN), least square support vector machine (LSSVM), and multi-gene genetic programming (MGGP) are developed and compared in both fractured and homogenous porous media. Buckingham π theorem is also used to generate dimensionless numbers to reduce the number of input and output parameters. The efficiency of the proposed models is examined through statistical analysis of R-squared, RMSE, MSE, ARE, and AARE. Moreover, the performance of the generated MGGP correlation is compared to the traditional models. Results demonstrate that the ANN model predicts the GAGD recovery factor more accurately than the LSSVM and MGGP models. The maximum R2 of 0.9677 and minimum RMSE of 0.0520 values are obtained by the ANN model. Although the MGGP model has the lowest performance among the other used models (the R2 of 0.896 and the RMSE of 0.0846), the proposed MGGP correlation can predict the GAGD recovery factor in fractured and homogenous reservoirs with high accuracy and reliability compared to the traditional models. Results reveal that the employed models can easily predict GAGD recovery factor without requiring complicate governing equations or running complex and time-consuming simulation models. The approach of this research work improves our understanding about the most significant parameters on GAGD recovery and helps to optimize the stages of the process, and make appropriate economic decisions.

Investigation of optimum conditions in gas-assisted gravity drainage using Taguchi experimental design

Gas-assisted gravity drainage (GAGD) is known as an important enhanced oil recovery (EOR) method. Detailed understanding of multiphase fluid flow mechanisms in fractured porous media is one of the challenging issues in reservoir engineering. In this paper, the most effective parameters on the GAGD recovery factor (RF) in fractured porous media are investigated using a new experimental fractured sand pack. The Taguchi method as an effective approach for design of experiments and optimization of design parameters is employed to evaluate impacts of various process variables such as sand particle size, type of wetting and non-wetting phases, gas injection rate, dip angle, and fracture position on oil RF under gravity drainage mechanism. During the experiments, distilled water and condensate are utilized as the wetting-phase. Nitrogen and carbon dioxide are also used as the non-wetting phase. Moreover, an analysis of variance (ANOVA) is conducted to find the most significant parameters affecting GAGD recovery performance. Also, the process variables are optimized to maximize oil RF. The results reveal that the type of wetting phase is the most effective parameter in the GAGD processes. The mean sand size and fracture position are the second and third influencing parameters followed by the injection rate, dip angle, and type of non-wetting phase. The optimum conditions for maximizing RF of the GAGD are identified in the following order: wetting phase of condensate, mean sand size of 300 μm, non-wetting phase of N2, fractures at the number of 3, dip angle equal to 0o (vertical model), and injection rate of 20 cm3/min. According to this research, the average RF of condensate as a wetting phase is found to be around 12% higher than the water case. Also, N2 as an immiscible injected gas causes a higher average RF compared to CO2. Increasing the mean sand size, injection rate, or the number of fractures can enhance the GAGD RF. The dip angle experiments demonstrate the RF of alignment of 0ᵒ or vertical mode is (75.06%) > dip angle of 20ᵒ (71.79%) > dip angle of 5ᵒ (71.60%). The more RF at the dip angle of 20ᵒ in comparison with the 5ᵒ scenario might be due to the capillary continuity and the liquid bridge of the wetting phase from the upper matrix block into the lower one in this specific fractured setup. The experimental results reveal that the emplacement, number, and direction of matrix and fractures play a considerable role in the recovery performance of fractured porous media that should be carefully evaluated in production management plans to obtain a higher final RF in fractured reservoirs.

Application of gas-assisted gravity drainage (GAGD) to improve oil recovery of Rang Dong basement reservoir

As an option to improve the ultimate oil recovery factor of the Rang Dong field, a feasibility study of gas-assisted gravity drainage (GAGD) application was carried out for the fractured basement reservoir with a single-well Huff ‘n’ Puff pilot test applied on a high water-cut producer. This paper aims to provide an in-depth understanding about such case study, which includes details on candidate selection, gas injection scheme, on-site execution, results of flow-back, post-job review and lessons learned. 
 The pilot test of GAGD was recorded with a good oil rate and low water-cut during flowing back after gas injection and shut-in for gas segregation, which suggests the positive effectiveness of GAGD to some degree. The expansion of the GAGD application to other wells and areas in the field would be encouraged in any similar situation. On the other hand, the results of this pilot test shed a light into further optimisation of the candidate selection and gas injection scheme by material balance analysis and reservoir simulation respectively.

Experimental Characterization of Oil/Gas Interface Self-Adjustment in CO2-Assisted Gravity Drainage for Reverse Rhythm Reservoir

Worldwide practices have proven that gas-assisted gravity drainage can obviously enhance oil recovery, and this technology can be especially effective for reservoirs with a thick formation and large inclination angle. For the successful implementation of this process, a key technology is the stable control of gas–oil interface during gas injection. For a detailed exploration of this technique, a three-stage permeable visual model was designed and manufactured, with permeability decreasing from top to bottom, thus, a reverse rhythm reservoir was effectively modeled. Then the experiment concerning CO2-assisted gravity drainage was carried out with the adoption of a self-developed micro visual displacement device. This study mainly focused on the micro migration law of gas–oil interface and the development effects of CO2-assisted gravity drainage. According to the experiments, CO2 fingering somewhat happens in the same permeable layer from the beginning of gas injection. However, phenomena of “wait” and “gas–oil interface self-adjustment” occur instead of flowing into the next layer when the injected CO2 reaches the boundary of the next lower permeability layer through the dominant channel. By the “gas–oil interface self-adjustment”, the injected CO2 first enters into the pores of the relative higher permeability layer to the greatest extent, and thus expands the sweep volume. Futhermore, in the process of CO2 injection, obvious gas channeling occurs in the low permeability layer directly connected to the outlet, resulting in low sweep efficiency and poor development effect. After connecting the core with lower permeability at the outlet, the development indexes of the model, such as the producing degree of the low permeability layer, the oil recovery before and after gas breakthrough, are significantly improved, and the recovery degrees of the medium permeability layer and the high permeability layer are also improved, and the overall recovery factor is increased by 12.38%. This “gas–oil interface self-adjustment” phenomenon is explained reasonably from the two scales of macroscopic flow resistance and microscopic capillary force. Finally, the enlightenments of the new phenomenon are expounded on the application of gas-assisted gravity drainage on site and the treatment of producers with gas breakthrough in gas injection development.

Experimental evaluation of Carbon Dioxide-Assisted Gravity Drainage process (CO2-AGD) to improve oil recovery in reservoirs with strong water drive

The Gas-Assisted Gravity Drainage (GAGD) process has been developed to improve and enhance oil production in both secondary and tertiary recovery stages. In the GAGD process, oil is produced through horizontal wells above the oil-water contact. Therefore, high levels of water cresting are probably happening, especially in reservoirs with active water aquifers. However, all the previous GAGD feasibility experimental studies have never been addressing the existence of active water aquifers. Consequently, the current research was conducted to test the immiscible GAGD process feasibility to improve oil recovery and minimize water cut in brown reservoirs with strong water coning tendencies.A Hele-Shaw model consists of two parallel glass plates packed with silica sand to visually discern the process performance. Specifically, the CO2-AGD process feasibility versus the Free Fall Gravity Drainage (FFGD) mechanism was investigated on the physical model with large, moderate, and without bottom water drive. The experimental results indicated that the GAGD process performance is higher performance than the FFGD in all runs because of its fast high oil recovery, especially when implemented on the reservoir without a bottom water drive. The immiscible CO2-AGD process is not only important in terms of increasing oil recovery, but it also significantly delays the gas breakthrough. The strength of the aquifer inversely impacts the gas breakthrough time as increasing the aquifer strength results in fast oil production and early gas breakthrough. Additionally, the immiscible GAGD experiments illustrated that oil recoveries in the FFGD and GAGD processes improved to 35% and 47% of OOIP for the model without bottom water drive, respectively. However, the oil recovery increased in the same FFGD and GAGD processes to 61% and 63% of OOIP for the model with a large bottom water drive, respectively. Specifically, the ultimate oil recovery during the GAGD process with a large bottom water drive was higher than the FFGD run with only 2%; while there is increasing in ultimate oil recovery for the model without the bottom water drive of about 12%. Consequently, the GAGD process is more efficient to improve oil recovery in reservoirs with limited or without bottom water drive.

Characteristics of gas-oil contact and mobilization limit during gas-assisted gravity drainage process

Gravity can reduce the instability of the gas-oil contact that is caused by gas channeling in locations with low flow resistance, such as high-permeability layers, macropores, and fractures during the gas-assisted gravity drainage process. Herein, the microscopic forces during the gas-assisted gravity drainage process were analyzed and combined with the capillary model to study the occurrence boundary of gas-assisted gravity drainage process, and the characteristics of the gas-oil contact in the gas-assisted gravity drainage process was discussed. The results show that free gravity drainage occurs only in pores where a certain height of the oil column and pore radius are reached. Furthermore, the lower the oil-gas interface migration rate, the easier free gravity drainage occurs. In other scenarios, additional gas injection is required. During the gas-assisted gravity drainage process, the gas-oil contact moves down stably as a transition. The width of the transition zone and the available pore radius are related to the gas-oil contact migration rate and the oil viscosity; the smaller the gas-oil contact migration rate and the lower the oil viscosity, the smaller pore throat can be involved in mobilization. Optimizing the gas injection rate and reducing the oil viscosity can delay the gas channeling maturity time, which is beneficial for the realization of the gas-assisted gravity drainage process. Finally, a method considering micropore heterogeneity is established for determining the critical gas injection rate, while the mainstream pore throat can be involved in mobilization and the gas-oil contact can be stabilized at the same time. The method of determining the critical gas injection rate can help researchers and reservoir engineers to better understand and implement the gas-assisted gravity drainage process. Cited as: Kong, D., Gao, J., Lian, P., Zheng, R, Zhu, W., Xu, Y. Characteristics of gas-oil contact and mobilization limit during gas-assisted gravity drainage process. Advances in Geo-Energy Research, 2022, 6(2): 169-176. https://doi.org/10.46690/ager.2022.02.08

A Single-Well Gas-Assisted Gravity Drainage Enhanced Oil Recovery Process for U.S. Deepwater Gulf of Mexico Operations

The U.S. Deepwater Gulf of Mexico (DGOM) area that has some of the most prolific oil reservoirs is still awaiting the development of a viable enhanced oil recovery (EOR) process. Without it, DGOM will remain severely untapped. Exorbitant well costs, in excess of $200 million, preclude having extensive injection patterns, commonly used in EOR design frameworks. Aside from injection patterns, even operationally waterflooding has met with significant challenges because of injectivity issues in these over pressurized turbidities. The gas-assisted gravity drainage (GAGD) EOR process, that holds promise for deepwater environments because of lesser injectivity issues, among others, has been adapted in this work to overcome these limitations. A novel design in the form of a single well—gas assisted gravity drainage (SW-GAGD) process, has been demonstrated to emulate the benefits of a GAGD process in a cost-effective manner. Unlike conventional GAGD processes, which need multiple injectors and separate horizontal production wells, the SW-GAGD process just uses a single well for injection and well production. The performance of the process has been established using partially scaled visual glass models based on dimensional analyses for scale up of the process. The recovery factor has been shown to be in the range of 65–80% in the immiscible mode alone, and the process is orders of magnitude faster than natural gravity drainage. A toe-to-heel configuration of the SW-GAGD process has also been tested and for the configuration to be immune from reservoir layering, the toe of the well should ideally end at the top of the payzone. Better sweep of the payzone and consequent high recovery factor of 80% OOIP was observed, if the heel part of the bottom lateral is located in a lower permeability zone.

New insights into forced and free fall gravity drainage performance in a fractured physical model

Gravity is one of the major driving forces for fluid flow in naturally fractured reservoirs. Gravity drainage appears to be a vital recovery mechanism over the oil production process in a majority of fractured reserves. In this paper, free-fall gravity drainage (FFGD) and forced gravity drainage (FGD) production approaches are investigated through employing a new fractured sand pack with a rectangular geometry. Distilled water and condensate are used as the wetting phase. Nitrogen, carbon dioxide, and air are also utilized as the non-wetting phase. A systematic sensitivity analysis is conducted to find the effects of the key factors such as fracture blockage, injection rate, dip angle, and type of wetting phase and injection fluid on the performance of FFGD and FGD processes. Also, a numerical simulation is performed to simulate the experiments. Results reveal that the FGD has a better performance under controlled process conditions, compared to the FFGD so that gas injection with a controlled rate improves the recovery. Moreover, it was found that increasing the gas injection rate improves the recovery factor (RF) of wetting-phase when the up and bottom sides of the fractures are blocked; the RF is decreased in the case with open fracture sides. The recovery of the wetting phase decreases in both FFGD and FGD modes when the porous system has a deviation from the vertical orientation. According to the study outcomes, the immiscible gas-assisted gravity drainage offers a higher condensate recovery, compared to water recovery, due to lower viscosity and interfacial tension (IFT) of the condensate phase. The comparison of the experimental data and simulation results implies that the simulation approach can satisfactorily predict the performance of the FGD process. Based on the error analysis, there is a good match between the simulation results and the experimental measurements; the fluid pair of CO2-condensate exhibits the highest accuracy with an R-squared of 0.9961 and an average relative error (ARE) of 0.0054.

Visualization of Spreading and Non-Spreading Oil Films in Gas- Assisted Gravity Drainage (GAGD) Process Using Novel NOA81 Microfluidic Platform

The presence of oil films in three phase flow of oil, water and gas through reservoir rocks has a significant effect on the recovery efficiency associated with various Enhanced Oil Recovery (EOR) processes like Water Alternating Gas (WAG) and Gas-Assisted Graviry Drainage (GAGD). Visualization of these oil films helps in having a better understanding of the conditions required for the formation of such films in a rock pore network. In this work, we have used a microfluidic platform consisting of Norland Optic Adhesives-81(NOA81) that better mimics the reservoir rock pore geometry, to visualize the oil films in different spreading systems. NOA81 is a transparent polymer with high chemical and physical resistance, which enabled the device to withstand harsh organic solvents as well as high pressures and temperatures encountered in the EOR experiments. This device was designed with pore network similar to that of a consolidated water wet porous rock with varying channel widths and taper, unlike various other platforms using regular square or constant channel width grids. This modification resulted in a more realistic representation of the actual pore network of reservoir rocks. Continuous thinner oil films were observed in the positive spreading system, whereas discontinuous trapped oil blobs were encountered in the negative spreading system. Statistical analysis carried out on the thickness of the oil phase separating water and gas phases indicated significant differences and confirmed the visual observations.

Performance demonstration of gas-assisted gravity drainage in a heterogeneous reservoir using a 3D scaled model.

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 Nnew 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.

Pore-scale investigation of immiscible gas-assisted gravity drainage

Gas-assisted gravity drainage (GAGD) is an effective method of oil recovery that is influenced by the properties of the fluids and formations involved. In this paper, a direct numerical simulation method is employed to investigate immiscible GAGD in an oil-wet porous medium. The interface between oil and gas is tracked via the phase-field method. A series of numerical simulations are performed over a large range of values of various factors (gravity force, capillary force, viscous force, viscosity ratio, and porous medium properties) to investigate the gas flooding process in a porous medium. The results show the oil–gas interface as a transition zone that migrates during the GAGD process. Gravity improves oil–gas interfacial stability because the continuous oil film gravity-assisted hydraulic connection effect can overcome the capillary force in a small pore. The oil displacement process is dominated by gravity instead of the capillary and viscous forces when the gravitational number exceeds 500. Finally, the pore-scale dimensionless number (Npore) enables a quantitative analysis of the effects of various factors on GAGD. Npore helps predict GAGD oil recovery.

Numerical Simulation of Immiscible CO2-Assisted Gravity Drainage Process to Enhance Oil Recovery

The Gas Assisted Gravity Drainage (GAGD) process has become one of the most important processes to enhance oil recovery in both secondary and tertiary recovery stages and through immiscible and miscible modes. Its advantages came from the ability to provide gravity-stable oil displacement for improving oil recovery, when compared with conventional gas injection methods such as Continuous Gas Injection (CGI) and Water – Alternative Gas (WAG).
 Vertical injectors for CO2 gas were placed at the top of the reservoir to form a gas cap which drives the oil towards the horizontal oil producing wells which are located above the oil-water-contact. The GAGD process was developed and tested in vertical wells to increase oil recovery in reservoirs with bottom water drive and strong water coning tendencies. Many physical and simulation models of GAGD performance were studied at ambient and reservoir conditions to investigate the effects of this method to enhance the recovery of oil and to examine the most effective parameters that control the GAGD process.
 A prototype 2D simulation model based on the scaled physical model was built for CO2-assisted gravity drainage in different statement scenarios. The effects of gas injection rate, gas injection pressure and oil production rate on the performance of immiscible CO2-assisted gravity drainage-enhanced oil recovery were investigated. The results revealed that the ultimate oil recovery increases considerably with increasing oil production rates. Increasing gas injection rate improves the performance of the process while high pressure gas injection leads to less effective gravity mediated recovery.

Potential application of the CO<SUB align="right">2-assisted gravity drainage process in a mature oil field: insights from reservoir-scale EOR evaluation

The gas-assisted gravity drainage (GAGD) process was implemented through continuous and cyclic immiscible injection to enhance the recovery of bypassed oil in the upper sandstone reservoir in the South Rumaila oil field, located in Southern Iraq. A compositional simulation model was constructed for the carbon dioxide (CO2) flooding evaluation through the GAGD process implementations. After achieving history matching, 20 vertical CO2 injectors and 11 horizontal oil producers were placed in top reservoir and oil zone, respectively. The immiscible CO2-GAGD performance was evaluated for 10 years of future prediction. The continuous and cyclic immiscible GAGD cases resulted in reaching recovery factor of 14.5% and 21.3% given the remaining oil, respectively. However, the recovery factor given the remaining oil was 7.6% through primary production by the end of prediction period. Additionally, the obtained amount of oil in 10 years primary production can be produced in only one year by the continuous case and in 8 months by the cyclic case. Consequently, the optimal implementation of the GAGD process is by adopting the cyclic CO2 flooding that efficiently enhance the recovery of bypassed oil. [Received: December 30, 2017; Accepted: December 17, 2018]

From Coreflooding and Scaled Physical Model Experiments to Field-Scale Enhanced Oil Recovery Evaluations: Comprehensive Review of the Gas-Assisted Gravity Drainage Process

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 con...

Robust Optimization of Cyclic CO2 flooding through the Gas-Assisted Gravity Drainage process under geological uncertainties

The purpose of this research is to determine an estimate for actual optimal oil recovery through cyclic Gas-Assisted Gravity Drainage (GAGD) process in a heterogeneous sandstone reservoir under geological uncertainties. A robust optimization approach was adopted to determine the optimal durations of gas injection, soaking, and oil production under geological uncertainties. 100 stochastic reservoir realizations of the 3D permeability and porosity distributions were created to honor geological constraints. Ranking was applied through quantifying of reservoir oil response to select P10, P50, and, P90 that represent the overall reservoir uncertainty. A compositional reservoir flow simulation was used for the GAGD process performance evaluation. Approximately 200 simulation jobs were created, including the aforementioned durations and geological uncertainty parameters, through Design of Experiments (DoE). The Latin Hypercube Sampling was adopted to create these 200 simulation jobs that then evaluated by the compositional reservoir simulation to calculate the cumulative oil production by the end of 10 prediction years. The robust optimization approach was then applied to select the true optimal solution of the highest oil recovery by taking into account the geological uncertainties in permeability, porosity, and anisotropy models. The nominal optimization of one single realization was also adopted for the comparison. The robust optimization has shown its feasibility to increase oil production through the cyclic GAGD process from 4.535 to 4.62547 billion barrels. However, the nominal optimization case increased oil production to 5.9726 billion barrels. The presented robust optimization workflow under geological uncertainties resulted in higher oil recovery and net present value than nominal realization optimization, with providing degrees of freedom for the decision-maker to significantly reduce the project risk. It was specifically concluded that the robust optimal solution represents the most economically feasible solution to obtain the highest NPV through the GAGD process for a range $(30–80) per barrel oil prices. However, the base case and nominal solution (no geological uncertainties) were not economical when the oil price declines to be less than 36 and 32, respectively.

Pore-Level Investigation of the Influence of Wettability and Production Rate on the Recovery of Waterflood Residual Oil with a Gas Assisted Gravity Drainage Process

Gas assisted gravity drainage (GAGD) is an oil recovery mechanism that can be implemented after waterflood to enhance the recovery of oil. The performance of postwaterflood GAGD is affected by a variety of parameters that determine the balance between capillary, gravitational, and viscous forces. In this research, the influence of the wettability, heterogeneities, and production rate on the recovery of oil have been studied at the pore level to recognize phenomena affecting mechanisms of oil recovery visualizing interfaces in a newly designed micromodel that contains a coarse pore network covered by fine capillaries. Experimental results show that regions with high oil saturation (oil-bank) were formed ahead of the gas front in both oil-wet and water-wet micromodels when the production rate was low. Under oil-wet conditions, the size of the oil-bank was greater, and the recovery of oil initiated prior to a gas breakthrough. Under water-wet conditions, the flow of the residual oil after a gas breakthrough ...

Demonstrating the effect of hydraulic continuity of the wetting phase on the performance of pore network micromodels during gas assisted gravity drainage

The flow of fluids during oil recovery processes can be visualized in pore network micromodels that represent the porous nature of reservoir rocks. In a permeable rock, pores are formed in spaces between connected solid grains with various sizes and shapes. The surface roughness and irregularities of solid grains create networks of fine capillaries in conjunction with coarse pores. These fine capillaries can maintain films of a wetting phase in regions occupied by a non-wetting phase. In two-dimensional micromodels, the pore network is formed between separated solid grains, and the hydraulic communication of the wetting phase between regions separated by the non-wetting phase is terminated. In this paper, we present a simple procedure for the fabrication of oil-wet and water-wet micromodels that provide the wetting phase with strong hydraulic continuity. The new micromodel contains a pattern of coarse pores covered by fine capillaries without affecting its visualization capabilities. The performance of micromodels with and without fine capillaries was evaluated with the gas assisted gravity drainage (GAGD) experiments under oil-wet and water-wet conditions. The experimental results show that the presence of fine capillaries improved of the hydraulic continuity of a residual wetting phase. The new micromodel effectively demonstrated the interaction between capillary and gravitational forces in gravity drainage processes.

Proxy-Based Metamodeling Optimization of Gas-Assisted-Gravity-Drainage Process

This article, written by Special Publications Editor Adam Wilson, contains highlights of paper SPE 185701, “Proxy-Based Metamodeling Optimization of the Gas-Assisted-Gravity-Drainage Process in Heterogeneous Sandstone Reservoirs,” by Watheq J. Al-Mudhafar and Dandina N. Rao, SPE, Louisiana State University, prepared for the 2017 SPE Western Regional Meeting, Bakersfield, California, USA, 23–27 April. The paper has not been peer reviewed. Unlike continuous gas injection and water-alternating-gas injection, gas-assisted gravity drainage (GAGD) takes advantage of the natural segregation of reservoir fluids to provide gravity-stable oil displacement. The feasibility of carbon dioxide (CO2) GAGD was investigated for immiscible injection through equation-of-state compositional reservoir simulation with design of experiments (DOE) and proxy modeling to obtain the optimal future-performance scenario. After history matching, Latin-hypercube sampling (LHS) was used as a low-discrepancy and more-uniform DOE approach to create hundreds of simulation runs to construct a proxy-based optimization approach. Introduction Many enhanced-oil-recovery studies have been conducted for CO2-flooding optimization in real oil fields; however, to the best of the authors’ knowledge, no study has been made for GAGD implementation and optimization in a real oil field. To implement the optimization process, a full compositional reservoir simulation was constructed to evaluate the reservoir performance through CO2-GAGD flooding for 10 years of future reservoir prediction. Then, proxy-model optimization was conducted through manipulating the operational decision factors that influence the CO2 flooding through GAGD by means of DOE. More specifically, DOE and proxy modeling were combined to create a simplified alternative (metamodel) to the compositional reservoir simulation to optimize the operational decision factors affecting GAGD. Four proxy models were adopted and validated as metamodels for the compositional reservoir simulator: polynomial proxy model, multivariate additive regression splines (MARS), fuzzy logic/genetic algorithm, and generalized boosted modeling (GBM). GAGD The GAGD concept involves placing horizontal producers at the bottom of a pay zone. Then, gas is injected in a gravity-stable mode, either immiscible or miscible, through vertical wells from the top of the formation. Because of gravity segregation resulting from the distinct fluid densities at reservoir conditions, the injected gas accumulates at the top of the pay zone to form a gas cap, providing gravity-stable oil displacement that drains down toward horizontal producers and leading to better sweep efficiency and higher oil recovery. Fig. 1 illustrates the basic concepts of GAGD. GAGD Simulation The main-pay reservoir in the South Rumaila oil field was selected for a full, detailed compositional reservoir simulation to enhance oil recovery through GAGD. The main pay has only three lithology types—sand, shaly sand, and shale—with distinct areal permeability distributions. A high-resolution geostatistical reservoir model was reconstructed for lithofacies and petrophysical properties considering multiple-point geostatistics.

Optimizing the location of the gas injection well during gas assisted gravity drainage in a fractured carbonate reservoir using artificial intelligence

Gas assisted gravity drainage (GAGD) is a novel subdivision of gas injection method. In this method the injection wells are located in the upper bed of the oil zone, and the production wells are drilled at the bottom bed of the oil zone. Reservoir simulation is among the decision tools for investigating production rate and selecting the best scenarios for developing the oil and gas fields. Selecting the location of the injection wells for reaching the optimized pressure and production rate is one of the most significant challenges during the injection process. Recent experiences have shown that artificial intelligence (AI) is a reliable solution for taking the mentioned decision appropriately and in a least possible time. This study is attributed to the investigation of applying the artificial neural network (ANN) as an artificial intelligence method and a potent predictor for choosing the most proper location for injection in a GAGD process in a fractured carbonate reservoir. The results of this investigation clearly show the efficiency of the ANN as a powerful tool for optimizing the location of the injection wells in a GAGD process. The comparison between the results of ANN and black oil simulator indicated that the predictions obtained from the ANN is highly reliable. In fact the production flow rate and pressure can be obtained in every possible location of the injection well.

Case study: Comparison of enhanced heavy-oil recovery by CGI, WAG, and GAGD

ABSTRACTContinuous gas injection (CGI) in the conventional horizontal flooding patterns leads to severe gravity segregation and poor reservoir contact (sweep) volumes. To improve the sweep efficiency, the Water-Alternating-Gas (WAG) process has been widely practiced in the industry. However, the WAG process has not measured up to expectations, as evidenced by the low recoveries observed in several field cases.The Gas-Assisted Gravity Drainage (GAGD) process is designed and practiced based on gravity drainage idea and uses the advantage of density difference between injected gas and reservoir oil to overcome the drawbacks of the WAG process.In this study, a comparison of enhanced heavy-oil recovery by three methods (CGI, WAG, and GAGD) is conducted by a commercial numerical simulator in a sector model of an Iranian offshore field. For this purpose, different production scenarios are designed. Moreover, the effect of several parameters such as injection fluid (CO2, hydrocarbon gas), in situ oil viscosity (heavy or extremely heavy oil), rate and volume of injection, and also three different WAG ratios are studied.The results show that the GAGD method is not suitable for this field as the thickness of pay zone is low for vertical sweep efficiency and causes early breakthrough of injected gas. Also, CGI leads to lower recoveries compared to the WAG process, due to its unfavorable mobility ratio. Injection of CO2 instead of hydrocarbon gas results in higher sweep efficiency because of its viscosity reduction and swelling effects. In case of extremely heavy-oil recovery, with decreasing well spacing, the oil recovery factor increases as the drainage radius of wells reduces substantially due to high-viscosity oil.