Water Alternating Gas Injection Research Articles

Study Investigates Hydrate Formation Risk in WAG Changeover Operations

_ This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 218101, “Investigating the Effect of Carbon Dioxide Concentration on Hydrate Formation Risk From Water-Alternating-Gas (WAG) Changeover Operations,” by Farzan Sahari Moghaddam, SPE, Majid Abedinzadegan Abdi, SPE, and Lesley A. James, SPE, Memorial University of Newfoundland. The paper has not been peer reviewed. _ Hydrate formation is a flow-assurance challenge for offshore oil and gas operations with subsea pipelines, wells, and tiebacks. In water-alternating-gas (WAG) operations, hydrates can form within the injection wells when switching from water to gas and vice versa. This study investigates hydrate formation in a WAG injection well under water-to-gas and gas-to-water changeover operations. Introduction Few previous studies have focused on hydrate formation in gas injection and production wells. Hydrate formation in a gas well under particular enhanced oil recovery techniques requires more attention. This study aims to investigate the changeover operations of water-to-gas and gas-to-water (well depth: 4096 m) and the effects of gas composition changes in terms of CO2 content (5–44 wt%) and thermodynamic inhibition (5 m3 methanol) after water injection. In terms of flow rates, injection rates of 2300–3800 m3/d for water and 1 million std m3/d for gas, which are applicable for offshore Newfoundland and Labrador (NL), are studied. The complete paper includes a discussion of past studies on hydrate formation in production and injection-gas systems. Methodology Two scenarios were simulated: water-to-gas changeover and gas-to-water changeover over a range of CO2 concentrations of 5–44 wt%. For operational parameters, up to 3 days of shut-in period was considered for the changeover operations. The water injection rate of 2300 m3/d and gas injection rate of 1 million std m3/d were considered. The rate was increased to find the injection rate that could provide full displacement of the water phase within less than 1 hour from a water-to-gas changeover operation. The same injection rate is maintained for other natural-gas cases with increased CO2 content by changing the compressor injection pressure. After modeling the fluid with an appropriate cubic equation of state, the fluid model file was imported to the dynamic multiphase flow simulator. A sample WAG well from offshore NL where hydrate formation was experienced was considered for the simulations. After finalizing the setup of the well, the simulation scenario was finalized according to the changeover operation and the operating conditions. A sensitivity analysis was conducted on various concentrations of CO2 (5–44 wt%) followed by conducting both water-to-gas and gas-to-water changeover operations in the transient multiphase simulator. Finally, hydrate formation in presence of methanol was simulated, and the resulting profiles of hydrate formation temperature minus fluid temperature, known as DTHYD, were compared. The well depth is 4096 m from the seabed, and tubing internal diameter is 0.16 m. The seabed depth is 124 m below mean sea level. The bottomhole is known as the zero depth on the DTHYD, holdup, density, and pressure profiles, and the wellhead is considered to be 4096 m above the bottomhole depth in these profiles. A methanol slug was injected directly into the well under a sea temperature of 3°C at the end of water injection and before the shut-in duration.

Data-Analytics-Driven Sectorization Review Enables Efficient Reservoir Management

_ This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 216359, “Data-Analytics-Driven Subsurface Reservoir Sectorization Review of a Giant Abu Dhabi Onshore Field Carbonate Reservoir for Efficient Reservoir Management,” by Khalid Javid, Sara Alshkeili, and Fatema Al-Hammadi, ADNOC, et al. The paper has not been peer reviewed. _ The complete paper discusses an approach used to sectorize a mature onshore Abu Dhabi giant carbonate reservoir for the purposes of reservoir management, offtake, and injection balancing. The reservoir is developed under a line-drive water-alternating-gas (WAG) scheme in combination with peripheral water injection. The development plan for the reservoir includes massive deployment of maximum reservoir contact (MRC) horizontal wells and a gas-based enhanced oil recovery scheme. A practical data-driven approach, based on one of the operator’s integrated reservoir management (IRM) workflows, was selected for the purpose of sectorization. Field Development Background Reservoir A is part of a giant oil field considered low permeability. Its porosity ranges between 13 and 26%, while permeability increases from 1 md on the flanks to 50 md in the crest of the structure. Production began 30 years ago, and the development scheme has undergone several transformations since. Currently, it is being developed under mid-flank line-drive waterflooding combined with crestal WAG and peripheral water injection. The current recovery factor of Reservoir A is approximately 10%. Two field-trial pilots were implemented (gas-injection and water-injection pilots) and then were converted to WAG injection between 2007 and 2013. These locations show high gas/oil ratio (GOR) and high water cut (WC). The development scheme includes downspacing of the existing line-drive to approximately 300 m intended to enhance sweep efficiency and increase recovery factor. The number of wells is expected to increase substantially. To optimize well placement and reduce development capital expenditure and subsurface congestion with other development targets in the field, development will capitalize on long horizontal MRC wells. Reservoir Sectorization Objectives. The sectorization exercise undertaken for Reservoir A aimed to achieve the following: - Establish a manageable number of sectors and allow creation of relevant, meaningful reservoir management key performance indicators and more-efficient surveillance programs - Honor main geological features -Reflect reservoir pressure distribution and communication between different areas of the reservoir - Reflect fluid-front movement - Reflect well-performance trends - Honor future development plans (including MRC wells) Proposed Sectorization Options. Reservoir A originally was divided into 13 regions for reservoir management, surveillance, and reservoir monitoring planning purposes, including production and injection balancing, voidage replacement ratio (VRR), pressure performance, and diagnostic plots. At the start of the study, eight sectorization scenarios were proposed. These scenarios were evaluated following a methodology described in the complete paper, aiming to combine the initial 13 regions into a smaller number of sectors where possible. Each scenario was evaluated against criteria including data analytics; the scheme honoring most of the criteria with an optimal number of sectors would be selected.

Evaluating the efficacy of water alternating gas injection technique in the upper jurassic hydrocarbon reservoirs, considering saturation pressure

A tertiary method of enhanced oil recovery (EOR) based on the watergas alternating injection process (WG) is examined in this article based on the ratio between saturation pressure and reservoir pressure. A hydrodynamic simulation of the WAG process was carried out using TEMPEST MORE software (version 7,1). Many hydrocarbon fields worldwide are currently experiencing declining production rates. However, by utilizing advanced technologies like alternate injection of water and associated petroleum gas, the final oil recovery factor (RF) can be significantly increased. To ensure successful water injection experiments in real fields, it is crucial to consider the ratio of saturation and reservoir pressures during injection. Any negligence in this regard can lead to failure of the experiments aimed at enhancing oil recovery through WAG application. The research examines two variations of reservoir system models with certainty. In the initial model, the saturation pressure is lower than the reservoir pressure, signifying an under-saturated state of the reservoir system containing dissolved gas. Consequently, when accompanying petroleum gas is introduced, it mixes with oil at precise thermobaric conditions. According to the second model, the reservoir is saturated with gas at a saturation pressure equivalent to the formation pressure. A thorough assessment indicates that the success of water alternating gas injection (WAG) is heavily influenced by the initial state of the reservoir. In situations where the reservoir is already saturated with gas, implementing water-gas stimulation may be ineffective as gas breakthroughs may occur rapidly. However, implementing WAG in saturated reservoirs can lead to a 1 – 8% rise in overall oil production, observable within 3 – 4 years, depending on the timing after waterflooding. Simultaneously, in the case of reservoirs with a low saturation pressure, which exhibits an undersaturated reservoir system, the implementation of water alternating gas injection can be seen as a viable approach for enhancing oil recovery. WAG is a proven method that confidently increases oil recovery up to 10% in undersaturated reservoirs compared to conventional waterflooding.

Chemical-Assisted CO2 Water-Alternating-Gas Injection for Enhanced Sweep Efficiency in CO2-EOR.

CO2-enhanced oil recovery (CO2-EOR) is a crucial method for CO2 utilization and sequestration, representing an important zero-carbon or even negative-carbon emission reduction technology. However, the low viscosity of CO2 and reservoir heterogeneity often result in early gas breakthrough, significantly reducing CO2 utilization and sequestration efficiency. A water-alternating-gas (WAG) injection is a technique for mitigating gas breakthrough and viscous fingering in CO2-EOR. However, it encounters challenges related to insufficient mobility control in highly heterogeneous and fractured reservoirs, resulting in gas channeling and low sweep efficiency. Despite the extensive application and research of a WAG injection in oil and gas reservoirs, the most recent comprehensive review dates back to 2018, which focuses on the mechanisms of EOR using conventional WAG. Herein, we give an updated and comprehensive review to incorporate the latest advancements in CO2-WAG flooding techniques for enhanced sweep efficiency, which includes the theory, applications, fluid displacement mechanisms, and control strategies of a CO2-WAG injection. It addresses common challenges, operational issues, and remedial measures in WAG projects by covering studies from experiments, simulations, and pore-scale modeling. This review aims to provide guidance and serve as a reference for the application and research advancement of CO2-EOR techniques in heterogeneous and fractured reservoirs.

Hybrid EOR Performance Optimization through Flue Gas–Water Alternating Gas (WAG) Injection: Investigating the Synergistic Effects of Water Salinity and Flue Gas Incorporation

Hybrid EOR Performance Optimization through Flue Gas–Water Alternating Gas (WAG) Injection: Investigating the Synergistic Effects of Water Salinity and Flue Gas Incorporation

Monte Carlo Simulation of the CO2 Flooding Efficiency at a Core Scale for Different Oil Compositions

The evaluation of water-alternating-gas (WAG) efficiency and profitability is complicated by a large number of reservoir, operating, and economic parameters and constraints. This study aims at understanding the influence of the oil composition on different WAG injections. By employing compositional reservoir modeling and the Monte Carlo method to characterize the diversity of oils occurring in nature, we simulate the microscopic displacement efficiency of CO2 flooding when it is applied to both light- and heavy-oil reservoirs. We find that the economic performance of WAG in both miscible and immiscible scenarios is mainly characterized by the dimensionless injection rate and the oil density at surface conditions. Neither the bubble point pressure nor the minimum miscibility pressure can be used for the quantification of the optimal WAG parameters. We present our estimates of the best strategies for the miscible and immiscible injections and verify some of our previous results for randomly sampled oils. In particular, we demonstrate that CO2 flooding is better to apply at higher-dimensionless injection rates. We show that the injection of CO2 organized at a light-oil reservoir results in a higher profitability of WAG, although this comes at the cost of lower carbon storage efficiency.

The Application of Water Alternating Gas Injection to Maximize Oil Recovery in the Niger Delta

One of the most significant challenges for extending production life in mature waterflood fields is high water cut. Couple with high reservoir heterogeneity, extensive layering and faulting, these fields often developed irregular flood patterns after decades of production which compounded the challenge of optimizing recovery from these fields. The severity of this problem has been observed in the Niger Delta oil fields, where several matured fields are producing at high water cut after many years of waterflooding. This study aimed to determine the viability of Water Alternating Gas (WAG) injection in comparison with Waterflooding and Gas injection methods for optimum oil recovery of an oil field in Niger Delta. WAG injection had a maximum field oil efficiency (FOE) of 31%, a field oil production total (FOPT) of 4,944 MMSTB, a plateau time of 14 years and a total field water production (FWPT) of 18,356 MMSTB. Waterflooding had a FOE of 23%, a FOPT of 37,466 MMSTB, a plateau time of 9 years and a FWPT of 96,895 MMSTB. Whereas gas injection had an FOE of 15%, a FOPT of 36,063 MMSTB, a plateau time of 3.2 years, and a FWPT of 13,444 MMSTB, respectively. From the comparative analysis of the three recovery methods, WAG injection outperformed both waterflooding and gas injection with the highest FOE of 31% and the longest plateau time of 14 years, respectively.

Numerical study of the mechanisms of nano-assisted foam flooding in porous media as an alternative to gas flooding

Oil reservoirs are nearing maturation, necessitating novel enhanced oil recovery (EOR) techniques to meet escalating global energy demands. This demand has spurred interest in reservoir production analysis and forecasting tools to enhance economic and technical efficiency. Accurate validation of these tools, known as simulators, using laboratory or field data is pivotal for precise reservoir productivity estimation. This study delves into the application of nanoparticles in foam flooding for mobility control to improve sweep efficiency. Foam generation can occur in-situ by simultaneous injection of surfactants and gas or through pre-generated foam injection into the reservoir. In this work, a series of systematic simulations were run to investigate how much injected fluids can reduce gas breakthrough while also increasing oil recovery. Subsequently, we analyzed the most effective optimization strategies, considering their economic limits. Our primary objective is to numerically model nanofoam flooding as an innovative EOR approach, synergizing foam flooding mechanisms with nanotechnology benefits. In this work, modeling of nanoparticles in foam liquid was represented by the interfacial properties provided to the injection fluid. Additionally, we simulated Water-Alternating-Gas (WAG) injection schemes across various cycles, comparing their outcomes. Our results showed that nanofoam injection achieved a higher recovery factor of at least 38% and 95% more than WAG and gas injections, respectively. The superior efficiency and productivity of foam injection compared to WAG and gas injection suggest an optimal EOR approach within the scope of our model. These simulated optimization techniques contribute to the future development of processes in this field.

Research on the Timing of WAG Intervention in Low Permeability Reservoir CO2 Flooding Process to Improve CO2 Performance and Enhance Recovery

In low permeability reservoirs, CO2 flooding usually leads to gas channeling, whereby a significant amount of CO2 bypasses the oil-bearing formation and fails to effectively displace oil. Introducing water-alternating-gas (WAG) flooding, utilizing water phase stability-driven processes, serves to suppress gas channeling and enhance oil recovery rates. Implementing WAG flooding, which utilizes water phase stability-driven processes, helps suppress gas channeling and improve oil recovery rates. The timing of implementing WAG flooding is crucial. Initiating WAG flooding prematurely can limit the efficiency of CO2 displacement, while initiating it with delays may result in severe gas channeling, resulting in decreased production and increased environmental risks. Finding the balance point is the challenge. The balance point can effectively control gas channeling without reducing the efficiency of CO2 flooding. In this paper, the timing of WAG flooding in low permeability reservoirs is studied in detail. Firstly, this study conducted experimental research to investigate the CO2 displacement process in both homogeneous and heterogeneous cores. Furthermore, it validated the correlation between the timing of WAG injection and the heterogeneity of the cores. The experimental results indicated the existence of an optimal timing for WAG injection, which is correlated with the degree of heterogeneity. Numerical simulation studies were performed to simulate the characteristics of the light oil–CO2 system using the Peng–Robinson (PR) equation. Furthermore, a history matching analysis was performed to validate the experimental results and investigate the correlation between WAG injection and the degree of heterogeneity. The study concluded that as the degree of heterogeneity increases, initiating WAG injection earlier leads to a more significant suppression of gas channeling, increased water–gas interaction, improved gas–oil contact, and enhanced the synergistic effect of increasing the resistance and pressure of WAG flooding and controlling gas channeling. This finding has significant practical implications, as the optimization of WAG injection timing can enhance oilfield production efficiency.

The Effect of Different Gas Water Ratio on Recovery Factor and CO2 Storage Capacity in Water Alternating Gas Injection. A Case Study: “V” Field Development, North Sea

CO2 injection is one of the Enhanced Oil Recovery (EOR) methods. In this study Water alternating gas (WAG) CO2 injection method was used to obain the maximum sweep efficiency. The purpose of this study was to analyze the effect of gas water ratio (GWR) value on recovery and CO2 storage capacity, and to analyze the best scenario in term of technical objective.
 This study was carried out using E300 reservoir simulator. The increase in recovery and CO2 storage were observed throught the parameters of recovery factor and CO2 storage capacity, while the determination of the best scenario in term of technical objective was observed using the parameters of objective function. This study was carried out in 3 different scenarios, which were the injection of 100% CO2, 60% CO2and 40% water, and 40% CO2 and 60% water
 Based on the observation, it was founded that third scenario with the GWR of 40:60 resulted the highest cumulative production and recovery factor with the value reaching 14.1 milliom m3 and 67.4%. Meanwhile the second scenario with the GWR of 60:40 has the highest CO2 storage capacity of 3 billion Sm3 CO2. The second scenario has the best performance in term of technical objective with the value of objective function reaching 0.45.

Pore-Scale Characterization of CO2 Trapping and Oil Displacement in Three-Phase Flow in a Heterogeneous Layered Sandstone

Summary Permeability variation in the vertical direction, a typical sandstone reservoir heterogeneity, can trap a large amount of oil in the low-permeability layer. We performed water-alternating-gas (WAG) injection and CO2 foam flooding on a specially constructed millimeter-sized layered sandstone and investigated fluid distribution using high-resolution X-ray microtomography. Based on the segmented images, CO2 capillary-trapping capacity, oil recovery, Euler number, shaper factor, capillary pressure, and fluid flow conductivity were calculated. Our results show that increasing the number of WAG cycles favored CO2 capillary trapping, and oil recovery was enhanced by the WAG strategy. However, there was still a significant amount of oil trapped in the low-permeability layer. After the WAG injection, the connectivity of the residual oil clusters decreased, the capillary pressure of the oil clusters increased, and oil flow conductivity decreased. This was not conducive to further oil recovery. The subsequent injection of CO2 foam effectively recovered the oil in the low-permeability layer. During the no-injection period, we observed a crossflow phenomenon caused by gravity segregation (the high-permeability layer was located below the low-permeability layer), i.e., oil in the low-permeability layer decreased while oil in the high-permeability layer increased, which is beneficial for subsequent oil production. Furthermore, CO2 moved upward driven by gravity, and although capillary barriers could prevent CO2 from escaping, subsequent water injection was essential to improve the stability of CO2 capillary trapping. This work accurately quantifies the distribution of oil and gas in high- and low-permeability layers, thus providing fundamental data for oil recovery and CO2 trapping in reservoirs with vertical heterogeneity. Although the sample used in the experiment was not natural reservoir rock, our results imply that when the permeability ratio between the two layers is greater than 2, sufficient attention must be paid to the fluid distribution differences caused by this layered heterogeneity. Different displacement strategies, such as WAG and CO2 foam flooding, or gravity differences between oil and gas can be used to enhance oil recovery.

Impact of interphase component transfer on CO2 distribution and pH during CO2 injection in the subsurface

Single phase CO2 injection and CO2 water alternating gas (WAG) injection processes are simulated using reactive transport modelling to understand the inter-phase component transfer between CO2, brine and oil, and to address geochemical (aqueous) reactions induced by CO2 in the near wellbore region. In this research, calculations are performed using a numerical one-dimensional cartesian model with homogenous properties. We investigate how fast the pH changes as CO2 is injected into the system and how the presence of oil affects the velocity of the pH front. We measure the velocity of the front at which oil becomes completely desaturated with respect to CO2 – referred to as the “CO2 desaturation front” and compare it with the classical Buckley-Leverett saturation front displacement during WAG injection. We also study the impact of the WAG cycles on the CO2 desaturation front velocity and the pH change. The study showed that the presence of hydrocarbons in the model buffers and delays the pH drop. By the end of each water cycle all the CO2 was removed from the contacted oil phase within the first few meters from the well. The CO2 desaturation front travels at approximately one twentieth of the phase saturation front velocity during the first three WAG cycles, but it then stopped for later cycles, which gives an indication of the extent of the desaturation of oil. During the WAG injection, different pH fronts developed due to the impact of each cycle on the fluid composition and component transfer. The pH reduction during the last WAG cycles was greater near the injection well as most of the lighter hydrocarbon components were displaced out of the residual “oil”, meaning the CO2 content of this residual phase was higher than for initial cycles. This would result in a greater risk of calcite dissolution around the injection well if there were calcite present in the rock formation.

A Novel Multi-Phase Strategy for Optimizing CO2 Utilization and Storage in an Oil Reservoir

In this paper, an innovative multi-phase strategy is developed and numerically tested to optimize CO2 utilization and storage in an oil reservoir to support low carbon transition. In the first phase, the water-alternating-gas (WAG) injection is conducted to simultaneously store CO2 and produce crude oil in the reservoir from the respective injection and production wells. In the second phase, the injection and production wells are both shut in for some time to allow CO2 and water to be stratigraphically separated. In the third phase, CO2 is injected from the upper part of the reservoir above the separated water layer to displace water downwards, while fluids continue to be produced in the water-dominated zone from the lower part of the production well. Lastly, the production well is finally shut in when the produced gas–water ratio (GWR) reaches 95%, but CO2 injection is kept until the reservoir pressure is close to the fracture pressure of its caprocks. The numerical simulations show that implementing the proposed multi-phase strategy doubles CO2 storage in comparison to applying the WAG injection alone. In particular, 80% of the increased CO2 is stored in the third phase due to the optimized perforation. In addition, the CO2 injection rate in the last phase does not appear to affect the amount of CO2 storage, while a higher CO2 injection rate can reduce the CO2 injection time and accelerate the CO2 storage process. In the proposed strategy, we assume that the geothermal energy resources from the produced fluids can be utilized to offset some energy needs for the operation. The analysis of energy gain and consumption from the simulation found that at the early stage of the CO2-WAG phase, the energy gain mostly comes from the produced oil. At the late stage of the CO2-WAG phase and the subsequent phases, there is very little or even no energy gain from the produced oil. However, the geothermal energy of the produced water and CO2 substantially compensate for the energy loss due to decreasing oil production. As a result, a net energy gain can be achieved from the proposed multi-phase strategy when geothermal energy extraction is incorporated. The new multi-phase strategy and numerical simulation provide insights for practical energy transition and CO2 storage by converting a “to be depleted” oil reservoir to a CO2 storage site and a geothermal energy producer while enhancing oil recovery.

Comparative studies on numerical sensitivity of different scenarios of enhanced oil recovery by water-alternating-gas (CO2) injection

Enhanced oil recovery by CO2 injection technology (CO2-EOR) plays a crucial role in enhancing oil production and the permanent sequestration of anthropogenic CO2 in depleted oil reservoirs. However, the availability of CO2 in oil field locations and its mobility in contrast with reservoir fluids are prime challenges in CO2-EOR. The cost of CO2 and its availability at the oil fields has prompted investigations on efficient injection of CO2 at the fields to achieve the best sweep efficiency possible. Injection strategies such as water-alternating-gas (WAG), simultaneous vertical and horizontal WAG, simultaneous water injection into the aquifer and vertical WAG, water and gas injection simultaneously but separately (SS-WAG), and water and gas injection simultaneously but not separately (SNS-WAG) play a significant role, as well as the purity of CO2. In this work, the significance of the above criteria was investigated individually and in combination. The coupled sequence of injection rate, soaking time, WAG ratio, and purity of injected CO2 for enhancement of oil production were delineated. A realistic reservoir simulation model conceptualizing the CO2-EOR system with five spot injection patterns was developed by the company CMG. The history-matched model that was developed was used to investigate the sensitivity of the coupled effects to the criteria listed above on oil recovery. Numerical investigations quantitatively emphasized that purity and soaking time of CO2 have an inverse effect in the oil production rate and that SNS-WAG resulted in a better oil production rate than SS-WAG.

Research and simulation study of different technological processes of miscible CO2 water alternating gas injection

One of the most commonly used methods for EOR in recent years is the water-alternating-gas (WAG) method, WAG injection is an oil recovery method aiming to improve displacement ratio, sweep efficiency and adjust the alignment of displacement in different layers to improve oil recovery and pressure maintenance. The main mechanism of it is 1) bettering the mobility control, 2) improvement of sweep efficiency (comparing to gas methods) and 3) the displacement efficiency (comparing to waterflooding). Many studies have been done in the past, but due to the increasing hard-to-recover field and facing difficulties during the production, the traditional WAG is facing problems that need to be coupled with. Implementation of new combinational methods and changes in the injection process to meet the needs have been developed during the last two decades. In this study, a simulation investigation has been done to compare proposed changes in the injection process to find the optimal injection scheme for the high heterogeneity - low permeability field. After analyzing the output of the simulation, the results show that each of the technologies has its advantages and disadvantages, and need to be applied according to the field constraints and requirement. Keywords: water alternating gas (WAG); enhanced oil recovery; reservoir simulation; injection scheme; heterogeneity; permeability.

Simulation study of water and gas injection process into the Azadegan reservoir for enhanced oil recovery

AbstractIt is necessary to improve oil production from reservoirs. Various methods have been proposed to increase oil extraction from reservoir. Each method has specific challenges. In this research, the effect of water and gas injection in to Azadegan reservoir has been analyzed. Azadegan oil field is located south of Iran. In this study, water, immiscible gas and water alternating gas injected to reservoir and its effect on enhanced oil recovery have been investigated. Finally, a comparison between results of methods is provided. Results show that effective method for enhanced oil recovery is immiscible gas injection with 46% oil production efficiency and water alternating gas injection with 36% oil production efficiency. This study shows that oil production efficiency can be increased if duration of gas injection is increased. This study shows, increasing viscosity of water in water alternating gas scenario did not improve the production of Azadegan reservoir.

Experimental evaluation of the water-based enhanced oil recovery methods in ultra-tight reservoirs

Water-based enhanced oil recovery methods have been developed to improve the oil production rate from ultra-tight reservoirs. By coupling the effect of surfactant as wettability alteration and water alternating gas injection method, we aimed to determine the most efficient enhanced oil recovery technique. We performed seven injectivity scenarios to measure the oil recovery factor by introducing the alkylbenzene sulfonic acid (LABSA) as a surfactant agent during the active carbonated water alternating gas (ACWAG) injection. To consider the effect of slug size during water alternating gas injection, we used two different slug sizes (0.3, and 0.6). After the water breakthrough, a little oil volume was produced, and the maximum oil recovery factor at 1.5 Pore Volume (PV) was 26%. This issue corresponded to the water channeling after the breakthrough point. For smaller slug sizes (0.3), the maximum oil recovery factor (78%) was reached in smaller pore volumes. One of the exciting results wass the considerable influence of slug ratio during the water alternating gas (WAG) injection, in which it provided more oil recovery factor (83%) when the gas volume is higher than the water volume. Finally, by introducing the coupling effect of active carbonated water (made by LABSA surfactant) and WAG injection, the maximum oil recovery factor was 85%, corresponding to the better efficiency of active carbonated water in interfacial tension reduction. The results of this comprehensive investigation can be extended in ultra-tight sandstone reservoirs and can be applied as a further guideline in numerical simulations.Graphical abstract

Optimization of design variables and control rules in field development under uncertainty: A case of intelligent wells and CO2 water alternating gas injection

This paper focuses on life-cycle optimization of oil field development plan under uncertainty. The optimization problem included a wide range of design variables and control rules related to wells and platform in a realistic benchmark case (UNISIM–II–D) with a known ground truth reservoir model, UNISIM–II–R, that resembles Brazilian pre-salt fractured carbonate reservoirs in their early development stage. The design variables were the number and location of wells, the fluid processing capacity of the platform, and the location of internal control valves (ICVs), whereas the control rules were the setting of ICVs, production and injection rates, and the duration of the water-alternating-gas (WAG-CO2) cycle. An iterative sequential optimization framework was developed to deal with the massive search space and complex parameterization. The optimization further took into consideration the subsurface, operational and economic uncertainties, and used iterative discrete Latin hypercube method as the search algorithm. The robust optimization was carried out on a subset of representative models derived from the reduction of a large ensemble of data-assimilated models. As a low-fidelity representation of the compositional fluid model, a black-oil model was used to reduce simulation runtime. To validate our optimization framework, we applied the optimal development strategy to the ensemble of compositional simulation models, as well as the ground truth model. The true model's responses were within the ranges predicted by the compositional ensemble, confirming the optimization framework's reliability. The general methodology developed in this study, as well as our findings, can be used to optimize other similar real-world complex and high-risk field development projects, and are especially useful in closed-loop field development and management practices.

A Systematic Experimental Study to Understand the Performance and Efficiency of Gas Injection in Carbonate Reservoirs

Summary Gas injection is the most widely applied recovery method in light, condensate, and volatile oil carbonate reservoirs. Gas has high displacement efficiency and usually results in a low residual oil saturation in the part of the reservoir that is contacted with gas. The displacement efficiency increases when the injected gas is near-miscible or miscible with the oil. In addition to nitrogen and hydrocarbon gas projects, carbon dioxide (CO2) enhanced oil recovery (EOR) has been the dominant gas EOR process. Gas-based EOR has been implemented in both mature and waterflooded carbonate reservoirs. In this paper, we present the results of a detailed experimental study aimed at understanding the performance and efficiency of gas injection in carbonate reservoirs. A series of immiscible and miscible gas injection coreflood experiments were performed using limestone reservoir cores under different injection strategies. To minimize laboratory artifacts, long cores were used in the experiments, and to observe the effect of gravity, both 2 in. diameter and 4 in. diameter (whole core) were used. The experiments were performed under reservoir conditions using live crude oil. The core wettability was restored by aging the core in crude oil for several weeks under reservoir temperature. Hydrocarbon gas (methane) was used as the immiscible injectant, and both CO2 and a mixture of 50% C1 and 50% CO2 were used as miscible injectant. All gas injection experiments were performed using vertically oriented cores, and the gas was injected from the top unless it is stated otherwise. The main parameters investigated in this study are as follows: The effect of miscibility on oil recovery for both continuous gas injection and water alternating gas (WAG). The effect of gravity on gas sweep efficiency compared to waterflooding. The effect of gas-oil interfacial tension (IFT) on oil recovery when using the same oil. The effect of oil type on oil recovery using the same injected gas at miscible and immiscible conditions. The effect of immiscible gas injection on subsequent miscible gas injection performance. Impact of CO2 cycle length on ultimate oil recovery. The impact of the order of fluid injection where multiple WAG injection cycles were performed in separate experiments after water or gas injection. The main conclusions of this study are as follows: As expected, miscibility has a significant impact on displacement efficiency and oil recovery where miscible gas recovered more than 20% extra oil compared to immiscible gas. A significant variation in oil recovery is observed for miscible gas injection (i.e., more than 10 saturation units difference) depending on the minimum miscibility pressure (MMP) between the injected gas and crude oil, even when both experiments are performed at miscible conditions using the same injected gas. The performance of tertiary CO2 flood was adversely affected by the slug of immiscible gas injected. Therefore, it is not recommended to have immiscible gas injection before miscible gas injection. Regardless of injected gas type, gas injection with similar IFTs achieved similar oil recovery. During WAG experiments, starting the injection cycles with water or gas did not have any impact on the ultimate oil recovery for both miscible and immiscible cases for one of the reservoirs, while WAG_G (WAG starting with gas injection) recovered more oil for another reservoir. Gravity has a significant impact on oil recovery for both miscible and immiscible gas injections. A significant difference is observed in oil recovery when comparing CO2 injection on 2-in.- and 4-in.-diameter core samples or when comparing horizontal vs. vertical immiscible gas injection and WAG experiment. The longer the CO2 slug size, the higher the oil recovery observed in gas injection experiments. The results of this study provide a rich and rarely available set of experimental data that can help improve and optimize gas and WAG injection in oil-wet carbonates.

WAG injection in porous media: A microfluidic analysis

Water Alternating Gas (WAG) injection is one of the common methods to displace oil in porous media, which is relevant to many applications including soil remediation or enhanced oil recovery from underground reservoirs. We conducted a comprehensive series of experiments to extend the fundamental understanding of WAG injection in porous media. Three types of porous media were manufactured with a 3D printer in this investigation. The first medium had single permeability (S), the second one was fractured (F), and the third one was a medium with dual permeability (D). The porous media were saturated with silicone oil. Nitrogen and water were used to displace oil under different WAG ratios of 4:1, 2:1, 1:1, 1:2, and 1:4. High-resolution imaging was used to quantify displacement dynamics. The highest oil recovery was observed under WAG ratio of 1:1, i.e., the equal slug size of the water and gas. The obtained results showed that the WAG ratio of 1:1 injection in the S medium recovered 55% of the oil, while in the F and D medium, the recovery efficiency was 36% and 47%, respectively. Our findings offer new insights regarding effects of heterogeneity on WAG injection efficiency in porous media under different boundary conditions.