Gas Process Displacement Efficiency Comparisons on a Carbonate Reservoir

2006 ◽  
Vol 9 (06) ◽  
pp. 621-629 ◽  
Author(s):  
Patrick Egermann ◽  
Michel Robin ◽  
Jean-Marc N. Lombard ◽  
Cyrus A. Modavi ◽  
Mohammed Z. Kalam
Keyword(s):  
Oil Recovery ◽  
Oil And Gas ◽  
Gas Injection ◽  
Displacement Efficiency ◽  
Sweep Efficiency ◽  
Permeability Model ◽  
Oil Saturation ◽  
Gas Phases ◽  
Three Phase ◽  
Water Blocking

Summary Secondary- and tertiary-recovery processes based on gas injection can extend the life of waterflooded reservoirs by maximizing the oil recovery. However, the injection strategy needs to be studied carefully to optimize the overall sweep efficiency. In particular, the impact of possible water blocking on the recovery has to be addressed. For that purpose, a series of experiments was performed under reservoir conditions on a carbonate rock type to compare the displacement efficiencies of a secondary gas injection, a tertiary gas injection, and a simultaneous water-alternating-gas (SWAG) injection. The experiments were carried out on composite cores consisting of several carefully selected reservoir core plugs of the chosen rock type. The operating pressure was lower than the minimum miscible pressure (MMP) and reflected the current reservoir pressure. Phase exchanges were monitored continually during the hydrocarbon recovery, including the chromatographic analysis of the produced gas. The final oil recovery resulting from the three types of experiments was very good [approximately 90% original oil in place (OOIP) at surface conditions after 6 pore-volume (PV) injection] and quite similar within the expected experimental error, regardless of the sequence of gas injection. The low remaining oil saturation (ROS) values observed were consistent with competing processes of both viscous displacement of oil by gas and phase exchanges occurring between oil and gas. Because of the nature of the injected gas (rich gas from the first separation stage), a condensing/vaporizing process had to be considered. The SWAG injection speeds up the oil recovery by mobility control of the water phase. This enhances the sweep efficiency by viscous drive. A water-blocking effect was found to be negligible because it could be anticipated due to wettability consideration. The influence of the fluid description (equation of state, or EOS) and the three-phase relative permeability model on the simulation results was studied. An excellent agreement between simulation and production data was obtained with both gas/oil relative permeability data measured at ambient conditions on a restored composite core and an appropriate EOS (with seven pseudos). The condensing/vaporizing process that strips the intermediate compounds from the oil phase to the gas phase was properly taken into account with this appropriate EOS. The influence of the three-phase permeability model (either "geometrical construction" or Stone1) on the results was found to be small. Introduction For enhanced oil recovery (EOR) purposes, miscible or immiscible hydrocarbon gas injections have been applied successfully in many oil reservoirs throughout the world (Thomas et al. 1994; Lee et al. 1988). Compared to water injection, gas injection is associated with higher microscopic displacement efficiency due to the low value of the interfacial tension (IFT) between the oil and gas phases. IFT tends toward zero when miscibility is reached, which means that the oil recovery can be total in the swept area. Even when miscibility is not reached, the mass-transfer mechanisms that occur between oil and gas phases lead to low IFT values when compared to waterflooding. Even under those conditions, regarding remaining oil-saturation values, gas injection appears to be an interesting recovery process.

Three-Phase Imbibition Relative Permeability

10.2118/90-pa ◽  
1961 ◽  
Vol 1 (04) ◽  
pp. 254-258 ◽  
Author(s):  
J. Naar ◽  
R.J. Wygal
Keyword(s):  
Oil Recovery ◽  
Oil And Gas ◽  
Water Flooding ◽  
Pressure Curve ◽  
Complete Wetting ◽  
Oil Saturation ◽  
Gas Saturation ◽  
Three Phase ◽  
Oil Gas ◽  
Wetting Fluid

Abstract An equation for three-phase (water, oil, gas) imbibition oil permeability is developed, assuming the water to be the dominant wetting fluid. Oil isoperms are obtained for consolidated sandstones characterized by. The evolution of an oil-gas system imbibing water from is shown to proceed along a line of constant oil saturation with increasing oil permeability and decreasing gas saturations. When the gas saturation cannot be reduced further, the system evolves along a line of constant with decreasing oil saturation and permeability. The initial gas saturation is shown to reduce markedly the effect of complete wetting by either oil or water on flow performance. Introduction Imbibition oil isoperms are required for performance prediction when a well is producing water, oil and gas. This situation occurs in multiphase displacements such as underground combustion, steam injection and the water flooding of highly depleted reservoirs. In a recent paper, a model was presented for the prediction of two-phase imbibition characteristics. This paper extends the imbibition model to the case of three phases by assuming that the water is the dominant wetting fluid. The following results were obtained from the model:an analytical expression of oil isoperms;oil isoperms as functions of reduced water, oil and gas saturations, valid for all sandstones having a capillary pressure curve which can be approximated by; andevaluation of the three-phase flow performance as dictated by complete wetting by either oil or water. The agreement between predicted and observed oil recovery in the presence of a gas phase, reported in Ref. 1, is a partial support for the present development. However, experimental data are not available at this time to check fully the model predictions. Perhaps this paper will stimulate the collection of such data. THEORETICAL The imbibition model of a porous medium has been described previously, and the reader is referred to the paper of Naar and Henderson for details. In brief, the model is formed by the random interconnection of straight capillaries, with a provision for the blocking of the non-wetting phase by the invading wetting fluid.

Experimental Investigation of Enhanced Oil Recovery by Thermal Foam Flooding

2011 ◽  
Vol 236-238 ◽  
pp. 814-819 ◽  
Author(s):  
Hui Qing Liu ◽  
Jing Wang ◽  
Peng Cheng Hou ◽  
Bing Ke Wang
Keyword(s):  
Oil Recovery ◽  
Resistance Factor ◽  
Displacement Efficiency ◽  
Liquid Ratio ◽  
Sweep Efficiency ◽  
Oil Saturation ◽  
Foaming Agent ◽  
Foaming Agents ◽  
Nitrogen Foam ◽  
Foam Flooding

Foam has been widely used in petroleum industry. It could enhance oil recovery by the means of improving mobility ratio, selective plugging and lowering the interfacial tension(IFT) of oil and water. The influences of concentration, temperature, gas-liquid ratio, permeability and oil saturation on the plugging property of 3 foaming agents were studied experimentally. The foaming agent concentration and the ratio of steam to nitrogen for thermal foam flooding were optimized. Displacement experiments were performed to investigate the EOR effect of 2# foaming agent. It was shown that the resistance factor increased with the increase of the concentration, gas-liquid ratio and permeability and the increase velocity slowed down in the later period of experiments. The optimal concentration was 0.5wt% and the optimum gas-liquid ratio was 1:1. The resistance factor reduced with increasing oil saturation. The plugging ability lost when the oil saturation was greater than 0.2. The resistance factors of 1# and 2# foaming agents decreased with increasing temperature but 3# increased. The best concentration was 0.6wt% and the ratio of steam to nitrogen was 3:2 for steam and nitrogen foam flooding. In the process of thermal foam flooding, oil recovery increased by 20.82%, and the sweep efficiency and displacement efficiency was 13% and 24.6% , separately.

scholarly journals Compositional Modeling of Impure CO2 Injection for Enhanced Oil Recovery and CO2 Storage

2021 ◽  
Vol 11 (17) ◽  
pp. 7907
Author(s):  
Hye-Seung Lee ◽  
Jinhyung Cho ◽  
Young-Woo Lee ◽  
Kun-Sang Lee
Keyword(s):  
Enhanced Oil Recovery ◽  
Oil Recovery ◽  
Carbon Capture ◽  
Oil And Gas ◽  
Co2 Storage ◽  
Carbon Capture And Storage ◽  
Co2 Injection ◽  
Displacement Efficiency ◽  
Compositional Simulation ◽  
Sweep Efficiency

Injecting CO2, a greenhouse gas, into the reservoir could be beneficial economically, by extracting remaining oil, and environmentally, by storing CO2 in the reservoir. CO2 captured from various sources always contains various impurities that affect the gas–oil system in the reservoir, changing oil productivity and CO2 geological storage performance. Therefore, it is necessary to examine the effect of impurities on both enhanced oil recovery (EOR) and carbon capture and storage (CCS) performance. For Canada Weyburn W3 fluid, a 2D compositional simulation of water-alternating-gas (WAG) injection was conducted to analyze the effect of impure CO2 on EOR and CCS performance. Most components in the CO2 stream such as CH4, H2, N2, O2, and Ar can unfavorably increase the MMP between the oil and gas mixture, while H2S decreased the MMP. MMP changed according to the type and concentration of impurity in the CO2 stream. Impurities in the CO2 stream also decreased both sweep efficiency and displacement efficiency, increased the IFT between gas and reservoir fluid, and hindered oil density reduction. The viscous gravity number increased by 59.6%, resulting in a decrease in vertical sweep efficiency. In the case of carbon storage, impurities decreased the performance of residual trapping by 4.1% and solubility trapping by 5.6% compared with pure CO2 WAG. As a result, impurities in CO2 reduced oil recovery by 9.2% and total CCS performance by 4.3%.

Parametric Investigation of WAG Floods Above the MME

SPE Journal ◽  
2007 ◽  
Vol 12 (02) ◽  
pp. 224-234 ◽  
Author(s):  
Leonardo Bermudez ◽  
Russell Taylor Johns ◽  
Harshad Champaklal Parakh
Keyword(s):  
Oil Recovery ◽  
Oil And Gas ◽  
Molecular Diffusion ◽  
Numerical Dispersion ◽  
Displacement Efficiency ◽  
Sweep Efficiency ◽  
Phase Zone ◽  
Two Phase ◽  
Recovery Method ◽  
Critical Locus

Summary Water-alternating-gas floods (WAG) are commonly used to improve sweep efficiency in heterogeneous reservoirs. There has been little reported in the literature, however, on the effectiveness of WAG processes where the gas is enriched above the minimum miscibility enrichment composition (MME). This paper examines how to optimize WAG processes for enriched gasfloods above the MME, particularly as a primary recovery method. Compositional simulations of x-z cross-sections are used to quantify the effects of WAG parameters, numerical dispersion, level of enrichment, and heterogeneity on local displacement efficiency and sweep efficiency. The main conclusions of this research show that the richer the gas above the MME, the fewer the number of WAG cycles required for maximum oil recovery at a given WAG ratio. Another significant observation is that overenrichment above the MME improves recovery the most when the largest permeability layers are at the bottom of the reservoir. Continuous slug injection performs better than WAG when the largest permeability layers are at the bottom of the aquifer, richer gases are used, and the vertical to horizontal permeability ratio is small. Introduction Gas enrichment is one of the important optimization variables in WAG enriched-gas floods. Recoveries from slimtube experiments with continuous gas injection often give a sharp bend at the minimum enrichment for miscibility (MME). Above the MME, slimtube recoveries do not increase significantly with enrichment. The optimum enrichment required to maximize recovery on a pattern scale in the field, however, is likely different from the MME. The difference in the optimum enrichment may be largely the result of greater mixing in the reservoir than exists in slimtubes. In addition, enrichment may impact sweep efficiency in 2D displacements. Oil and gas mixing in a reservoir can include mechanisms such as molecular diffusion, mechanical dispersion, gravity crossflow, viscous crossflow, and capillary crossflow. WAG in particular causes significant mixing of reservoir and injected fluids, depending on the total volume of the gas injected (slug volume), the WAG ratio, and the number of gas cycles or WAG frequency. There are several reasons why recovery could increase for gas enrichments above the MME. First, the density and viscosity of the gas will increase with enrichment, which may improve sweep efficiency. Second, mixing can cause an otherwise multicontact miscible flood (MCM) to develop some two-phase flow (Johns et al. 1993; Walsh and Orr 1990; Pande and Orr 1989; Lake 1989). Richer gases mix closer to the critical locus in the two-phase zone, which causes a smaller and slower lean gas bank. A smaller lean gas bank could improve sweep efficiency. Last, richer gases, which mix near the critical locus, decrease "miscible residual oil" by increasing the velocity of the trailing evaporation fronts.

Carbonated Water Injection for Recovery of Oil and Wettability Analysis

2014 ◽  
Vol 695 ◽  
pp. 499-502 ◽  
Author(s):  
Mohamad Faizul Mat Ali ◽  
Radzuan Junin ◽  
Nor Hidayah Md Aziz ◽  
Adibah Salleh
Keyword(s):  
Oil Recovery ◽  
Oil And Gas ◽  
Promising Result ◽  
Water Injection ◽  
High Mobility ◽  
Wettability Alteration ◽  
Sweep Efficiency ◽  
Gas Flooding ◽  
Carbonated Water Injection ◽  
Carbonated Water

Malaysia oilfield especially in Malay basin has currently show sign of maturity phase which involving high water-cut and also pressure declining. In recent event, Malaysia through Petroliam Nasional Berhad (PETRONAS) will be first implemented an enhanced oil recovery (EOR) project at the Tapis oilfield and is scheduled to start operations in 2014. In this project, techniques utilizing water-alternating-gas (WAG) injection which is a type of gas flooding method in EOR are expected to improve oil recovery to the field. However, application of gas flooding in EOR process has a few flaws which including poor sweep efficiency due to high mobility ratio of oil and gas that promotes an early breakthrough. Therefore, a concept of carbonated water injection (CWI) in which utilizing CO2, has ability to dissolve in water prior to injection was applied. This study is carried out to assess the suitability of CWI to be implemented in improving oil recovery in simulated sandstone reservoir. A series of displacement test to investigate the range of recovery improvement at different CO2 concentrations was carried out with different recovery mode stages. Wettability alteration properties of CWI also become one of the focuses of the study. The outcome of this study has shown a promising result in recovered residual oil by alternating the wettability characteristic of porous media becomes more water-wet.

The Experimental Analysis of the Role of Flue Gas Injection for Horizontal Well Steam Flooding

2018 ◽  
Vol 140 (10) ◽  
Author(s):  
Zhanxi Pang ◽  
Peng Qi ◽  
Fengyi Zhang ◽  
Taotao Ge ◽  
Huiqing Liu
Keyword(s):  
Oil Recovery ◽  
Heavy Oil ◽  
Flue Gas ◽  
Three Dimensional ◽  
Steam Injection ◽  
Displacement Efficiency ◽  
Oil Viscosity ◽  
Sweep Efficiency ◽  
Steam Flooding ◽  
Heavy Oil Reservoirs

Heavy oil is an important hydrocarbon resource that plays a great role in petroleum supply for the world. Co-injection of steam and flue gas can be used to develop deep heavy oil reservoirs. In this paper, a series of gas dissolution experiments were implemented to analyze the properties variation of heavy oil. Then, sand-pack flooding experiments were carried out to optimize injection temperature and injection volume of this mixture. Finally, three-dimensional (3D) flooding experiments were completed to analyze the sweep efficiency and the oil recovery factor of flue gas + steam flooding. The role in enhanced oil recovery (EOR) mechanisms was summarized according to the experimental results. The results show that the dissolution of flue gas in heavy oil can largely reduce oil viscosity and its displacement efficiency is obviously higher than conventional steam injection. Flue gas gradually gathers at the top to displace remaining oil and to decrease heat loss of the reservoir top. The ultimate recovery is 49.49% that is 7.95% higher than steam flooding.

Risk Assessment and Enhanced Oil Recovery Effect of Gravity Assisted Oxygen-Reduced Air Flooding

2021 ◽  
Author(s):  
Lijuan Huang ◽  
Zongfa Li ◽  
Shaoran Ren ◽  
Yanming Liu
Keyword(s):  
Natural Gas ◽  
Oil Recovery ◽  
Gas Injection ◽  
Oil Production ◽  
Air Injection ◽  
Oil Reservoirs ◽  
Displacement Efficiency ◽  
Risk Area ◽  
Recovery Method ◽  
High Risk Area

Abstract The technology of air injection has been widely used in the second and tertiary recovery in oilfields. However, due to the injected air and natural gas will explode, the safety of the gas injection technology has attracted much attention. Gravity assisted oxygen-reduced air flooding is a new method that eliminates explosion risks and improves oil recovery in large-dip oil reservoirs or thick oil layers. The explosion limit data of different components of natural gas under high pressure were obtained through explosion experiments, which verified the suppression effect of oxygen-reduced air on explosions. The influence of natural gas composition and concentration on explosion limits was also investigated. In addition, a rotatable displacement device was used to study the feasibility of gravity assisted oxygen-reduced air injection for improving the heavy oil reservoirs recovery. Under pressure and temperature conditions of 20MPa and 371K, the sand-filled gravity flooding experiments with different dip angles were carried out using oxygen-reduced air with an oxygen content of 8%. The results show that with the increase of the reservoir dip, the pore volume of the injected fluid at the gas channeling point, the efficient development time of gas injection, and the final displacement efficiency of gas injection development all increase through gravity stabilization caused by gravity differentiation. In the presence of a dip angle, the cumulative oil production before the gas breakthrough point exceeded 80% of the oil production during the entire production process, indicating that gravity assisted oxygen-reduced air flooding is an effective and safe improving oil recovery method. Finally, the explosion risk of each link of the air injection process is analyzed, and the high-risk area and the low-risk area are determined.

Improving CO2 storage and oil recovery by injecting alcohol-treated CO2

2020 ◽  
Vol 60 (2) ◽  
pp. 662
Author(s):  
Saira ◽  
Furqan Le-Hussain
Keyword(s):  
Oil Recovery ◽  
Co2 Sequestration ◽  
Computer Modelling ◽  
Co2 Storage ◽  
Co2 Injection ◽  
Displacement Efficiency ◽  
Sweep Efficiency ◽  
Numerical Studies ◽  
Reservoir Simulator ◽  
Enhance Oil Recovery

Oil recovery and CO2 storage related to CO2 enhance oil recovery are dependent on CO2 miscibility. In case of a depleted oil reservoir, reservoir pressure is not sufficient to achieve miscible or near-miscible condition. This extended abstract presents numerical studies to delineate the effect of alcohol-treated CO2 injection on enhancing miscibility, CO2 storage and oil recovery at immiscible and near-miscible conditions. A compositional reservoir simulator from Computer Modelling Group Ltd. was used to examine the effect of alcohol-treated CO2 on the recovery mechanism. A SPE-5 3D model was used to simulate oil recovery and CO2 storage at field scale for two sets of fluid pairs: (1) pure CO2 and decane and (2) alcohol-treated CO2 and decane. Alcohol-treated CO2 consisted of a mixture of 4 wt% of ethanol and 96 wt% of CO2. All simulations were run at constant temperature (70°C), whereas pressures were determined using a pressure-volume-temperature simulator for immiscible (1400 psi) and near-miscible (1780 psi) conditions. Simulation results reveal that alcohol-treated CO2 injection is found superior to pure CO2 injection in oil recovery (5–9%) and CO2 storage efficiency (4–6%). It shows that alcohol-treated CO2 improves CO2 sweep efficiency. However, improvement in sweep efficiency with alcohol-treated CO2 is more pronounced at higher pressures, whereas improvement in displacement efficiency is more pronounced at lower pressures. The proposed methodology has potential to enhance the feasibility of CO2 sequestration in depleted oil reservoirs and improve both displacement and sweep efficiency of CO2.

scholarly journals Differences of microscopic seepage mechanisms of water flooding and polymer flooding and prediction models of final oil recovery for conglomerate reservoir

2019 ◽  
Vol 74 ◽  
pp. 13
Author(s):  
Fengqi Tan ◽  
Changfu Xu ◽  
Yuliang Zhang ◽  
Gang Luo ◽  
Yukun Chen ◽  
...  
Keyword(s):  
Pore Structure ◽  
Polymer Solution ◽  
Oil Recovery ◽  
Particle Surface ◽  
Polymer Flooding ◽  
Water Flooding ◽  
Residual Oil ◽  
Displacement Efficiency ◽  
Oil Saturation ◽  
Oil Displacement Efficiency

The special sedimentary environments of conglomerate reservoir lead to pore structure characteristics of complex modal, and the reservoir seepage system is mainly in the “sparse reticular-non reticular” flow pattern. As a result, the study on microscopic seepage mechanism of water flooding and polymer flooding and their differences becomes the complex part and key to enhance oil recovery. In this paper, the actual core samples from conglomerate reservoir in Karamay oilfield are selected as research objects to explore microscopic seepage mechanisms of water flooding and polymer flooding for hydrophilic rock as well as lipophilic rock by applying the Computed Tomography (CT) scanning technology. After that, the final oil recovery models of conglomerate reservoir are established in two displacement methods based on the influence analysis of oil displacement efficiency. Experimental results show that the seepage mechanisms of water flooding and polymer flooding for hydrophilic rock are all mainly “crawling” displacement along the rock surface while the weak lipophilic rocks are all mainly “inrushing” displacement along pore central. Due to the different seepage mechanisms among the water flooding and the polymer flooding, the residual oil remains in hydrophilic rock after water flooding process is mainly distributed in fine throats and pore interchange. These residual oil are cut into small droplets under the influence of polymer solution with stronger shearing drag effect. Then, those small droplets pass well through narrow throats and move forward along with the polymer solution flow, which makes enhancing oil recovery to be possible. The residual oil in weak lipophilic rock after water flooding mainly distributed on the rock particle surface and formed oil film and fine pore-throat. The polymer solution with stronger shear stress makes these oil films to carry away from particle surface in two ways such as bridge connection and forming oil silk. Because of the essential attributes differences between polymer solution and injection water solution, the impact of Complex Modal Pore Structure (CMPS) on the polymer solution displacement and seepage is much smaller than on water flooding solution. Therefore, for the two types of conglomerate rocks with different wettability, the pore structure is the main controlling factor of water flooding efficiency, while reservoir properties oil saturation, and other factors have smaller influence on flooding efficiency although the polymer flooding efficiency has a good correlation with remaining oil saturation after water flooding. Based on the analysis on oil displacement efficiency factors, the parameters of water flooding index and remaining oil saturation after water flooding are used to establish respectively calculation models of oil recovery in water flooding stage and polymer flooding stage for conglomerate reservoir. These models are able to calculate the oil recovery values of this area controlled by single well control, and further to determine the oil recovery of whole reservoir in different displacement stages by leveraging interpolation simulation methods, thereby providing more accurate geological parameters for the fine design of displacement oil program.

An Improved Three-Phase Relative Permeability and Hysteresis Model for the Simulation of a Water-Alternating-Gas Injection

SPE Journal ◽  
2013 ◽  
Vol 18 (05) ◽  
pp. 841-850 ◽  
Author(s):  
H.. Shahverdi ◽  
M.. Sohrabi
Keyword(s):  
Relative Permeability ◽  
Oil Recovery ◽  
Gas Injection ◽  
Phase Flow ◽  
Relative Permeabilities ◽  
Water Alternating Gas ◽  
Three Phase ◽  
Three Phase Flow ◽  
Oil Water ◽  
Wag Injection

Summary Water-alternating-gas (WAG) injection in waterflooded reservoirs can increase oil recovery and extend the life of these reservoirs. Reliable reservoir simulations are needed to predict the performance of WAG injection before field implementation. This requires accurate sets of relative permeability (kr) and capillary pressure (Pc) functions for each fluid phase, in a three-phase-flow regime. The WAG process also involves another major complication, hysteresis, which is caused by flow reversal happening during WAG injection. Hysteresis is one of the most important phenomena manipulating the performance of WAG injection, and hence, it has to be carefully accounted for. In this study, we have benefited from the results of a series of coreflood experiments that we have been performing since 1997 as a part of the Characterization of Three-Phase Flow and WAG Injection JIP (joint industry project) at Heriot-Watt University. In particular, we focus on a WAG experiment carried out on a water-wet core to obtain three-phase relative permeability values for oil, water, and gas. The relative permeabilities exhibit significant and irreversible hysteresis for oil, water, and gas. The observed hysteresis, which is a result of the cyclic injection of water and gas during WAG injection, is not predicted by the existing hysteresis models. We present a new three-phase relative permeability model coupled with hysteresis effects for the modeling of the observed cycle-dependent relative permeabilities taking place during WAG injection. The approach has been successfully tested and verified with measured three-phase relative permeability values obtained from a WAG experiment. In line with our laboratory observations, the new model predicts the reduction of the gas relative permeability during consecutive water-and-gas-injection cycles as well as the increase in oil relative permeability happening in consecutive water-injection cycles.

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