Immiscible WAG Research Articles

Experimental investigation of CO2 storage and oil production of different CO2 injection methods at pore-scale and core-scale

The CO2 storage and oil production of different CO2 injection schemes via laboratory experiments was investigated in this study. Microfluidic equipment was upgraded to increase its working pressure above the miscible pressure of the CO2/oil system. Microfluidic experiments of immiscible CO2 injection, miscible CO2 injection, water injection, and water alternating CO2 (WAG) injection were conducted. Affected by buoyancy subject to gas phase, apparent gas overriding and flow stratification were observed under immiscible conditions in porous media. Miscible CO2 injection eliminated the influence of buoyancy, thereby expanding the CO2 storage area and enhancing oil production. Non-uniform miscibility was observed during miscible CO2 injection, caused by connate water, tiny pores, and differential pressure. Water flooded most areas in the porous media, but small dispersed oil such as droplet oil and film oil remained in the water-flooded pores, resulting in low oil washing efficiency. The strong Jamin effect in the water-flooded area, caused by the dispersion of the remaining oil, inhibited the gas overriding and expanded the scope of CO2 flow in WAG, thereby increasing the oil production. However, the water slug occupied a large pore volume and drove out the CO2 stored at the beginning stage, resulting in low CO2 storage. The core flooding experiments were conducted to quantitatively evaluate the CO2 storage and oil recovery of different CO2 injection methods. Miscible injection produced 20.5%, 12.2%, and 2.9% more oil than immiscible CO2 injection, water flooding, and WAG. Besides, the produced gas by miscible CO2 injection was 46.5% and 47.6% lower than that of immiscible CO2 injection and WAG, respectively.

Study of modern options for using combinations of gasflooding and traditional waterflooding (water-gas influence and its alternative)

Water-gas influence (WGI) is an oil recovery method improving displacement ratio, sweep efficiency and adjusting the alignment of displacement. This study is a review of the traditional WAG methods (Immiscible WAG, Hybrid WAG, Simultaneous WAG and Selective Simultaneous WAG), including with stabilizing surfactants, WAG. We also consider such sparsely used methods as: SSWAG, FAWAG, CWAG, TWAG, VR-WAG, Up- and Down-dip WAG, HC-WAG, PAG, SAG, WASP, LSW WAG, LSASF, SMSW-AGF and others. The advantages and disadvantages of these tools are considered. Keywords: water-gas influence (WGI); WAG; SWAG; enhanced oil recovery; APG utilization.

Simulation of Immiscible Water-Alternating-Gas Injection in a Stratified Reservoir: Performance Characterization Using a New Dimensionless Number

Summary Water alternating gas (WAG) is a well-established enhanced-oil-recovery process where gas and water are injected in alternating fashion. Good volumetric sweep is achieved as water and gas target both the oil residing in low and high portions of the reservoir, respectively. Other important features in three-phase hysteretic flow include phase trapping, which is believed to be more strongly associated with the gas phase. With these aspects in mind, a vast simulation study has been performed investigating immiscible WAG injection focusing on mechanisms such as mobility, gravity, injected volume fractions, reservoir heterogeneity, gas entrapment, and relative permeability hysteresis. The aim of our work is to investigate the interplay between these mechanisms for a model system with sufficient complexity to be of relevance and then scale recovery performance using a new dimensionless number that incorporates the relevant model input parameters. A horizontally layered reservoir is considered where oil is displaced by water and gas alternately injected toward a producer. The model is a modified black-oil type, where hysteresis in the gas phase is modeled using the Land (1968) model for trapping and the Carlson (1981) model for relative permeability hysteresis. It is seen that gravity segregation in uniform models and increased heterogeneity in no-gravity models both lead to lower oil recovery. However, in heterogeneous models, gravity can divert flow from high-permeability layers into low-permeability layers and improve recovery. Hysteresis lowers gas mobility and hence improves gas/oil mobility ratio and reduces gravity segregation. The first effect is always positive, but the second is mainly positive in more uniform reservoirs where gravity segregation has a negative effect on recovery. In heterogeneous reservoirs, reducing gravity segregation can lead to the oil in low-permeability layers remaining unswept. The newly derived characteristic dimensionless number is effectively a WAG mobility ratio, termed M*, expressing how well the injected-fluid mixture is able to displace oil, whether it is because of fluid mobilities, heterogeneity, or other effects. At a value of M* near unity, optimal recovery is achieved, whereas logarithmic increase of M* reduces recovery.

Coupling Immiscible CO2 Technology and Polymer Injection to Maximize EOR Performance for Heavy Oils

Summary With approximately 90% of Saskatchewan's original heavy oil in place remaining in the ground, there is excellent potential for the application of enhanced oil recovery (EOR) methods and new technologies. The goal of the study discussed in this paper was to investigate if a new proposed process--coupling CO2 and polymer injection--can increase EOR performance for heavy oil reservoirs. The oil recovery performance of three EOR modes [water-alternating-gas (CO2 WAG) injection, polymer-alone flood and coupled CO2 and polymer injection] was compared in laboratory-scale linear coreflood tests in waterflooded cores. The immiscible CO2 WAG process recovered 15.3% original oil in place (OOIP) with 6.16 MSCF/stb gas utilization. Under a controlled maximum pressure drop across the core, the polymer-alone (0.4 wt%) flood produced an additional 12.93% OOIP above the initial waterflood recovery. However, the coupled CO2 and polymer injection process (using a polymer concentration of only 0.2 wt%) gave better recovery efficiency (18.7% OOIP) than the polymer-alone flood. Moreover, it had much better gas utilization than the CO2 WAG run, consuming only 2.0 MSCF/stb, or one-third of the amount of CO2 used in that run to recover the same amount of oil. This performance comparison demonstrates two of the biggest advantages of coupled CO2 and polymer injection: it can effectively reduce the pressure drop across the core and can obtain encouraging recovery if the optimal polymer concentration is added to the water.

Key characteristics of three-phase oil relative permeability formulations for improved oil recovery predictions

Significant three-phase regions can occur in a range of reservoir development strategies and oil relative permeability may then critically affect ultimate oil recovery. Unfortunately, three-phase oil relative permeabilities are not generally well characterized. In this paper we focus on theoretical methods of estimating three-phase oil relative permeabilities, as typically applied in reservoir simulation. In the absence of good physical models, we propose applying a mathematical filter to the many existing methods before fitting to measured data. First, the key characteristics of methods for predicting three-phase oil relative permeabilities are discussed, including choice of variables, behaviour at low oil saturations and three-phase residual oil saturations. Second, a numerical comparison of both predicted oil relative permeabilities and predicted incremental oil recoveries for immiscible WAG over waterflood is presented. None of the four most commonly used formulations assessed passed the mathematical filter successfully. Shortcomings were found in both of Stone's commonly used formulations for estimating expected recoveries. A wide range of incremental oil recoveries for immiscible WAG was found from choosing different formulations or different three-phase residual oil saturations. Some recommendations for best practice have been made.

Effect of Nitrogen On the Solubility And Diffusivity of Carbon Dioxide Into Oil And Oil Recovery By the Immiscible WAG Process

Abstract In the immiscible displacement of oil by carbon dioxide gas, the solubility and diffusivity of carbon dioxide are important factors that determine the efficiency of the process, because an increase in the carbon dioxide solubility and diffusivity into oil leads to an increase in oil recovery. It is shown by experimental studies that the solubility and diffusivity of carbon dioxide into oil are governed by the saturation pressure, reservoir temperature, composition of the oil and purity of the gas. The solubility and diffusivity of carbon dioxide into Aberfeldy heavy oil were measured, using impure carbon dioxide gas containing nitrogen as the main contaminant gas. It was noted that increasing the concentration of nitrogen in the carbon dioxide stream decreased the solubility and diffusivity of carbon dioxide in oil, consequently leading to a reduction in the swelling of the oil by carbon dioxide. Displacement experiments were also conducted to observe the effect of using impure carbon dioxide in place of pure carbon dioxide in the immiscible displacement WAG process. It was noted that the presence of nitrogen in carbon dioxide adversely affected oil recovery by the process and that increasing the nitrogen concentration up to 30 mole% could result in 10% loss in oil recovery. Introduction The solubility of carbon dioxide is the most important effect in the immiscible displacement of oil by carbon dioxide gas since it was found by Rojas(1) that among other mechanisms, an increase in the carbon dioxide solubility in oil leads to an increase in oil recovery. This is true because the solubility of carbon dioxide greatly reduces the viscosity of the oil and promotes the swelling of the oil. Viscosity reduction and swelling of the oil lower the water-oil mobility ratio, consequently leading to an increased oil recovery. Early work in 1926 by Beecher and Parkhurst(2) showed that carbon dioxide was more soluble on a molar basis in a 30.2 °API oil than air and natural gas. Svreck and Mehrota's data(3) for carbon dioxide, methane and nitrogen showed that and Mehrotra's data(3), carbon dioxide is the most soluble and nitrogen the least soluble in bitumen. The solubility of carbon dioxide in oil is governed by the saturation pressure, reservoir temperature, composition of the oil and purity of the gas. Miller and Jones(4) and Chung, Jones, and Nguyen(5) measured the solubility of carbon dioxide in Canyon and Wilmington heavy oils and found that the solubility of carbon dioxide in heavy crude oils increased with pressure but decreased with temperature and reduced API gravity. Briggs and Puttagunta(6) reported sets of data for carbon dioxide solubility in Aberfeldy oil and swelling of oil at 20.6 °C. Their data showed that both carbon dioxide solubility and oil swelling increased when pressure increased. Later, Sayegh and Sarbar(7) established that carbon dioxide is more soluble in oil at lower temperatures than at higher ones.