Gas-oil Interfacial Tension Research Articles

Calculation of IFT in porous media in the presence of different gas and normal alkanes using the modified EoS

Gas injection can increase oil recovery because the gas–oil interfacial tension is less than the water–oil interfacial tension (IFT) and tends to zero in the miscibility state. However, little information has been provided on the gas–oil movement and penetration mechanisms in the fracture system at the porosity scale. The IFT of oil and gas in the porous medium changes and can control oil recovery. In this study, the IFT and the minimum miscibility pressure (MMP) are calculated using the cubic Peng-Robinson equation of state that has been modified using the mean pore radius and capillary pressure. The calculated IFT and MMP change with the pore radius and capillary pressure. To investigate the effect of a porous medium on the IFT during the injection of CH4, CO2, and N2 in the presence of n-alkanes and for validation, measured experimental values in references have been used. According to the results of this paper, changes in IFT vary in terms of pressure in the presence of different gases and, the proposed model has good accuracy for measuring the IFT and the MMP during the injection of hydrocarbon gases and CO2. In addition, as the average radius of the pores gets smaller, the interfacial tension tends to lower values. This effect is different with increasing the mean size of interstice in two different intervals. In the first interval, i.e. the Rp from 10 to 5000 nm, the IFT changes from 3 to 10.78 mN/m and in the second interval, i.e. the Rp from 5000 nm to infinity, the IFT changes from 10.78 to 10.85 mN/m. In other words, increasing the diameter of the porous medium to a certain threshold (i.e. 5000 nm) increases the IFT. As a rule, changes in IFT affected by exposure to a porous medium affect the values of the MMP. In general, IFT decreases in very fine porous media, causing miscibility at lower pressures.

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.

Improvement to Gravity Drainage Recovery by Repressurization as a Criterion to Screen and Rank Naturally Fractured Reservoirs for Gas Injection

Summary Many of the naturally fractured carbonate reservoirs of the Middle East exhibit low natural-depletion recoveries. The reason is that most of their oil reserves are stored in the low-permeability host rocks and are left behind by the fast advancing gas/oil contact (GOC) and water/oil contact (WOC) in fractures. Producing the remaining oil in the large gas-invaded zone of these reservoirs has been a crucial reservoir management issue. We show in this study using experimental observations, analytical calculations, and numerical investigations that repressurizing naturally fractured reservoirs (NFRs) by crestal immiscible gas injection has the potential to produce a large portion of this remaining oil by improving gravity drainage (GD) through two main mechanisms. One is that at higher pressures, the gas-oil interfacial tension (IFT) and hence the capillary forces that control recovery by GD are lessened, allowing additional recovery. This mechanism is aided by the other one, which is swelling of the oil at higher pressures. In this way, repressurization is thought to be not only a means for pressure maintenance but also a methodology for enhanced-oil recovery (EOR). This is confirmed by both laboratory studies and field performance of large-scale gas injection projects. Despite the desire for implementation of projects of repressurization, gas availability and cost of these projects are important concerns, requiring a cost-benefit analysis. Screening and ranking methodologies have been previously presented for some EOR techniques but not for repressurization by gas in NFRs. Evaluating the performance of gas injection in NFRs is often done using methodologies such as numerical simulations, which are in-depth, costly, and tedious. The methodology developed here is simple, requiring spreadsheet calculations. To develop the methodology, we first obtain simple relations to calculate additional GD recovery by considering the interplay of capillary and gravity forces in a matrix block subjected to pressurization by equilibrium gas injection and then use experimental data from literature to show that these relations can predict primary and secondary GD recoveries to a good approximation. We also show by mechanistic studies using a history-matched numerical model that IFT reduction and oil swelling are the main mechanisms contributing to additional oil recovery. Then, we propose a methodology to screen and rank candidate NFRs for gas injection that uses commonly available reservoir data and is based upon two criteria, these being additional oil recovered from a matrix block by pressurization and required volume of gas to produce an additional barrel of oil. We then implement this methodology to more than 20 Iranian NFRs and identify six reservoirs with potential for additional recovery of more than 20%. By quantifying and including the uncertainties associated with the reservoir data, we illustrate that for the reservoirs under study, capillary pressure parameters along with matrix-block height are the main parameters affecting GD recovery and should be characterized more accurately.

Pore-Scale Imaging and Analysis of Wettability Order, Trapping and Displacement in Three-Phase Flow in Porous Media with Various Wettabilities

Three-phase flow in porous media is encountered in many applications including subsurface carbon dioxide storage, enhanced oil recovery, groundwater remediation and the design of microfluidic devices. However, the pore-scale physics that controls three-phase flow under capillary dominated conditions is still not fully understood. Recent advances in three-dimensional pore-scale imaging have provided new insights into three-phase flow. Based on these findings, this paper describes the key pore-scale processes that control flow and trapping in a three-phase system, namely wettability order, spreading and wetting layers, and double/multiple displacement events. We show that in a porous medium containing water, oil and gas, the behaviour is controlled by wettability, which can either be water-wet, weakly oil-wet or strongly oil-wet, and by gas–oil miscibility. We provide evidence that, for the same wettability state, the three-phase pore-scale events are different under near-miscible conditions—where the gas–oil interfacial tension is ≤ 1 mN/m—compared to immiscible conditions. In a water-wet system, at immiscible conditions, water is the most-wetting phase residing in the corners of the pore space, gas is the most non-wetting phase occupying the centres, while oil is the intermediate-wet phase spreading in layers sandwiched between water and gas. This fluid configuration allows for double capillary trapping, which can result in more gas trapping than for two-phase flow. At near-miscible conditions, oil and gas appear to become neutrally wetting to each other, preventing oil from spreading in layers; instead, gas and oil compete to occupy the centre of the larger pores, while water remains connected in wetting layers in the corners. This allows for the rapid production of oil since it is no longer confined to movement in thin layers. In a weakly oil-wet system, at immiscible conditions, the wettability order is oil–water–gas, from most to least wetting, promoting capillary trapping of gas in the pore centres by oil and water during water-alternating-gas injection. This wettability order is altered under near-miscible conditions as gas becomes the intermediate-wet phase, spreading in layers between water in the centres and oil in the corners. This fluid configuration allows for a high oil recovery factor while restricting gas flow in the reservoir. Moreover, we show evidence of the predicted, but hitherto not reported, wettability order in strongly oil-wet systems at immiscible conditions, oil–gas–water, from most to least wetting. At these conditions, gas progresses through the pore space in disconnected clusters by double and multiple displacements; therefore, the injection of large amounts of water to disconnect the gas phase is unnecessary. We place the analysis in a practical context by discussing implications for carbon dioxide storage combined with enhanced oil recovery before suggesting topics for future work.

Modeling Near-Miscible Gas Foam Injection in Fractured Tight Rocks and Its Challenges

Unlocking oil from tight reservoirs remains a challenging task, as the existence of fractures and oil-wet rock surfaces tends to make the recovery uneconomic. Injecting a gas in the form of a foam is considered a feasible technique in such reservoirs for providing conformance control and reducing gas-oil interfacial tension (IFT) that allows the injected fluids to enter the rock matrix. This paper presents a modeling strategy that aims to understand the behavior of near-miscible foam injection and to find the optimal strategy to oil recovery depending on the reservoir pressure and gas availability. Corefloods with foam injection following gas injection into a fractured rock were simulated and history matched using a compositional commercial simulator. The simulation results agreed with the experimental data with respect to both oil recovery and pressure gradient during both injection schedules. Additional simulations were carried out by increasing the foam strength and changing the injected gas composition. It was found that increasing foam strength or the proportion of ethane could boost oil production rate significantly. When injected gas gets miscible or near miscible, the foam model would face serious challenges, as gas and oil phases could not be distinguished by the simulator, while they have essentially different effects on the presence and strength of foam in terms of modeling. We provide in-depth thoughts and discussions on potential ways to improve current foam models to account for miscible and near-miscible conditions.

Pore-Scale Study of Oil Recovery by Gas and Foam in a Fractured Carbonate Rock at Different Gas–Oil Interfacial Tension

This work studies oil displacement by gas and foam in a fractured low-permeability oil-wet carbonate rock. In the three experiments conducted, gas is a methane–ethane mixture whose ethane mole frac...

Experimental and simulation investigations of carbon storage associated with CO2 EOR in low-permeability reservoir

CO2 based water-alternating-gas (WAG) injection and surfactant-alternating-gas (SAG) injection have shown to be two effective and practical methods to enhance oil recovery, which, also achieves carbon sequestration as well. In this study, a combination of experiment and numerical simulation was used to evaluate the performances of WAG and SAG flooding in low-permeability reservoir. Core drainage experiments were conducted, and NMR equipment was used to reveal the microscopic fluid distribution and explain the macroscale drainage results for each of the enhancing oil recovery (EOR) technique. In addition, the two EOR techniques were further evaluated in a realistic low-permeability reservoir, Yushulin oil field from Songliao Basin, China. The results show that, gas phase can lower gas-oil interfacial tension (IFT) in WAG process which contributes the oil displacement from smaller pores. Besides that, the surfactant in SAG process can also improve the oil displacement efficiency in larger pores due to the generation of foams. The optimal WAG and SAG ratios (1.25–1.5) in the realistic reservoir are all higher than the typical ratio (equal to 1) from the core experimental results and that in the most conventional oilfields due to the higher heterogeneity in low-permeability reservoir with easier gas breakthrough. Furthermore, the CO2 utilization efficiency for SAG is higher than WAG.

Pore-scale mechanisms of immiscible and miscible gas injection in fractured carbonates

Oil recovery in fractured carbonates is low because of fracture-matrix permeability contrast, oil/mixed-wettability, and high capillary entry pressure. Gas injection can enhance oil recovery because gas-oil interfacial tension is less than water-oil interfacial tension and diminishes to zero towards miscibility. Nevertheless, pore-scale mechanisms of gas-oil displacement and diffusion within fractured systems are still poorly understood. We created a fractured system using a 1.1-cm long and 0.5-cm diameter Texas cream limestone core (matrix) immersed in sandpack (fracture). Immiscible (methane) and miscible (ethane) gas injections were conducted and monitored with X-ray computed microtomography at 10 µm resolution for oil saturation/concentration evolution. During immiscible displacements, matrix oil saturation change was cyclic instead of monotonic due to oil imbibition and vugs (10–300 µm) remained 100% oil saturated when the ultimate oil recovery was 10% in matrix and 78% in fracture. During miscible displacements, oil concentration monotonically decreased and vugs became 100% gas-filled at 50% overall matrix oil concentration. The ultimate oil recovery was 69% in matrix and 100% in fracture. The effective ethane diffusivity in fracture and matrix were estimated to be 5.07 × 10−5 and 1.70 × 10−6 cm2/s, respectively. Oil in vugs can be recovered only after invading intergranular pores (1–6 µm) connecting vugs. Fracture permeability determines the maximum pressure in the gas phase which must overcome the matrix capillary pressure to invade the matrix under immiscible conditions. Finally, spatial heterogeneity of effective diffusivity can exist in carbonates and create gravitationally-unstable oil concentration profiles both in lab and field scales under miscible conditions.

Effects of temperature, pressure and fluid composition on hydrocarbon gas - oil interfacial tension (IFT): An experimental study using ADSA image analysis of pendant drop test method

An attempt was done to construct a reliable framework for measurement of hydrocarbon gas-oil interfacial tension (IFT) for live crude oil systems at reservoir conditions. We utilized a state-of-the-art experimental apparatus and robust experimental procedure to measure precisely gas/oil IFT using pendant drop technique and analyze the images based on Axisymmetric Drop Shape Analysis method. Initially, all phases were brought into equilibrium at experimental conditions and the density of each phase was measured. To measure IFT for each pair of fluids, an IFT cell was almost filled with the gas phase, and the live crude oil was then injected to create a pendant drop. The image was captured, using a microscope attached to a digital camera, and analyzed with Drop Analysis System software to determine the interfacial tensions. The densitometer and the IFT measurement apparatuses were all calibrated using reference fluids.We tried to spotlight the effects of pressure, temperature and composition on interfacial tensions. The findings show that effects of pressure are more profound on IFT rather than temperature. As pressure increases, particularly at low pressure conditions, the gas-oil interfacial tension declines with a descending trend. This behavior continues even at higher pressure with smaller rates. Increases in temperature increase the interfacial tensions as well. The effects of pressure and temperature are linked to the changes in density contrast, mutual gas-oil solubility, and miscibility development. The IFT variation can also be affected by the oil composition and therefore the trends and/or IFT values might change from one fluid system to another. The effects of composition are found to have significant effects on IFT, which depend on the phase envelope of the sample.

Development of robust model to estimate gas–oil interfacial tension using least square support vector machine: Experimental and modeling study

The measuring of physical properties in laboratory is very important issue in petroleum industry. Secondary and tertiary oil recovery, gas condensate recovery, especially by gas injection, near-critical fluids recovery and wettability alteration surface tensions are very important to measure. One objective of this study is to perform a precise measuring procedure employing the pendant drop technique. Iranian oil reservoir samples as denser phase and its immiscible injecting gas are used at reservoir condition. While experimental measurements are often expensive and time-consuming, models are commonly used. Moreover, this study presents the potential of the least squares support vector machines (LSSVM) modeling approach to predict the gas–oil interfacial tension. To develop the model, a total of 75 data generated from our experiments covering a wide temperature range of 100 through 200F and a wide pressure range of 14.7 through 5000psi are used. Genetic algorithm (GA) as population based stochastic search algorithm was used to gain the optimal LSSVM models parameters respectively. The results revealed that the GA-LSSVM are capable of capturing the complicated nonlinear relationship between the input and output variables. For the purpose of predicting gas–oil interfacial tension, the GA-LSSVM models yielded the mean absolute error (MAE) and coefficient of determination (R2) values of 1.6028 and 0.9988, respectively for the whole data set.

Determination of Gas-oil Interfacial Tension

Reliable knowledge of minimum miscibility pressure plays a vital parameter in the design and implementation of any miscible gas injection process and gas-oil interfacial tension extremely impacts on minimum miscibility pressure values. In this article two Iranian oil fields were investigated. Gas-oil interfacial tension technique relies on the measurements of gas/oil interfacial tension by pendant drop at several pressures and reservoir temperature for the first field and results were compared with generated values by the Parachor method. Then at different pressures and constant temperature (115°F) condition in the second field interfacial tension values have been evaluated for different oil-gas molar ratios.

DEVELOPING A COMPOSITIONAL RESERVOIR MODEL FOR INVESTIGATING THE EFFECT OF INTERFACIAL TENSION ON OIL RECOVERY

In this paper, a simplified formulation for compositional reservoir simulator is presented. These types of simulators are used when inter-phase mass transfer depends on phase composition as well as pressure. The procedure for solving compositional model equations is completely described. For equilibrium calculation, property estimation Peng Robinson equation of state is used. This equation was tuned using some data from swelling test and saturation pressure data. It is another purpose of this work, to show how the gas oil interfacial tension impresses the predictions of developed compositional model. Application of the simulator to simulate the results of oil recovery from displacement tests is presented. A good agreement was achieved between the experimental data and model predictions.

Application of the new vanishing interfacial tension technique to evaluate miscibility conditions for the Terra Nova Offshore Project

Terra Nova oil pool is the second largest oil pool discovered in the Grand Banks of the Canadian East Coast and is under development. As a part of the oil recovery process selection criteria, miscibility conditions were determined for Terra Nova oil with various enrichment levels of gas available from the offshore production facilities using the recently developed vanishing interfacial tension (VIT) technique. The VIT technique is based on the concept that the interfacial tension between the gas and crude oil phases at reservoir temperature must reduce to zero as these two phases approach the point of miscibility. The concept of zero-interfacial tension at miscibility is, in turn, based on the well-accepted fact that the interface between the phases must vanish, as they become miscible with one another. Thus, the minimum miscibility pressure (MMP) and minimum miscibility composition (MMC) can be determined precisely by measuring gas–oil interfacial tension as a function of pressure and gas composition, down to as low an interfacial tension as the measurement technique allows, and then extrapolating the data to zero-interfacial tension. This paper presents the details of this new VIT technique and its evaluation against slim-tube tests, and discusses its application to the Terra Nova gas injection scheme. The interfacial tension data obtained at reservoir conditions using the computerized axisymmetric drop shape analysis (ADSA) technique are presented as a function of pressure, gas composition, and the mode of gas–oil contact (first-contact or equilibrium). In addition to providing visual evidence of miscibility as the point of zero-interfacial tension is approached, the VIT technique is rapid in that it enables the experimental determination of MMP and MMC within about 2–3 days as against 4–6 weeks required by the slim-tube technique.

Variation of gas-oil-solid contact angle with interfacial tension

Contact angle has a major influence on the distribution of multi-phase fluids within petroleum reservoir rocks. However, there is little information on the variation of gas-oil-rock contact angle with pertinent parameters in the literature. In this study, it has been observed that the contact angle is almost constant at high gas-oil interfacial tension (IFT) above a threshold value and declines at a variable rate, depending on the volatility of the mixture, approaching zero at the critical point. The generated data were used to develop a generalized correlation between the contact angle and IFT and other measurable parameters of the system.

The depressurization of water-flooded reservoirs; wettability and critical gas saturation

The influence of wettability on the formation, growth and mobilization of bubbles formed when solution gas is released from water-flood residual oil have been visually observed in a series of experiments. The experiments were performed using a mixture of low boiling point hydrocarbons, which had a positive spreading coefficient for the oil phase in contact with water and its own vapour. In an oil-wet matrix, nucleation of gas bubbles occurred on the surface of the matrix. While it was impossible to determine where nucleation occurred in the water-wet condition, the results suggest that wettability influences the gas nucleation behaviour. In a water-wet system, the oil-water interfacial tension controlled the growth pattern for the gas bubbles, but in an oil-wet system the gas-oil interfacial tension was the controlling parameter. As a result, it seems likely that wettability influences the critical saturation for mobilization of the gas phase. The behaviour of the oil phase during depressurization is influenced by wettability. In a water-wet system the physical form of the oil is changed from immobile droplets into films which may be transported with the gas phase, and in which the oil is mobile. In contrast in an oil-wet system, the oil phase can move as films when the gas is released from solution but generally will not initially move over many pores.

Oil recovery by gas displacement at low interfacial tension

The authors show that an interfacial tension-dependent relative permeability function can be used to improve simulation of oil recovery when gas-oil interfacial tension [ IFT] is low. Accurate simulation of miscible displacements under a broad range of operating conditions hinges on the proper treatment of IFT as it is related to relative permeability. Potential applications of IFT-dependent relative permeability to reservoir simulation studies include multicontact miscible and gas pressure maintenance projects and volatile oil and rich gas condensate recovery. This paper presents an empirical mixing rule for relative permeability that accounts for the change of relative permeability and residual saturation with IFT. The authors use the function in flow simulation to predict experimental gas-oil displacement data on a binary and a ternary mixture. The authors propose an extension to account for the presence of mobile water and for gas hysteresis as the wetting phase saturation increases with a flow reversal (imbibition).