Gas Phase Relative Permeability Research Articles

Material balance evaluation method for water-bearing gas reservoirs considering the influence of relative permeability

In this paper, we developed a material balance method based on a two-phase flow equation for evaluating the development efficiency in gas reservoirs. The calculating results show that the theoretical curves of development performance simulated by material balance fit well with early production data and can be used to evaluate the development efficiency of the field. The influence parameters of the theoretical curves were analyzed by simulating a constant production gas reservoir. The results show that the numerical differences between the initial water saturation and the water saturation at the isotonic point of the relative permeability curve greatly influence the theoretical curves. The higher the ratio of water phase relative permeability to gas phase relative permeability, the higher the water-gas ratio in the early and middle periods of well production. It is beneficial to exploit the underground fluid with a large average rock compressibility coefficient which means a strong formation elastic energy. Besides, the value of initial water saturation will also influence the loss of formation elastic energy. This study extends the applicability of material balance and avoids the cost risk of field well testing. Therefore, it has a good practical significance.

Experimental investigation of water-gas mixed seepage parameters characteristics in broken coal medium

In order to study the mixed permeability characteristics of broken coal medium, the parameter changes during water-gas permeation are analyzed and discussed in this study. It includes the law of two-phase flow state transformation, the law of permeability evolution and the principle of effective stress action. Firstly, the water-gas mixed permeation test system was designed by independent design. Then the gas and liquid two-phase permeation parameters were measured in real time by using multiple sets of sensors. The results are as follows: In one hand, the two-phase seepage process in broken coal medium, the seepage apparent Reynolds number is mainly distributed between 1230–2207. The difference of two orders of magnitude between the kinematic viscosities of the two fluids leads to an asynchronous transition process between the liquid and gas phase flow regimes. On the other hand, there is a competitive relationship between the relative permeability ratio of water and gas phases. When the proportion of gas phase relative permeability is distributed in the interval 71.7%–85.1%, the proportion of gas phase relative permeability is dominant, and it is most sensitive to the influence of the compaction deformation process of the initial pore structure. At the same time, the permeability k decreases with the increase of the effective stress σov in all three stages of the compaction deformation of the skeleton of the broken coal medium, in accordance with the relationship: σov=0.678/k+0.608. The effective stress will directly determine the pore deformation process of the structure of the broken coal medium.

Effect of pore-throat structure on gas-water seepage behaviour in a tight sandstone gas reservoir

In this study, effect of pore-throat structure on gas–water seepage behaviour in a tight gas sandstone formation has been experimentally examined. More specifically, pressure-controlled mercury injection tests were performed to measure capillary pressure and identify the characteristics of a pore-throat structure such as its connectivity and size distributions. According to the pore-throat structure together with its median throat radius, pore-throat skewness, relative sorting coefficient, and cutoff throat volume ratio, the pore-throat structure was then classified into three types, while gas permeabilities under different conditions are corrected with consideration of the slippage effect and different pore-throat structures. Subsequently, seepage characteristics, including distribution of movable fluid saturation, relative permeability, and water locking degree, were quantified using displacement experiments integrated with the nuclear magnetic resonance (NMR) technique for the three classified types of pore-throat structure, respectively. With the deteriorated pore-throat structure, the throat size distribution curves are found to shift to the left, porosity gradually decreases, and the irreducible water saturation gradually increases. Both water saturation at the isotonic point and irreducible water saturation increase, and gas phase relative permeability at the irreducible water saturation together with water relative permeability within the saturation range of simultaneous gas–water flow decreases consecutively, indicating the seepage capacity of gas and water is weakened. With the deteriorated pore-throat structure, the water locking becomes more serious and its corresponding water saturation together with the damage coefficient of gas permeability is larger, and the influence of water on gas phase flow is more significant. The pore-throat structure, especially its connectivity, is found to be the main factor dominating the movable fluid saturation and two-phase seepage characteristics in a tight sandstone gas reservoir. This study allows us to better understand how the pore-throat structure affects the gas–water seepage behaviour in a tight gas reservoir, provided that its characterization has been quantitatively conducted and the seepage patterns are identified and classified within a consistent and unified framework. These findings further provides solid fundamentals for efficient and effective exploitation of tight gas reservoirs.

Water invasion and remaining gas distribution in carbonate gas reservoirs using core displacement and NMR

Water invasion is a common phenomenon in gas reservoirs with active edge-and-bottom aquifers. Due to high reservoir heterogeneity and production parameters, carbonate gas reservoirs feature exploitation obstacles and low recovery factors. In this study, combined core displacement and nuclear magnetic resonance (NMR) experiments explored the reservoir gas–water two-phase flow and remaining microscopic gas distribution during water invasion and gas injection. Consequently, for fracture core, the water-phase relative permeability is higher and the co-seepage interval is narrower than that of three pore cores during water invasion, whereas the water-drive recovery efficiency at different invasion rates is the lowest among all cores. Gas injection is beneficial for reducing water saturation and partially restoring the gas-phase relative permeability, especially for fracture core. The remaining gas distribution and the content are related to the core properties. Compared with pore cores, the water invasion rate strongly influences the residual gas distribution in fracture core. The results enhance the understanding of the water invasion mechanism, gas injection to resume production and the remaining gas distribution, so as to improve the recovery factors of carbonate gas reservoirs.

Numerical simulation study on characterization of foamy oil behavior in heavy oil/propane system

A new non-equilibrium kinetic model is developed with non-constant reaction rate to characterize foamy oil behavior for heavy oil/propane system in pressure depletion tests and obtained desired history matching results. The effect of k values, relative permeability curves and reaction frequency factors under different pressure depletion rates are analyzed based on the simulation results. The simulation results suggest that both k values and gas phase relative permeability reduce with the increase of pressure depletion rate. The oil phase relative permeability and reaction rate for both Reaction (1) and Reaction (2) increase with the increase of pressure depletion rate. When consider a constant value of reaction frequency factor for Reaction (1) and non-constant value of reaction frequency factor for Reaction (2), good history matching results could be obtained. Better history matching results could be obtained for the intermediate pressure depletion rate case when consider non-constant reaction frequency factor of both Reaction (1) and Reaction (2). The simulation study suggests different foamy oil characterization under different pressure depletion rates. Gas bubbles pass smoothly and have low dissolve rate at low pressure drop rate. Increasing pressure drop rate, gas bubbles expand a larger size and blocked by pore throat. Gas bubbles evolve and dissolve process both influence the foamy oil and gas-oil flow at this pressure drop rate. Exceed pressure drop rate could cause gas bubbles evolve rate faster than dissolve rate and shorter production time. This work provides an innovative methodology to characterize foamy oil flow in heavy oil/propane system.

Experimental study of influence of natural surfactant soybean phospholipid on wettability of high-rank coal

Changing wettability of coal rock surface for enhanced gas recovery, surfactant is widely used in coalbed methane exploitation. Recently, soybean phospholipid as non-toxic and degradable natural surfactant has gained increasing importance. However, effect of soybean phospholipid on wettability of high-rank coal is still unclear. In this work, typical high-rank coals were selected from the Qinshui Basin to analyze this effect mechanism. Experiments including surface tension, surface contact angle, coal fines imbibition, dispersion effect as well as gas-based permeability were carried out. Moreover, water locking mechanism of fracturing fluid in microfractures of coal reservoir was analyzed in detail. Results show that surface of high-rank coal is negatively charged in solution and have weak hydrophilicity. Soybean phospholipid can significantly reduce the surface tension of gas-liquid, and increase wettability of coal surface. Thus, soybean phospholipid contributes coal fines to disperse observed from filter cake using scanning electron microscope. Additionally, many conventional surfactants e.g. SDBS, CTMAB, OP-10 as well as soybean phospholipid were experimentally compared in performance in reducing capillary pressure. Results indicate that single soybean phospholipid do not show perfect performance. Specially, the imbibition rate of single soybean phospholipid solution along the pipe filled with coal fines was lower than that of conventional anionic and cationic surfactants, but still higher than that of stilled water and non-ionic surfactant. To further improve the capability of soybean phospholipid solution, composite surfactant was prepared with soybean phospholipid and OP-10. We found that composite surfactant at the mass ratio of 1:3 has a lowest capillary pressure with low surface tension and large contact angle. Finally, effect of three typical surfactants on permeability of coal was investigated. Results show that this suggested compound surfactant may be conducive to discharge of fracturing fluid from coal reservoir microfractures as well as improve gas-phase relative permeability in coal engineering practice.

Gas-water relative permeability model for tight sandstone gas reservoirs

The pores in tight sandstone gas reservoir are mostly in microscale, and the gas water two-phase flow behavior through those pores is considerably complicated, thus, how to establish a reliable relative permeability model is the urgent problem to be solved. Based on the single fluid continuity equation of the microtube, second-order slip model and the fractal scaling theory, the gas-water relative permeability model of tight sandstone gas reservoir is established. The model considers the gas slippage effect, the pore throat structure and the water saturation distribution. The reliability is validated by a variety of published experimental data of gas-water relative permeability. The results show that: 1) The established model can be reasonably adopted to describe the fluid flow behavior in the tight sandstone reservoir with microscale pores. 2) The increase of pressure and water saturation will reduce the effect of slippage effect on the relative permeability of gas phase. When the pressure is less than 1 MPa, the gas relative permeability is extremely sensitive to the pressure. The impact of temperature on the gas relative permeability is limited and can be neglected. 3) A higher fractal dimension of pore size distribution is beneficial to the relative permeability of gas phase, but it has a negative impact of the relative permeability of water phase. Similarly, a higher fractal dimension of tortuosity results in a higher gas phase relative permeability but a little lower water relative permeability.

Numerical Simulation of Multiphase Flow in Nanoporous Organic Matter With Application to Coal and Gas Shale Systems

AbstractFluid flow in nanoscale organic pores is known to be affected by fluid transport mechanisms and properties within confined pore space. The flow of gas and water shows notably different characteristics compared with conventional continuum modeling approach. A pore network flow model is developed and implemented in this work. A 3‐D organic pore network model is constructed from 3‐D image that is reconstructed from 2‐D shale SEM image of organic‐rich sample. The 3‐D pore network model is assumed to be gas‐wet and to contain initially gas‐filled pores only, and the flow model is concerned with drainage process. Gas flow considers a full range of gas transport mechanisms, including viscous flow, Knudsen diffusion, surface diffusion, ad/desorption, and gas PVT and viscosity using a modified van der Waals' EoS and a correlation for natural gas, respectively. The influences of slip length, contact angle, and gas adsorption layer on water flow are considered. Surface tension considers the pore size and temperature effects. Invasion percolation is applied to calculate gas‐water relative permeability. The results indicate that the influences of pore pressure and temperature on water phase relative permeabilities are negligible while gas phase relative permeabilities are relatively larger in higher temperatures and lower pore pressures. Gas phase relative permeability increases while water phase relative permeability decreases with the shrinkage of pore size. This can be attributed to the fact that gas adsorption layer decreases the effective flow area of the water phase and surface diffusion capacity for adsorbed gas is enhanced in small pore size.

An Analytical Equation to Predict Oil-Gas-Water Three-Phase Relative Permeability Curves in Fractures

As fractures are the major flow channels for multiphase flow in naturally and hydraulically fractured reservoirs, the accurate prediction of multiphase flow in fractures is highly important. The oil-gas-water three-phase relative permeability relations in fractures define the hydrodynamics of multiphase fluids flow and are necessary for modeling of multi-phase flow in fractured reservoirs. In this work, a novel flow model based on the concept of shell momentum balance, Newton's law of viscosity, and the cubic law, is derived to determine analytic functions for the three-phase relative permeability curves versus phase saturation and viscosity in a single fracture. The results show that the equations describing three-phase relative permeability curves in a fracture are function of saturations and viscosities. Water phase relative permeability depends on water saturation, gas phase relative permeability depends on gas saturation when µg is much lower than µo and µw. However, oil phase relative permeability is function of all-phase saturations. The isoperms of water phase and gas phase are straight lines. However, oil phase isoperms are functions of all phase saturations and have significant curvature. The curvatures of oil phase isoperms increase with the increase of µo. Gas saturation decreases oil phase relative permeability with a given oil saturation, while the viscosity ratio increases it.

Gas-Water Two Phase Flow Simulation Based on Pore Network Model for Reservoir Rocks

The relative permeability and capillary pressure are essential to investigate fluid flow in porous media, in terms of studying seepage characteristics of gas -water for CO2 emission reduction through deep saline sequestration. In this paper, we presented gas -water phase flow numerical simulation based on pore network extractions of four rock samples. The influence of temperature, pressure and pore structure on relative permeability and capillary pressure were carefully investigated. Analysis of evaluated results demonstrated that pore structure has significant impact on relative permeability and capillary pressure both for gas/water drainage and imbibition cycles. However, the influence of temperature and pressure on relative permeability and capillary pressure for drainage cycle is neglect-able, while during the imbibition cycle, the gas phase relative permeability is decreasing with increasing pressure and temperature, while capillary pressure and wetting phase relative permeability are decreasing with increasing pressure and increasing with increasing temperature. That might cause by change of rock wetting behavior and interactions between fluid-gas-rock as temperature, pressure change which has more impact on gas flooding process than water flooding. After comparing numerical simulation results of drainage cycle based on Berea sandstone sample to the literature, it is seemed that numerical simulation based on pore network extractions is more efficient and economical method of studying seepage characteristics of gas -water at CO2 reservoir storage conditions.

An analytical model for relative permeability in water-wet nanoporous media

A relative permeability model for gas-water two phase flow in water-wet nanoporous media is proposed based on the continuity equation with modified non-slip boundary in a single nanotube and the pore size distribution (PSD) of the media. The present model takes into account the nanoscale effects including gas slippage in the entire Knudsen range, multilayer sticking (near-wall structural water film) and the quantified thickness of water film. The flow model in single nanotube and relative permeability model in nanoporous media have been validated by comparing with the various molecular simulations, experimental data, and analytical models. The results show the nanoscale effects play an extremely significant role in determining both the gas and water phase relative permeability in nanoporous media: the gas phase relative permeability increases dramatically due to the gas slippage effect, especially at low water saturation; the multilayer sticking of the water film will reduce the water phase relative permeability as well as slightly decrease gas phase relative permeability; the flow of water film has a negative impact on both the gas and water phase relative permeability. Additionally, logarithmic normal distribution function is adopted to characterize PSD, and the sensitivity analysis of PSD on the relative permeability are examined as well.

Analyzing Permeability of the Irregular Porous Media Containing Methane Hydrate using Pore Network Model Combined with CT

Gas hydrate as the 21st century new energy is viewed as prospective energy with clean, smaller pollution, and large storage characteristics. The permeability is a key parameter for gas hydrate production. In this work, pore network models combined with X-ray computed tomography (CT) were proposed to analyze the properties of gas hydrate in porous media. We studied the permeability in porous media, used the different shapes of sand including quartz, dolomite and feldspar. Experimental results show that in these three kinds of sand, the absolute permeability of quartz is the largest, feldspar is minimal. Under the same water saturation, capillary pressure of dolomite is less than quartz; water-phase relative permeability in porous media did not obvious change, while gas phase relative permeability is a big difference. Gas phase relative permeability of dolomite is smaller than the other two kinds of sand with low water saturation. However, under the high water saturation, gas phase relative permeability of dolomite is greater than the other two kinds of sand.

Effect of pore structure on the seepage characteristics of tight sandstone reservoirs: A case study of Upper Jurassic Penglaizhen Fm reservoirs in the western Sichuan Basin

Tight sandstone reservoirs are characterized by complex pore structures and strong heterogeneity, and their seepage characteristics are much different from those of conventional sandstone reservoirs. In this paper, the tight sandstone reservoirs of Upper Jurassic Penglaizhen Fm in western Sichuan Basin were analyzed in terms of their pore structures by using the data about physical property, mercury injection and nuclear magnetic resonance (NMR) tests. Then, the seepage characteristics and the gas–water two-phase migration mechanisms and distribution of tight sandstone reservoirs with different types of pore structures in the process of hydrocarbon accumulation and development were simulated by combining the relative permeability experiment with the visual microscopic displacement model. It is shown that crotch-like viscous fingering occurs in the process of gas front advancing in reservoirs with different pore structures. The better the pore structure is, the lower the irreducible water saturation is; the higher the gas-phase relative permeability of irreducible water is, the more easily the gas reservoir can be developed. At the late stage of development, the residual gas is sealed in reservoirs in the forms of bypass, cutoff and dead end. In various reservoirs, the interference between gas and water is stronger, so gas and water tends to be produced simultaneously. The sealed gas may reduce the production rate of gas wells significantly, and the existence of water phase may reduce the gas permeability greatly; consequently, the water-bearing low-permeability tight sandstone gas reservoirs reveal serious water production, highly-difficult development and low-recovery percentage at the late stage, which have adverse impacts on the effective production and development of gas wells.

Impact of PTFE content and distribution on liquid–gas flow in PEMFC carbon paper gas distribution layer: 3D lattice Boltzmann simulations

A 3D multiphase lattice Boltzmann model (LBM) was established and employed to study the impact of polytetrafluoroethylene (PTFE) content and distribution on the liquid–gas transport in proton exchange membrane fuel cell (PEMFC) carbon-paper gas distribution layer (GDL). In the computer-generated carbon paper GDL, part of the fibers’ surface was randomly specified as PTFE to achieve a desired PTFE content and distribution. For non-uniform PTFE distribution cases, a GDL sub-region neighboring to gas channel (GC) was set to have higher PTFE content. PTFE content and distribution show important influence on the liquid–gas flow and on the relationship of relative permeability versus phase saturation. The GDL sub-region of more PTFE acts like a capillary barrier and raises the liquid saturation level in the rest part of GDL. The simulated liquid saturation level in GDL diminishes with the increase of PTFE content in GDL. The liquid phase relative permeability is larger in the GDL of lower PTFE content if the (overall) liquid saturation is lower than a threshold value, whereas it becomes smaller if the liquid saturation is higher than this threshold value. The liquid phase relative permeability in the GDL with non-uniform PTFE distribution is reduced when the liquid saturation in GDL is lower than a certain value, but when the liquid saturation is higher than this value, it is larger compared with that in the GDL with uniform PTFE distribution. The gas phase relative permeability in the GDL of lower PTFE content is larger than tat in the GDL of higher PTFE content and the non-uniform distribution of PTFE in GDL slightly reduces the gas phase relative permeability value.

Analysis of the effect of particle size on permeability in hydrate-bearing porous media using pore network models combined with CT

Because of the clean burning and minimal pollution generation of natural gas hydrates, they are viewed as premium fuel energy. The gas and water flow is highly dependent on the seepage properties of the hydrate sediments; therefore, the permeability is a key parameter for estimating the gas production of hydrate reservoirs. Pore network models combined with X-ray computed tomography (CT) were proposed to analyze the index properties and percolation characteristics of porous media containing hydrates in our previous study. This study extends our previous investigation into the influences of particle size and porosity on permeability. The results suggest the porosities of hydrate-bearing porous media formed by different-size particles, as calculated by both the pore network models and the volumetric method, are in agreement. Moreover, the hydrate-bearing porous media formed by larger-size particles has larger porosity, smaller capillary pressure, and larger absolute permeability. In addition, under the same degree of water saturation, larger porosity induced a larger water-phase relative permeability, but a smaller gas-phase relative permeability.

Improved models to predict gas–water relative permeability in fractures and porous media

Fractures and pores are major flow channels of fluid in low permeability and unconventional reservoirs. So, it is very important to accurately predict multiphase flow in fractures and porous media.In this paper, the empirical, semi-empirical, and theoretical relative permeability models in fractures and porous media are investigated. Among these models, four models have been usually suggested to represent two-phase flow behavior: X-model, Corey or Brooks–Corey model, viscous-coupling model and Chima's model. However, these models have not considered some factors that affect relative permeability significantly. For example, X-model doesn't reflect nonlinear characteristic, Corey or Brooks–Corey model neglects gas–liquid interaction, and viscous-coupling model and Chima's model don't consider irreducible phase.According to Chima's method, when the surface geometry of fracture is assumed to be two ideal parallel planes and that of fracture or pore is assumed to be a pipe, new analytical relative permeability models of fractures and porous media considering irreducible water have been proposed respectively, based on cubic law for flow in rectangular fractures, Poiseuille law for flow in pores; and the momentum balance and Newton's law of viscosity both in fractures and pores. Furthermore, we also improved these relative permeability models by considering the influence of tortuosity based on Brooks–Corey model. The results show that the relative permeability models are nonlinear functions of mobile water, viscosity, irreducible water and the fracture or pore-size distribution index. The gas and water relative permeabilities are different in fractures and pores, and the gas phase relative permeability is more sensitive to the surface geometry of flow channels. And compared with model of fractures, the gas phase relative permeability deviates by more than 50% while the water phase relative permeability deviates by less than 20% in pores. What's more, the deviation will become smaller with the increase of irreducible water saturation.The proposed model with irreducible water saturation of fractures is validated with experimental data from literature and good agreements between experimental data and those evaluated by the proposed model. And the model of porous media is validated by Brooks–Corey model and there is consistency in the forecasting result of two models when there is no irreducible water. The relative permeability models proposed in this work will be useful to professionals involved in modeling well performance, and gas production forecasting in low permeability and unconventional reservoirs.

Gas–oil relative permeability at near miscible conditions: An experimental and modeling approach

Reliable relative permeability curves of oil–gas systems are important for successful simulation and modeling of gas injection, especially when the miscibility condition approaches. In this work, the relative permeability of a CO2-light oil system has been measured under different conditions, using the Civan and Donaldson (1989) [13] method. Dolomite and sandstone core samples were used in the experiments. The minimum miscibility pressure was calculated using an empirical correlation, as well as slim-tube simulation. Due to some controversial assumptions of the Civan and Donaldson method, such as immiscible and incompressible displacement, history matching was used for predicting the reliable relative permeability of each phase at near miscible conditions. The Civan and Donaldson method was used to predict the relative permeabilities as the initial guesses for the history matching. We found that the Civan and Donaldson method underestimates oil relative permeability. Moreover, the effect of near miscibility on the gas phase relative permeability curve was stronger and the intersection point of the oil and gas phase relative permeability curves occurred at lower gas phase saturations. The results are helpful for understanding near miscible relative permeability behavior and provide knowledge on fluid flow at low IFT conditions during gas injection projects.

Geologic modeling and fluid-flow simulation of acid gas disposal in western Wyoming

The Moxa arch anticline is a regional-scale northwest-trending uplift in western Wyoming where geologic storage of acid gas (carbon dioxide, methane, nitrogen, hydrogen sulfide, ethane) is under consideration. Nugget Sandstone, a deep saline aquifer at depths exceeding 17,000 ft (5180 m), is a candidate formation. This study builds three-dimensional local- to regional-scale geologic and fluid-flow models for the Nugget Sandstone and its neighboring formations. Geologic and engineering characterization data were assembled and screened for accuracy. Using geostatistical simulations (first, sequential indicator simulation of facies, then the sequential Gaussian simulation of porosity []), the data were integrated to create a regional-scale geologic model from which a local-scale simulation model surrounding the proposed injection si te was extracted. Using this model, acid gas injection was simulated for 50 yr, followed by 1950 yr of monitoring. A sensitivity analysis was conducted, exploring the impact of geologic and engineering variables on model predictions. Results suggest that, at the simulation time scale, low dissolved solids in formation water, large gas-phase relative permeability (krg) hysteresis, and low vertical-to-horizontal intrinsic permeability (k) anisotropy all contribute to enhanced storage of acid gas in both residual (trapped) and dissolved forms. The parameter that exerts the largest control on gas storage is relative permeability hysteresis. However, given parameter uncertainty, the total predicted gas storage varies significantly. Prediction uncertainty increases in the order of dissolved gas, trapped gas, and mobile gas. In comparison, petrophysical uncertainty, as represented by multiple realizations, has limited impact on prediction, although future work is needed to expand the uncertainty analysis by developing alternative facies models for the storage formations.

Correlations for predicting single phase and two-phase flow pressure drop in pebble bed flow channels

An experimental study was conducted on the pressure drop of the single phase and the air–water two-phase flow in the bed of rectangular cross sections densely filled with uniform spheres. Three kinds of glass spheres with different equivalent diameters (3 mm, 6 mm, and 8 mm) were used for the establishment of the test sections. The Reynolds number in the experiment ranged from a dozen to thousands for the single-phase flow and from hundreds to tens of thousands for the two-phase flow. In the present flow-regime model, the bed was subdivided into a near-wall region and a central region in order to take the wall effect into account to improve the prediction at low tube-to-particle diameter ratios. Improved correlations are obtained based on the previous study to consider the single-phase flow pressure drops for finite pebble beds with spherical particles and nonspherical particles by fitting the coefficients of that equation to both the database and the present experiment. The correlation is consistent with the observed physical behavior which explains its comparatively good agreement with the experimental data. A new empirical correlation for the prediction of two-phase flow pressure drops was proposed based on the gas phase relative permeability as a function of the gas phase saturation and the void fraction. The correlation fit well for both experimental data of spherical particles and nonspherical particles.

Investigation of Cyclic Solvent Injection Process for Heavy Oil Recovery

Summary This paper summarizes numerical and experimental simulation results of a cyclic solvent injection process study, which was part of a continuing investigation into the use of solvents as a follow-up process in Cold Lake and Lloydminster reservoirs that have been pressure-depleted by cold heavy oil production with sand (CHOPS). Typically only 5% - 10% of the original oil in place (OOIP) is recovered during cold production; therefore, an effective follow-up process is required. The cyclic solvent injection (CSI) experiment consisted of primary production followed by six solvent (28% C3H8 - 72% CO2) injection cycles. Oil recovery after primary production and six solvent cycles was 50%, which indicates the potential viability of the CSI process. Concurrently with the laboratory physical simulation, a numerical simulation model was developed to represent the physical behaviour of the experimental results. A history match of the primary production portion of the experiment was obtained using an Alberta Innovates - Technology Futures (AITF) foamy oil model. This resulted in the characterization (fluid saturations and pressures) of the oil sandpack at the start of the solvent injection process. The history match of the subsequent six solvent injection cycles was used to validate the numerical model of the CSI process developed at AITF. This model includes nonequilibrium rate equations that simulated the delay in solvent reaching its equilibrium concentration as it dissolves or exsolves in the oil in response to changes in the pressure and/or gas-phase composition. Dissolution of CH4, C3H8 and CO2 in oil and CO2 in water were considered, as was exsolution of CH4, C3H8 and CO2 from oil and CO2 from water. Reduced gas-phase permeabilities resulting from gas exsolution were also included. The history match simulations indicated that: The important mechanisms were represented in the simulations. Significant oil swelling by solvent dissolution occurs during solvent injection periods. This can reduce solvent injectivity and penetration into a heavy oil reservoir during solvent injection periods. Low oil and gas-phase relative permeabilities are required during production periods to match the experimental oil and gas production during solvent cycles. A parametric simulation study showed that the quantity of gas injected in an injection period was relatively insensitive to the oil-phase diffusion coefficients, but was sensitive to solvent solubility in oil, dissolution rates, gas-phase diffusion coefficients, molar densities in the oil phase, gas-phase relative permeability and capillary pressure. It was shown that oil production is highly dependent on how quickly solvent can dissolve in the oil during injection and exsolve from the oil during production.