Water 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.

A New Method to Calculate the Relative Permeability of Oil and Water in Tight Oil Reservoirs by Considering the Nonlinear Flow

The theoretical research on the percolation mechanism and oil-water relative permeability of low-permeability oil reservoirs is the focus and hotspot of international researchers. Oil-water relative permeability is an important parameter that describes the characteristics of oil-water two-phase flow and is widely used in the dynamic analysis of development and numerical simulation technology in the reservoir. The traditional calculation method of oil-water relative permeability (i.e., the JBN method) is based on the Darcy flow law. When the velocity and the displacement pressure gradient do not follow the linear flow law, there are some errors in the results of oil-water relative permeability calculated by the JBN method. In this paper, the traditional JBN method is improved, and we establish a new processing method of experimental data for oil-water relative permeability considering the effects of nonlinear flow, capillary pressure, and gravity in tight oil reservoirs. The experiments on the flow characteristics of single-phase oil and oil-water relative permeability under nonsteady-state conditions were carried out. The flow velocity and displacement pressure gradient show nonlinear characteristics when single-phase oil is passed through a tight core. At the same time, when the air permeability decreases from 1.92 × 10 − 3 μ m 2 to 0.1 × 10 − 3 μ m 2 , the nonlinear characteristics are becoming more and more obvious. Compared with the traditional JBN method, when the nonlinear flow characteristics are considered, the oil phase relative permeability increases, and the water phase relative permeability is slightly lower. If nonlinear flow characteristics are considered, when the water saturation increases from 0.605 to 0.699, the difference of oil phase relative permeability calculated by the JBN method and this method is gradually decreasing and, with the increase of water saturation, decreases from 0.0029 to 0.0001. In addition, the effects of capillary pressure, gravity, and the nonlinear flow coefficient on the oil-water relative permeability in tight oil reservoirs are studied. The capillary pressure also has a great influence on the relative permeability of the oil phase, and the relative permeability of the oil phase increases with the increase in capillary pressure. In the development process of the low-permeability reservoir, the seepage characteristics of each flow area are different, and the oil-water relative permeability is also different. Therefore, the research results play an important role in guiding the understanding of seepage characteristics of low permeability of tight oil reservoirs.

Experimental Study on Gas–Water Relative Permeability Characteristics of Tight Sandstone Reservoir in Ordos Basin

Accurate measurement of relative permeability curve is the basis for evaluating gas reservoir performance. The unsteady-state method could bring significant measurement error for low-permeability cores. However, it is difficult to control the constant gas flow rate in the traditional steady-state method, which obstacles the experimental operation. In this study, an improved steady-state method was proposed. First, the pressure value obtained from the experiment, when the gas permeability no longer changed with the average pressure on the rock core, was set as the testing pressure. Then, the gas was injected under constant pressure, and the water was injected with a constant flow rate. Finally, the relative permeability values of gas and water phases were calculated based on Darcy’s law. Comparative analysis of the results of the relative permeability curves under formation pressure and pressure with negligible slip effect indicates that the relative permeability curves are the same in gas and water phases, proving the feasibility of the new method. Further, the results were compared with those of the test method at normal pressure, the water-phase relative permeability showed no significant change, the relative permeability of gas phase was larger, the two-phase flow area became wider, and the irreducible water saturation was lower than that at the normal pressure. This result reflects that pressure does not significantly affect the flow of wetting phase but tremendously influences the nonwetted phase under low pressure. The relationship between relative permeability and water saturation is linear in the semilogarithmic coordinate diagram and can be described by using the following relationship: ln k rg / k rw = a S w + ln b . With the decrease in the core permeability, relative permeability curve, and isotonic point moved to the right, irreducible water saturation gradually increased, and residual gas saturation decreased, indicating that the smaller permeability induced a lower gas-phase flow capacity.

Experimental Study of the Flow Mechanism of Deep Lacustrine Carbonate Reservoirs in the Yingxi Area of the Qaidam Basin

Many of the exploration and development theories derived for conventional clastic rock reservoirs are not applicable to pore-fracture lacustrine carbonate reservoirs. The fluid flow mechanisms under reservoir conditions are still unclear. Therefore, in this study, the rock samples were characterized using X-ray diffraction (XRD), porosity-permeability analysis, scanning electron microscopy (SEM), plain thin sections, and casting thin sections. The core samples were classified into two types (fractures and matrix pores) based on their reservoir spaces. The core flow experiments were performed under reservoir conditions using reservoir core plugs. The experimental results demonstrate that the cores, especially the fractured cores, have a strong stress sensitivity. The oil phase flow in the core has the characteristics of non-Darcy flow, and the threshold pressure gradient is 0.01–0.003 MPa/m. Additionally, for the oil-water two-phase flow in the fractured core, the water phase relative permeability of the residual oil is high. In contrast, the water phase relative permeability of the matrix core is less than 0.2. The nuclear magnetic resonance (NMR) transverse relaxation time ( T 2 ) spectra were used to analyze the differences between the water flooding characteristics of the two pore structures. The experimental results show that the peaks of the T 2 spectra after water flooding are lower than those before water flooding, and the matrix cores have a better oil displacement effect. The relaxation time of 0.1–10 ms makes the greatest contribution to the water flooding efficiency. The micropores smaller than 10 μm in diameter play an important role in the water flooding of the matrix core. These results will provide theoretical basis for solving the difficult problems of developing deep lacustrine carbonate reservoirs.

Seepage Characteristics of a Low Permeability Sandstone Reservoir in Mobei Oilfield, Junggar Basin

Abstract The microscopic pore structure characteristics and the oil-water two-phase seepage law in the low permeability sandstone reservoir in Mobei oilfield in Junggar Basin were analyzed through laboratory experiments. The results of mercury pressure, constant velocity mercury pressure, thin slice of casting, and CT scan analyses showed that the reservoir had strong microheterogeneity with the presence of local large channels. The large channel had a small volume but considerably contributed to the permeability, which played a crucial role in the reservoir seepage. The relative permeability curve showed that with the increase of water saturation, the relative permeability of the oil phase decreased rapidly; the water phase relative permeability of glutenite, gravel-bearing sandstone, and coarse sandstone increased slightly; and the water cut increased rapidly. The relative permeability of the water phase of medium and fine sandstone increased, the water cut increased rapidly, and the residual oil saturation was high. In the process of core displacement, on-line CT scanning monitoring showed that before the breakthrough of the water drive front, the oil saturation decreased greatly along the way. After the breakthrough of the water drive front, the water cut increased rapidly and directly entered the ultrahigh water cut stage. Owing to the serious heterogeneity of the micropore structure, the fingering phenomenon was obvious in the process of displacement.

Pore Network Modeling of Oil–Water Flow in Jimsar Shale Oil Reservoir

The oil–water two-phase flow mechanism is the critical issue for producing shale oil reservoirs after huge-volume hydraulic fracturing treatment. Due to the extremely low permeability of the shale matrix, the two-phase experimental measurement is impossible for shale samples. In this work, a pore network model is proposed to simulate steady-state oil–water flow with mixed wettability under consideration. The model is first applied in Berea sandstone, and the calculated relative permeabilities are validated with experimental studies for different wettability scenarios. Then, the three-dimensional FIB-SEM imaging of the Jimsar shale sample is used to extract a representative shale pore network with 13,419 pores and 31,393 throats. The mean values of pores and throats are 29.75 and 19.13 nm, and the calculated absolute permeability is 0.005 mD. With our proposed model, the calculated relative permeability curves show a high residual oil saturation for all the wettability conditions. Specifically, the oil-wet and mixed-wet conditions yield lower residual oil compared with the water-wet condition. For 50–50 mixed-wet conditions, the water phase relative permeability is much higher for smaller pores being oil-wet than the larger pores being oil-wet.

Pore network modeling of thin water film and its influence on relative permeability curves in tight formations

The thin water film stabilized by disjoining pressure is non-negligible in tight formations which results in significant difference in multiphase flow behavior compared with that in conventional formations. In this work, a pore network model is proposed to simulate two phase flow in tight formations to highlight the contribution of thin water film on multiphase flow. The newly developed pore network model includes the influence of thin water film on fluid configuration, capillary entry pressure, fluid conductance and connectivity during multiphase flow in pore space. Our approach is first validated with the existing pore network model and then the influence of thin water film on two-phase flow is investigated extensively. The results show that the connate water saturation increases and its associated oil relative permeability decreases as the average pore radius decreases. It also suggests that in water-wet systems, the influence of thin water film on both oil and water phases becomes significant when the average pore radius is smaller than 100 nm. Existence of thin water film will increase the proportion of film water and corner water, resulting in an increasement in oil phase relative permeability and a slight decline of water phase relative permeability in tight porous media dominated by angular pores and throats; while in porous media dominated by circular shaped pores and throats, oil and water phase relative permeability are both enhanced due to better connectivity caused by thin water film; at the same time swelling of water film results in lower residue oil saturation and higher end point of water relative permeability. We also found higher water relative permeability when porous media has more irregular pores.

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.

Extraction and numerical simulation of gas–water flow in low permeability coal reservoirs based on a pore network model

ABSTRACT This study aimed to investigate the effects of pore structure on gas–water permeability in low permeability coal reservoirs. A 3D digital coal model with macropores (>13.85 μm) was constructed by using a μCT225kVFCB test system and Avizo image processing software. An equivalent pore network model (EPNM) was extracted on the basis of the 3D model. PoreFlow was used to simulate the micro-flow process of gas and water in the EPNM. A control variable method was used to analyze the influence of pore structure on relative permeability. Results showed a sensitive zone in the relative permeability of the non-wetting phase in the low permeability coal reservoir. In this zone, the relative permeability of the gas phase showed remarkable variations, and the changes of the pore throat ratio (PTR) were minimal. In addition, a critical throat radius (TR) was established in the low permeability coal reservoir with water saturation (S w) of less than 48.33%. Gas fluidity was poor when TR reached its critical value. The water phase relative permeability (K rw) increased with the increase of PTR. The variation of K rw was minimal as the coordination number (CN) increased. The influence of the pore throat structure on K rw was ranked as PTR>TR>CN.

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.

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.

Killing fluid loss mechanism and productivity recovery in a gas condensate reservoir considering the phase behavior change

Abstract A single well numerical model considering rock capillary pressure and hysteresis was built to study killing fluid loss mechanism and its influence on productivity recovery under different positive pressure differentials based on the gas reservoir characteristics of the gas condensate well by combining the reservoir engineering and oil and gas phase behavior theory. The results show that when reservoir pressure of near wellbore zone increases to the critical pressure of condensate oil, the three-phase (oil, gas, water) flow will change to two-phase (oil, water) flow, the gas block effect will weaken, and water-phase relative permeability will increase, which can be manifested as sharp increase of killing fluid loss rate; and the rising fluid loss into the reservoir can affect the phase of condensate oil and gas and fluid distribution in the storage space near wellbore, and consequently lead to abnormal killing fluid loss. The larger the fluid loss volume, the longer the time is needed to flow back the killing fluid after going into operation again and the lower the fluid flow back efficiency, and the longer the time need to recover stable production of condensate oil and gas will be. Using fluid loss control solution or lowering liquid-column positive pressure differential (by using low-density killing fluid) can effectively avoid abnormal fluid loss during overbalanced well workover and guarantee productivity recovery after well workover.

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.

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.

Thief zone identification based on transient pressure analysis: a field case study

Thief zones are generally a channel with high absolute permeability. However, a not very strict theory analysis shows that neglecting the effect of variant of water saturation on formation of thief zone in mature reservoirs cannot explain some thief zones in mature reservoirs. This paper focuses on the effect of water saturation on thief zone development for wells in mature reservoirs with areal permeability heterogeneity. The water saturation increases in high permeable channel with water passing through, which gradually leads to higher value of water phase relative permeability, and thus leads to higher value of effective permeability k·k rw in the high permeable channel than that in surrounding reservoir. The gradually increasing difference of effective permeability k·k rw between permeable channel and surrounding reservoir would be the main reason for formation of thief zones in mature reservoir. The oil–water two-phase numerical model based on PEBI (perpendicular bisection) gridding is used to study effect of variant of water phase saturation on formation of thief zone. We find that relatively small pressure change and not obvious bump in pressure derivative curves during shut-in are indicators of thief zones in mature reservoirs. This finding provides a further understanding for the thief zone development and also gives us a guidance to interpret the buildup pressure data in the mature sandstone reservoirs. A field case study verifies the effectiveness of the new explanation.

Permeability of laboratory-formed porous media containing methane hydrate: Observations using X-ray computed tomography and simulations with pore network models

The permeability of methane hydrate reservoirs is a key parameter for estimating gas production performance and the flow behaviors of the gas and water during dissociation. In this study, pore network models are combined with X-ray computed tomography (CT) to investigate the index properties and percolation characteristics of hydrate-bearing porous media. Methane hydrate was formed with quartz sands in an X-ray transparent pressure vessel. Three-dimensional (3D) methane hydrate images were observed via CT and processed using VGStudio (Volume Graphics). The distribution of hydrate is non-uniform, and hydrate tends to concentrate in the pore centers. A network model representing the topology of the pores and throats (pore network models) was extracted from the processed 3D image and used in the simulation. The simulation results suggested that porosities calculated using a two-phase flow simulator used in the pore network models are in agreement with those calculated using the volumetric method. Moreover, the hydrate saturation, capillary pressure, and permeability of the hydrate-bearing porous media were calculated. The data predicted that absolute permeability decreased when hydrate saturation increased. In addition, under the same water saturation, lower hydrate saturation induced a larger water-phase relative permeability, while gas relative permeability did not exhibit obvious change. This study indicated that pore network models combined with CT, which can be used for applications in the oil and gas industry as well as carbon dioxide storage, also satisfies simulations of the hydrate. Introducing a realistic structure of hydrate-bearing porous media from CT scanning into pore network model simulation improves the accuracy of the simulation.

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.

Estimation of the Water–Oil Relative Permeability Curve from Radial Displacement Experiments. Part 2: Reasonable Experimental Parameters

The capillary pressure is the key parameter to affect the inversion accuracy of the water–oil relative permeability curve. The existing analytical inversion methods have neglected the influence of capillary pressure, which may cause low precision for the estimated relative permeability curve in some cases. On the basis of the numerical inversion method for the water–oil relative permeability curve established in part 1 (10.1021/ef300018w), taking the one-dimensional radial numerical experiment for example, the rules of relative permeability variation and influence of different displacement conditions on relative permeability deviation when neglecting the capillary pressure are investigated. With regard to water-wet cases whose oil–water viscosity ratio is greater than 1.5, it indicates that the estimated water-phase relative permeability curve is higher and the estimated oil-phase relative permeability curve is lower compared to the true relative permeability curve when the capillary pressure is neglected...