Flow In Tight Reservoirs Research Articles

Concept and key technology of “multi-scale high-density” fracturing technology: A case study of tight sandstone gas reservoirs in the western Sichuan Basin

There are abundant tight sandstone gas resources in the Sichuan Basin, which are the important objects of reserve and production increase and large-scale development. Due to their discontinuous sandbody distribution, narrow channels, and strong horizontal and vertical heterogeneity, however, conventional fracturing technologies cannot achieve the ideal stimulation effect here. In order to address this difficulty, this paper dissects the geology engineering characteristics of tight sandstone gas reservoirs in the western Sichuan Basin. Starting from the seepage mechanics theory, the concept of “multi-scale high-density” tight gas fracturing technology is put forward by fully referring to the experience of previous multi-round reservoir stimulation in the western Sichuan Basin and the idea of unconventional volume fracturing technology. In addition, its conceptual connotation, key technologies and implementation effects are illustrated. The following research results are obtained. First, the seepage characteristics make it necessary for the efficient production of tight gas reserves to increase fracture density and stimulated reservoir volume (SRV). Second, the “multi-scale high-density” fracturing technology emphasizes the rationality of high-density hydraulic fracture creation and the matching of multi-scale fracture flow capacity, and aims at establishing a multi-level fracture system with effective and steady gas flow in tight reservoirs through fracturing. Third, the “wide, dense, support, stable, and precise” fracturing technology is applied to improve single well production and estimated ultimate recovery (EUR). Fourth, the engineering practice of “multi-scale high-density” fracturing technology in the tight reservoirs of Jurassic Shaximiao Formation and Triassic Xujiahe Formation in the ZJ Gas Field realizes the average single well production rate of 15.6 × 104 m3/d, which is 1.96 times higher than that before the stimulation. Obviously, it provides powerful support for the operation of the ZJ Gas Field into a giant gas field with the reserves of 100 billion cubic meters. In conclusion, the formation of the concept and key technologies of “multi-scale high-density” fracturing technology effectively supports the efficient development of tight gas in the western Sichuan Basin and points out the following research direction of tight gas reservoir stimulation. The research results provide reference and guidance for the large-scale benefit development of tight gas in China.

Characterizing the Microscopic Anisotropic Permeabilities of Tight Oil Reservoirs Impacted by Heterogeneous Minerals

This study aimed to reveal the anisotropic permeabilities of tight oil reservoirs impacted by heterogeneous minerals. SEM imaging, image processing, fractal calculation, microscopic reservoir modeling, and visual flow simulation were carried out to investigate the above problems. Results show that the variation coefficient of two-dimensional permeability for the studied tight reservoir samples ranges from 0.09 to 0.95, with an average value of 0.68. The penetration coefficient ranges from 1.16 to 2.64, with an average value of 2.13. The ratio of maximum to minimum permeability is between 1.25 and 7.67, with an average value of 5.62. The fluid flow in tight reservoirs has significant anisotropy comprising dominant flow through conductive channels. Flow in tight oil reservoirs tends to involve minor hydraulic fracturing with no proppant.

A relative permeability model considering nanoconfinement and dynamic contact angle effects for tight reservoirs

With a sharp reduction in conventional oil and gas resources, tight oil and gas resources have attracted great interest in the petroleum industry. Relative permeability plays an important role in modeling fluid flow in tight reservoirs. Here, considering the nanoconfinement effects (abnormal viscosity effect (AVE) and slip effect) and dynamic contact angle (DCA) effect, a relative permeability model for tight reservoirs is proposed. The results show that the proposed model can accurately describe the relative permeability in tight reservoirs. As the AVE of water or oil increases, the relative permeability of water decreases, while the relative permeability of oil hardly changes for rocks with an average pore radius of 298 nm and decreases for the ones with an average pore radius of 49 nm. As the slip length of oil increases, the relative permeabilities of both water and oil decrease. As the DCA effect increases, the relative permeability of water increases, while the relative permeability of oil is unchanged. With a decrease in the pore size, the nanoconfinement effects on relative permeability become more notable, while the DCA effect on relative permeability becomes smaller. This work is of great significance to the development of tight reservoirs.

Investigation of Non-Newtonian Characteristics of Water Flow in Micro-/Nanochannels and Tight Reservoirs

The characteristic scale of pore flow in tight reservoirs is generally in the range of 0.1 μm to 1 μm, which shows the obvious micro- and nanoscale effect. The traditional oil and gas seepage theory cannot accurately describe the flow law of liquid in the micro- and nanopores. The determination of seepage characteristics is crucial to the development, layout, and prediction of tight oil. Therefore, a non-Newtonian fluid model is established to discuss the flow characteristics of confined liquid in the heterogeneous pores of microtubules and reveal the nonlinear seepage law of water in micro- and nanochannels and tight reservoirs. Based on the characteristics of non-Newtonian fluid of confined fluid in micro- and nanospace, the flow model of non-Newtonian fluid under the action of shear stress was deduced. The flow velocity variation of liquid in micro- and nanochannel and dense core was analyzed, and the flow rate of water was less than that predicted by macro theory. According to the flow experiment of water in micro- and nanochannels, the flow model of power-law non-Newtonian fluid was verified. At the same time, through the flow experiment of water in the dense rock core, the non-Newtonian model was used for nonlinear fitting, and the non-Newtonian power-law parameters and average pore radius were obtained, which verified the effectiveness of the non-Newtonian flow model.

Modeling the spontaneous imbibition of non-Newtonian fluids into the fractal porous media of tight reservoirs

This study proposes a new fractal model to describe the spontaneous-imbibition process of non-Newtonian fluids in tight reservoirs. In the new fractal model, the imbibed mass can be mainly expressed as a function of pore-geometry parameters, the rheological properties of non-Newtonian fluid, and contact angle. We validated the new model against experiments, which were conducted on three core samples collected from a tight reservoir in the Ordos Basin. Comparative analysis shows a relatively good match in imbibition profiles obtained by modeling and experiments at the early stage of imbibition. Unlike the Newtonian fluids, the modeling results suggest a non-linear relationship between imbibition distance and the square root of time when the tortuosity and non-Newtonian fluids are considered. This study may thus provide new insights into modeling the fracturing-fluid flow in tight reservoirs.

Theoretical investigation of electroviscous flows in hydrophilic slit nanopores: Effects of ion concentration and pore size

Nanopores with various shapes are well developed in unconventional reservoirs, and the transport phenomena of solutions in these reservoir rocks are ubiquitous but have not yet been fully understood. This article investigates the flow characteristics of solutions in hydrophilic slit nanopores through the combination of a modified Poisson–Boltzmann (MPB) model and the modified Navier–Stokes (NS) equation. To account for the nanoconfinement effects on ion concentration and fluid viscosity, an electrochemical potential term is used in the MPB model and a varying viscosity model (VVM) is introduced in the NS equation. The model rationality is first confirmed, and then the influences of ion concentration and pore size on the transport capacities of solutions in nanopores are illuminated. In addition, the hydrodynamic features of liquids in nanopores and the limitations of this coupled model are discussed as well. The results show that the dimensionless apparent permeability of the slit increases with an increase in ion concentration and pore size. The relative contributions of the electroviscous effect (EVE) and VVM to the total flow resistance reveal different varying trends as ion concentration or pore size increases, which is greatly related to the surface charge density and the sign of the charged wall. Additionally, although the effects of EVE and VVM resulting from the nanoconfinement are considered, average velocities of fluids in nanopores exhibit a linear correlation with the pressure gradient, which cannot be used to explain the nonlinear flow mechanism occurring in tight reservoirs. Furthermore, we also compare the velocity difference between the classical PB and MPB models. We hope that the findings in this work can help improve our understanding of the characteristics of liquid flow in tight reservoirs and provide vital practical implications for diverse engineering applications.

Dynamic capillarity during displacement process in fractured tight reservoirs with multiple fluid viscosities

AbstractDynamic capillarity commonly exists for multiphase flow in porous media, during which fluid viscosity varies and has strong influence. Displacement experiments are conducted on water‐wet, fractured tight rock at in situ pressure and temperature of an oil reservoir via a specially designed apparatus to investigate the effects of fluid viscosity on the dynamic capillarity. The dynamic effect in the matrix is examined through the measurement and calculation of capillary pressure, the dynamic coefficient, and the fluid flow behavior. The results show that with a higher oil viscosity: (a) both the steady and the dynamic capillary pressures reverse their directions more quickly and behave as larger resistances in the matrix; (b) the difference between the steady and the dynamic capillary pressures becomes around 5%‐19% more significant; (c) water saturation changes more slowly corresponding to the lower water relative permeability, while oil relative permeability quickly becomes lower than that during the basic displacement process; and (d) the dynamic coefficient becomes 2‐3 times higher, and the dynamic contact angle becomes 10%‐25% larger, showing a more variable interface. A contact angle advancement coefficient is proposed to identify the significance of contact angle advancement and the competition between capillary pressure and viscous force. The findings of this study can help for better understanding of multiphase flow in tight reservoirs and enhancing oil recovery.

Pressure Analysis for Volume Fracturing Vertical Well considering Low-Velocity Non-Darcy Flow and Stress Sensitivity

In general, there is stress sensitivity damage in tight reservoirs and fractures. Furthermore, the flow in tight reservoirs is the low-velocity non-Darcy flow. Currently, few researches of pressure analysis for volume fracturing vertical well are conducted simultaneously considering the low-velocity non-Darcy flow and stress sensitivity. In the paper, a novel flow model of a volume fractured vertical well is proposed and solved numerically. Firstly, the threshold pressure gradient, permeability modulus, and experimental data are, respectively, utilized to characterize the low-velocity non-Darcy flow, matrix stress sensitivity, and fracture stress sensitivity. Then, a two-region composite reservoir is established to simulate the vertical well with volume fracturing. After that, the logarithm meshing method is used to discrete the composite reservoir, and the flow model is solved by the method of finite difference and IMPES. Finally, the model verification is conducted, and the effects of the low-velocity non-Darcy flow and stress sensitivity on the pressure and pressure derivative are analyzed. The six flow regimes are identified by the dimensionless pressure and pressure derivative curve. They are, respectively, the fracture linear flow regime, early transition flow regime, radial flow regime, crossflow regime, advanced transition flow regime, and boundary controlling flow regime. The stress sensitivity and threshold pressure gradient have a great effect on the dimensionless pressure and pressure derivative. With the increase of reservoir stress sensitivity, the pressure and pressure derivative are upward at the advanced transition flow and boundary controlling regimes. However, the pressure and pressure derivative are downward at the advanced transition flow and boundary controlling regimes when the fracture sensitivity increases. An increase in the threshold pressure gradient results in a high dimensionless pressure and pressure derivative. This work reveals the effects of low-velocity non-Darcy flow and stress sensitivity on pressure and provides a more accurate reference for reservoir engineers in pressure analysis when developing a tight reservoir by using the volume fracturing vertical well.

Representation of a new physics-based non-Darcy equation for low-velocity flow in tight reservoirs

There has been a growing interest in the study of low-velocity non-Darcy flow in tight reservoirs. Most existing non-Darcy equations, however, are flawed in model assumption, equation derivation or field practicability. For another, current non-Darcy simulations are based on the traditional methods, which are incapable of describing the fracture-rich feature of tight reservoir geology. In light of this, this paper introduces a new physics-based non-Darcy equation for low-velocity flow from four aspects: equation derivation, experimental validation, flow simulation and flow analysis. The rigorous derivations of the new equation are presented with a modified Buckingham-Reiner equation in which the boundary layer effect and the Bingham fluid behavior are described. The non-Darcy coefficient controlled by the boundary layer parameter and threshold pressure gradient (TPG) is incorporated into Darcy's equation. The equation validations are performed by liquid column experiment and core flow experiment, which yields good matching relationship between modeled values and observed values. The non-Darcy flow simulation is based on the triangle-gridded discrete fracture-matrix model (DFM) which can model arbitrary fractures. The upstream weighting scheme for computing the non-Darcy transmissibility is proposed to improve numerical robustness. Then the scheme is implemented by constructing non-Darcy operators, consisting of half-face upstream weighting operator and gradient operator, and further setting up the Automatic Differentiation (AD)-style discrete equations. The studies on non-Darcy flow in matrix coupled with Darcy flow in fracture are performed by modeling two types of fractured reservoirs. Detailed analyses are illustrated with pressure transient, long-term well bottom pressure and pressure map.

Investigation of Cyclic $$\text {CO}_{2}$$ CO 2 Injection Process with Nanopore Confinement and Complex Fracturing Geometry in Tight Oil Reservoirs

Carbon dioxide is one of the capable processes in improving oil recovery from low-permeable oil reservoirs. However, the evaluation of cyclic $$\text {CO}_{2}$$ injection process with nanopore confinement effect in tight reservoirs is deficient in the oil industry. The nanopores confinement plays a significant role in low-permeable formations, creating a high capillary pressure which substantially influences fluid phase behavior and fluid flow in tight reservoirs. In order to consider the effect of nanopore confinement in unconventional reservoirs, the conventional methods need to be modified. Thus, we evolve an effective model for cyclic $$\text {CO}_{2}$$ injection process considering the effect of complex fracture geometry with nanopore confinement on the production from tight formations. Firstly, the reservoir fluid properties with nanopore confinement are estimated. Secondly, the minimum miscibility pressure is measured and verified with experimental data. Lastly, the well performance of cyclic $$\text {CO}_{2}$$ injection process in unconventional tight reservoirs is evaluated based on few parameters such as $$\text {CO}_{2}$$ diffusivity and matrix permeability. The results show that the combined effect of capillary pressure and $$\text {CO}_{2}$$ dispersion has significantly influenced the oil production efficiency from tight oil reservoirs. The oil recovery factor of cyclic $$\text {CO}_{2}$$ injection process at five years boosts from 14.67% as primary recovery to 22.54% due to $$\text {CO}_{2}$$ molecular diffusion effect with overall 7.87% incremental recovery. Moreover, the incremental oil recovery of cyclic $$\text {CO}_{2}$$ injection process is increased further by 1.7% while taking into consideration the combine effect of capillary pressure and $$\text {CO}_{2}$$ diffusion on the oil recovery. This study provides an appropriate method for predicting the production of cyclic $$\text {CO}_{2}$$ injection process with a complex fracture geometry, considering the capillary pressure and $$\text {CO}_{2}$$ diffusion on well performance of tight oil reservoirs.

Chromatographic separation and liquid drop-out in unconventional gas reservoirs

A study is presented on the impact of heavier components on gas production in unconventional reservoirs. The competing effects of Knudsen and molecular diffusion are incorporated by using Maxwell-Stefan equations and the Dusty-Gas approach. The total flux of gas considers contribution of viscous flow, molecular and Knudsen diffusion, adsorption/desorption and surface diffusion. The model is used to perform numerical experiments demonstrating the effects of transport mechanisms, medium permeability and initial gas composition on production performance. We evaluate pressure decline and chromatographic separation effects in the presence of a wider range of components in flow through both adsorbing and poorly-adsorbing porous media.During gas production, the flow of different chemical species will result in chromatographic separation. Therefore, gas composition will change over time, causing shifts in the phase envelope. Depending on the degree of chromatographic separation, liquid drop-out may occur in the near-wellbore.In this study, we demonstrate that for poorly adsorbing media, the degree of chromatographic separation is small due to the balance between Knudsen and molecular diffusion fluxes. In this case, chromatographic separation is intensified with decreasing permeability, since molecular sieve mechanism becomes dominant with smaller pore sizes at lower pressures. However, when adsorption is present, species separation is more relevant, resulting in significant shifts in the phase envelope. Production behavior is affected by the higher affinity of hydrocarbon molecules with adsorption sites. As a result, condensate formation in the reservoir is likely to occur as production progresses.Many analytical/semi-analytical models available for gas transport in unconventional reservoirs are based on single component or binary mixtures. In this work, we demonstrate the effect of including heavier fractions in modelling gas transport when they are present, which is relevant in prediction of pressure decline, produced gas composition and natural gas liquids (NGLs) yields. Moreover, we demonstrate that gas composition at the wellbore can be significantly influenced by a balance between viscous and diffusion fluxes, and we highlight the relevant transport mechanisms to be considered when modelling multicomponent gas flow in tight reservoirs.

A New Non-Darcy Flow Model for Low-Velocity Multiphase Flow in Tight Reservoirs

The pore and pore-throat sizes of shale and tight rock formations are on the order of tens of nanometers. The fluid flow in such small pores is significantly affected by walls of pores and pore-throats. This boundary layer effect on fluid flow in tight rocks has been investigated through laboratory work on capillary tubes. It is observed that low permeability is associated with large boundary layer effect on fluid flow. The experimental results from a single capillary tube are extended to a bundle of tubes and finally to porous media of tight formations. A physics-based, non-Darcy low-velocity flow equation is derived to account for the boundary layer effect of tight reservoirs by adding a non-Darcy coefficient term. This non-Darcy equation describes the fluid flow more accurately for tight oil reservoir with low production rate and low pressure gradient. Both analytical and numerical solutions are obtained for the new non-Darcy flow model. First, a Buckley–Leverett-type analytical solution is derived with this non-Darcy flow equation. Then, a numerical model has been developed for implementing this non-Darcy flow model for accurate simulation of multidimensional porous and fractured tight oil reservoirs. Finally, the numerical studies on an actual field example in China demonstrate the non-negligible effect of boundary layer on fluid flow in tight formations.

Investigation of nanopore confinement on fluid flow in tight reservoirs

The nanopore confinement plays an important role in the phase behavior and well performance in tight oil reservoirs; it impacts the phase behavior, as well as the fluid transport. Conventional phase equilibrium model fails to accurately simulate the complex phase behavior in the nanopores due to large capillary pressure. In this study, we modify Peng-Robinson Equation of State (PREOS) to calculate the black-oil properties including solution gas-oil ratio, viscosity, and formation volume factor by considering the capillary equilibrium. Afterward, we perform a series of sensitivity studies to identify the critical parameters affecting well performance with and without the capillary pressure effect. Five parameters, which are matrix permeability, fracture conductivity, number of fracture, fracture half-length, and bottomhole pressure, are investigated. Finally, we apply this model to analyze the performance for an actual well from the Bakken formation. We divide the nanopore size distribution into five regions, which are randomly distributed in the reservoir model. The role of the nanopore size distribution on well performance analysis is examined in detail. This work provides an improved understanding of the capillary pressure effect on the phase equilibrium and well performance in tight oil reservoirs.

Slip in natural gas flow through nanoporous shale reservoirs

It is observed that to assess the shale gas flow in nanopores the recent literature relies on the flow regimes discovered by Tsien (1946). Tsien classified fluid flow systems based on the range of Knudsen number (Kn), the ratio of the mean free path to average pore diameter. The flow regimes are: continuum flow for Kn<0.01, slip flow for 0.001<Kn<0.1, transition regime for 0.1<Kn<10, and free molecule flow for Kn>10. This scale was originally developed from the physics of rarefied gas flow. Is it then appropriate to use the classical Kn scale to develop models of shale gas flow in tight reservoirs where the nanopores are in the range of 1–1000nm, and pore pressures can be as high as 10,000psi? The present work explores answers to this question. We provide an analysis based on classical slip flow model. We validate the Kn scale incorporating PVT (Pressure–Volume–Temperatures) schemes. Our results show that in very tight shale (order of 1nm pore size) there can be substantial slip flow based on the characteristics of pore walls in the reservoirs of high temperatures and low pressures. In the case of large pore size (∼1000nm) there is zero slip flow irrespective of temperature and pressure. The Kn scale which was designed for rarefied gases cannot be true for the natural gas flow regimes at all temperatures and pressures. Therefore we must be careful in referring this scale to model the shale gas flows. Results presented here from simple calculations agree with those obtained from expensive molecular dynamics (MD) simulations and laboratory experiments.

Analytical Model for Unconventional Multifractured Composite Systems

Summary This paper presents an analytical model for unconventional reservoirs with horizontal wells with multiple fractures. The model is an extension of the "trilinear flow" solution, but it subdivides the reservoir into five regions instead of three. This enables it to be used for more-complex reservoirs. Accordingly, the model can simulate a fracture that is surrounded by a stimulated region of limited extent (fracture branching), whereas the remaining reservoir is nonstimulated. In addition to modeling flow within the fracture and flow within the stimulated region, the model takes into account flow from the surrounding nonstimulated region, both parallel to and perpendicular to the fracture. The model can be used to simulate the flow in tight reservoirs with multifractured horizontal wells. In many cases, the fractures do not have a simple biwing shape, but are branched. This effectively creates regions of higher permeability around each fracture, which obviously affect the production performance significantly. However, in many tight reservoirs, in spite of their low permeability, the surrounding nonstimulated region can also be a significant contributor to long-term production. The five-region model accounts for this contribution. Thus, it is particularly valuable when generating production forecasts for reserves evaluation. The model was validated by comparing its results with numerical simulation. We found that analytical and numerical results are in good agreement only when the geometry of the system falls within certain limitations. However, these limitations are met in most cases of interest. Therefore, the model is useful for practical engineering purposes.

Pseudo Steady State Gas Flow in Tight Reservoir under Dual Mechanism Flow

Gas reservoirs with low permeability (k<0.1 mD) are among the unconventional reservoirs and are commonly termed as Tight Gas Reservoirs. In conventional gas reservoirs that have high permeability, the flow of gas is basically controlled by the reservoir permeability and it is calculated using the Darcy equation. In these reservoirs, gas flow due to gas diffusion is ignored compared to Darcy flow. However, diffusion phenomenon has a significant impact on the gas flow in tight gas reservoirs and the mechanism of gas diffusion can no longer be ignored in comparison to Darcy flow. In this study, a dual mechanism based on Darcy flow as well as diffusion is used for the gas flow modeling in tight gas reservoirs. The diffusivity equation is obtained using this method that it indicates the gas flow in a porous media. The conventional dry gas pseudo pressure function is not able to linearize the diffusivity equation including diffusion effect. Subsequently, a new real gas pseudo pressure function is used and a novel real gas pseudo time function is introduced. These pseudo functions consider changes in gas properties with pressure and linearize the diffusivity equation. The linear diffusivity equation is solved analytically for constant gas flow boundary condition under Pseudo Steady State (PSS) situation. Then, pseudo steady state analytical solution, based on new functions of pseudo pressure and pseudo time, is obtained. The calculation of reservoir parameters such as permeability, effective diffusion coefficient and original gas in place (OGIP) using reservoir data is the first application of analytical solution. Reservoir data is required to analysis the results of application of introduced model in low permeability gas reservoir.