Fracture Network Conductivity Research Articles

Effect of proppant injection condition on fracture network structure and conductivity

AbstractThe hydraulic fracturing of shale reservoirs is an important topic, and adjusting the fracturing process can enhance fracturing efficiency. To analyze the effect of injection conditions on the fracture network structure and conductivity, numerical simulations and theoretical calculations are carried out based on the construction data, and the variation patterns of the fracture network parameters are determined. During the theory study, a fracture network conductivity model was obtained by combining the fracture network expansion model and the fracture diversion model. Then a numerical model was set up according to the analysis results of monitoring data. The numerical simulation results showed the fracture network structure and proppant distribution under different conditions. Throughout the simulation process, the structural parameters and conductivity of the fracture network can be determined by controlling the injection amount and adjusting the injection method, speed, and sand ratio. Results indicated that the proppant pulse frequency during the injection process was a major factor affecting the structure and conductivity of the fracture network. At the same time, a comparison of the distribution structure of the proppant revealed that although the intermittent injection of the proppant improved the flow channel, the efficiency of fracture utilization can still be improved.

Numerical Simulation of Fracturing Fluid Storage in Shale Reservoirs Based on Experimental Measurements of Stress Sensitivity of Hydraulic Fracture Network Conductivity

Hydraulic fracturing is used in shale reservoir production, with low flowback rates and a large amount of fracturing fluid retained inside the reservoir. In this study, a stress sensitivity analysis experiment on the fracture inflow capacity was implemented to investigate the relationship between the hydraulic fracture (HF) and natural fracture (NF) inflow capacities and effective stress. A three-dimensional shale reservoir model was also constructed to couple the experimentally obtained laws with the numerical model to investigate the effects of the connection and closure of the fracture network on the retention of the fracturing fluid. The results show that the stress sensitivity of natural fractures is two orders of magnitude higher than that of hydraulic fractures. The seepage-absorption effect of capillary forces is not the whole reason for the large amount of fracturing fluid retention. The closure of the fracture network formed by natural and hydraulic fractures during the production process led to the storage of a large amount of fracturing fluid, and this process maintained the stability of the water production rate during the steady water production period.

Optimization Method for Fracture-Network Design under Transient and Pseudosteady Conditions Using Unified-Fracture-Design and Deep-Learning Approaches

Summary In unconventional shale and tight reservoirs, the concept of stimulated reservoir volume (SRV) is used to correlate the volume of total injected proppant with well performance. The SRV configuration consists of primary fractures connected to the wellbore and secondary fractures intersecting primary fractures. SRV productivity is determined by fracture conductivity, fracture dimensions, and network complexity, which also vary with time. This work presents an extension of the unified-fracture-design (UFD) approach to account for not only the pseudosteady state (PSS) but also transient flow regimes and ultimately optimize SRV for maximizing well performance. A generalized productivity index (PI) for both the transient and PSS regimes is presented to improve well performance by searching for the maximum PI over time. In addition, a surrogate model is developed to accelerate the optimization. This study demonstrates that the UFD enables the determination of the optimal fracture network conductivity and complexity that contribute to the maximum PI with a given proppant volume. The optimal SRV design is time-dependent until the PSS is reached. The surrogate model not only improves the computational efficiency but also delivers high precision, which means far less computational burden than the traditional parametric-sensitivity analysis.

Hydraulic Behavior of Fractured Calcite-Rich Sandstone After Exposure to Reactive CO2–H2O Flow

Geological carbon sequestration in jointed reservoirs will require the use of fracture network for the flow of CO2 plumes. However, acidic solution formed at the interface between brine and CO2 can cause chemical erosion of the local rock mass, especially in rocks with high carbonate content. The use of the water alternating gas technique for injection stimulation can exacerbate this issue, as the water–CO2 interface occurs in areas near the injection point. As a result, acidic flow can impact the surrounding rock mass, particularly around the main flow paths where fracture network conductivity is much higher than matrix permeability. To investigate the impact of acidic flow on fracture conductivity, we conducted an experiment on a fractured sandstone sample that was exposed to CO2-saturated water. Our findings revealed a nearly ten-fold increase in post-experimental water-relative permeability, and restriction of flow within established flow channels, which consist one third of the fracture surface. In conclusion, our study sheds light on the dynamic behavior of fractured sandstone under the influence of CO2–H2O flow, revealing significant changes in transmissivity and fracture geometry. These findings contribute to a better understanding of the hydraulic performance of fractures in the context of geological carbon sequestration.

New Insight into Enhancing Organic-Rich Shale Gas Recovery: Shut-in Performance Increased through Oxidative Fluids

Oxidizing stimulation of organic-rich shale reservoirs, as a supplement of hydraulic fracturing, was proposed to enhance shale gas recovery. Previous publications revealed that the interaction between organic-rich shale and oxidative fluids causes the components’ dissolution, which induces lots of pores and microfractures, resulting in rock microfracturing without confined pressure and associated increments of the matrix permeability, and improving unpropped fracture conductivity. However, the enhancement of shale gas recovery with oxidative fluids still lacks an implementation clue targeted for specific engineering problems. In recent years, water–rock interaction inducing microfractures indicates a positive effect of retained fracturing fluid on the stimulation after the fracturing operation, which sheds light in the enhancement of shale gas production by shut-in. The objectives of this study are to provide a new perspective whereby the shut-in performance to enhance shale gas recovery could be increased by the injection of oxidative fluids into the formation during the fracturing operation. Firstly, the mechanisms of shut-in performance increased by oxidative dissolution, which illustrate the increment of the density of fracture networks, the improvement of fracture network conductivity, and the promotion of gas desorption and diffusivity, are demonstrated. Then, the feasibility of using oxidative fluids to increase shut-in performance, which follows the geological and engineering characteristics of organic-rich shale reservoirs, is evaluated. Finally, according to the analysis of production performance for two typical types of shale gas wells, in which one is a low gas production and a high fracturing fluid recovery (LGP-HFR) and the other is a high gas production and a low fracturing fluid recovery (HGP-LFR), a shut-in strategy with oxidative fluids to enhance shale gas recovery is developed. This indicates that the injection of oxidative fluids during the fracturing operation may become a promising and cost-effective approach to enhance shale gas recovery.

Pump-stopping pressure drop model considering transient leak-off of fracture network

By introducing the coupling flow expressions of main fracture-matrix, secondary fracture-matrix and main fracture-secondary fracture into the traditional main fracture material balance equation, the “main fracture—secondary fracture—matrix” leak-off coupling flow model is established. The pressure-dependent fracture width equation and the wellbore injection volume equation are coupled to solve the pressure-rate continuity problem. The simulation and calculation of the bottomhole pressure drop and fracture network closure after the pump stopping in slickwater volumetric fracturing treatment are realized. The research results show that the log-log curve of pump-stopping bottomhole pressure drop derivative presents five characteristic slope segments, reflecting four dominant stages, i.e. inter-fracture crossflow, fracture network leak-off, fracture network closure and residual leak-off, after pump shutdown. At the initial time of pump shutdown for volumetric fracturing treatment of horizontal well, the crossflow between main and secondary fractures is obvious, and then the leak-off becomes dominant. The leak-off of main and secondary fractures shows a non-uniform decreasing trend. Specifically, the leak-off of main fractures is slow, while that of secondary fractures is fast; the fracture network as a whole presents the leak-off law of fast first, then slow, until close to zero. The influence of fracture network conductivity on the shape of pressure decline curve is relatively weaker than that of fracture network size. The fracture network conductivity is positively correlated with leak-off volume and fracture closure. The secondary fracture size is positively correlated with leakoff volume and closure of the secondary fracture, but negatively correlated with closure of the main fracture. Field data validation proves that the proposed model and simulation results can effectively reflect the closure characteristics of the fracture network, and the interpretation results are reliable and can reflect the non-uniform stimulation performance of each fracturing stage of an actual horizontal well.

Enhancing fracture network characterization: A data-driven, outcrop-based analysis

We utilize a pixel-based fracture detection algorithm to digitize 80 published outcrop maps of different scales at different locations. The key fracture properties, including fracture lengths, orientations, intensities, topological structures, clusters, and flow, are analyzed. Our findings provide significant justifications for statistical distributions used in SDFN modelings. We find that fracture lengths follow multiple (instead of single) power-law distributions with varying exponents. Large fractures tend to have large exponents, possibly because of a small coalescence probability. Most small-scale natural fracture networks have scattered orientations, corresponding to a small κ value (κ<3) in a von Mises–Fisher distribution. Large fracture systems analyzed in this research usually have more concentrated orientations with large κ values. Fracture intensities are spatially clustered at all scales. A fractal spatial density distribution, which introduces clustered fracture positions, can better capture the spatial clustering than a uniform distribution. Natural fracture networks usually have a significant proportion of T-type nodes, which is unavailable in conventional SDFN models. Thus, a rule-based algorithm is necessary to mimic the fracture growth and form T-type nodes. Most outcrop maps show good topological connectivity. However, sealing patterns and stress impact must be considered to evaluate the hydraulic conductivity of fracture networks.

Pressure transient response with random distributed fracture networks using a semi-analytical method for fractured horizontal wells in a rectangular closed reservoir

The focus of this paper is to establish a general model, which is capable of dynamic simulation of discrete fractures at any position and arbitrary distribution in rectangular closed reservoir. In this article, a semi-analytical model for fractured horizontal wells with random distributed fracture networks is proposed to facilitate pressure transient response using a double node method. A rectangular closed reservoir model and fracture network flow model are established respectively, and then coupled at the fracture wall. In order to deal with the flow distribution at the fracture intersection, a simple adaptive material balance method is proposed in this paper, which successfully solves the flow distribution at the intersection. Using advanced mathematical means, the model is successfully solved in Laplace space, and then the pressure response solution in real space is obtained by Stehfest numerical inversion method. The obtained solutions are verified and compared with the numerical simulation results. The calculation results show that the flow characteristics of the orthogonal fracture network can be roughly divided into six stages, namely, bi-linear flow, first linear flow, first radial flow, second linear flow, second radial flow and boundary dominated flow. However, these flow characteristics will deviate or even be missing, depending on the complexity of the fracture network. Finally, the effects of some important parameters (such as dimensionless fracture network conductivity, main fracture length, fracture network density, reservoir area and eccentric position) on pressure response and pressure field distribution are discussed in detail.

Evaluation Method of the Vertical Well Hydraulic Fracturing Effect Based on Production Data

Hydraulic fracturing technology has become a key technology for the development of low-permeability/tight oil and gas reservoirs. The evaluation on the postfracturing effect is imperative to the formulation and implementation of the fracturing and development plan. Based on the characteristics of the flow in fracture network after a large-scale hydraulic fracturing, a numerical method for evaluating the effect of fracturing in vertical well was established. This study conducts postfracturing effect evaluations to block C Oilfield’s wells that underwent conventional fracturing and volumetric fracturing, respectively, proposes the definition of fracture network conductivity and its relationship with cumulative production, and analyzes the fracturing construction parameters. The results suggest that the conventional fracturing can only form a single fracture instead of a stimulated reservoir volume (SRV) region. However, the volumetric fracturing transformation can form a complex fracture network system and SRV region and meanwhile bring obvious increase in the production. The effective time lasts for a longer period, and the increase of average daily oil is 2.2 times more than that of conventional fracturing. Additionally, with the progress of the production, the SRV area within the core region of the volume transformation gradually decreased from 6664.84 m2 to 4414.45 m2; the SRV area of the outer region decreased from 7913.5 m2 to 5391.3 m2. As the progress develops, the equivalent permeability and the area of the fracture gradually decrease as the fracturing effect gradually weakens, and so does the conductivity of the network decreasing exponentially; a good correlation is observed between the conductivity of the fracture network, the cumulative production, and fracturing construction parameters, which can serve as the evaluation parameters for the fracturing effects and the basis for fracturing productivity prediction and provide a guidance for fracturing optimization design.

A new method of predicting network fracture conductivity based on the similitude principle of water and electricity

The conductivity of network fracture is a key factor that affects horizontal well production, but using conductivity cells or modified conductivity cells to test it is uncommon. Several theoretical and empirical models have been developed to estimate network fracture conductivity. This paper develops a new method of calculating network fracture conductivity based on the electrical similitude principle and experimental data. Taking into account the network fracture type, test fluid type, proppant combination ratio, and propped type, an experimental scheme is designed, and a series of network fracture conductivities are obtained indoors. Using the formula for seepage resistance R and a calculation procedure chart, the equivalent conductivity of the 20°, 30°, 45°, 60°, and 90° types of network fractures are compared between test data and predictions. Comparisons of our experimental data to the prediction data indicate little error, verifying the accuracy of the new method. This predicting method can provide a reference for the fracture network conductivity optimization of shale reservoir multi-staged fracturing.

Numerical Simulation on Proppant Transport in Fracture Junctions Affected by the Fracture Scale

Abstract The proppant distribution significantly affects the conductivity of fracture networks. However, the law of proppant transport in fracture networks is still unclear, and the influence of fracture scale on the proppant distribution has not been determined. Thus, in the present study, the influence of fracture scale was investigated, and the influences of approaching angle and width ratio on fluid split ratio were analyzed. An Eulerian–Eulerian model was utilized to simulate suspended proppant and bed load proppant migration in fracture junctions. Then, a sensitivity analysis was carried out to evaluate the parameters that may affect the proppant distribution pattern, such as injection velocity, fluid viscosity, and proppant density. The results show that the approaching angle and width ratio significantly influence the fluid split ratio in a small-scale fracture. Moreover, the effect of the approaching angle decreases with an increase in the fracture scale. The split ratio of suspended proppant increases with increasing sand ratio, fluid split ratio, and width ratio. The split ratio of bed load proppant increases with increasing injection rate, fluid viscosity, width ratio, fluid split ratio, and decreasing proppant diameter. In small-scale fracture junctions, the approaching angle affects the split ratio of suspended proppant or bed load proppant by influencing the fluid split ratio; however, the effect is inconspicuous in large-scale fractures. The increase in fluid split ratio with the fracture scale leads to an increase in the split ratio of suspended proppant or bed load proppant.

Comparison of fracturing unconventional gas reservoirs using CO2 and water: An experimental study

CO2-based fracturing (CBF) has been regarded as the most promising alternative to water-based fracturing (WBF) in water-sensitive unconventional gas reservoirs, and the fracture initiation and propagation at different in-site stresses created by CBF is crucial to the flow conductivity of fracture network. The main aim of this study is to compare the fracturing efficiency of WBF and CBF by conducting a series of fracturing tests on siltstone samples. According to the experimental results, the breakdown pressure linearly increases with the confining pressure, and the slope is 1.3928 and 1.6422 for CBF and WBF, respectively, and the much lower breakdown pressure for CBF is because of the fast penetration of CO2 through the rock matrix, which significantly reduces the effective stress around the borehole. Importantly, the observed fracture aperture for CBF is much greater than that for WBF, the maximum fracture aperture for CBF is around 2 to 5 times greater than that for WBF under the same test conditions. The difference in fracture aperture depends on the presence of discrete blocks and particles, and CBF can create greater and more loose particles in both mechanically-created method and hydraulically-created method to keep the created fractures open after the release of the injection pressure. The greater fracture aperture of CBF is favourable for the flow capacity of the fractures and therefore reservoir productivity, which is verified by the permeability tests with 190.43 times of permeability than that of WBF. Interestingly, the greater fracture width expansion for CBF perpendicular to the major principal pressure promotes the generation of horizontal fractures, even when the injection pressure is smaller than the major principal pressure, and the probability of horizontal fracture for CBF is 4–5 times of that for WBF, which reflect its great potential to create complex fracture network in unconventional gas reservoirs. The test results reveal that CBF is superior to the WBF since it is capable to create much more complex and efficient fracture networks. The findings are beneficial to understand the difference of fracturing behaviours at different in-site stresses between WBF and CBF, and provide experimental guidance for the exploitation of water-sensitive unconventional gas reservoirs by CBF.

A new well test interpretation model for complex fracture networks in horizontal wells with multi-stage volume fracturing in tight gas reservoirs

Multi-stage volume fracturing of horizontal wells is the main means to develop tight gas reservoirs. Complex fracture networks of various shapes are generated around the wellbore after volume fracturing. At present, however, most of the well test models suitable for fracturing horizontal wells take all hydraulic fractures as single main fractures, which results in a large error between well test interpretation result and actual situation. As a result, the fracture network characteristic parameters of the stimulated areas cannot be obtained accurately. To this end, a well test model for complex fracture networks in tight-gas fracturing horizontal wells was established on the basis of the non-structural discrete fracture model. Then, this model was solved by using the finite element method with combined triangular elements and linear elements. And accordingly, the well test type curves of a horizontal well under different fracture network patterns (rectangular, elliptical and hyperbolic) were prepared. Based on this, well test type curves were analyzed from the aspects of characteristics and influential factors and were compared with those obtained from the conventional single-fracture model. Finally, the new model was applied in well test interpretation of one multi-stage volume fracturing horizontal well in the gas reservoir of Permian Shan 1 formation in the Qingyang Gas Field of the Ordos Basin. And the following research results were obtained. First, the biggest difference of well test type curve between the fracture network model and the conventional single-fracture model occurs in the early stage, the characteristics of first linear flow regime are replaced with the characteristics of pseudo-radial flow regime in the stimulated area. Second, the end time of the pseudo-radial flow regime in the stimulated area is mainly dominated by the size and shape of the stimulated area. The larger the stimulated area is, the longer the pseudo-radial flow regime lasts. As the shape of the stimulated area approaches to be elongated, the characteristics of the well test type curve obtained by the new model are more consistent with those by the single-fracture model. Third, the pressure derivative value of the pseudo-radial flow regime in the stimulated area is mainly dependent on the conductivity and density of the fracture network. The higher the density or the conductivity of fracture network in the stimulated area is, the earlier the wellbore storage effect regime ends, the lower the pressure derivative value of the pseudo-radial flow regime in the stimulated area is and the more obvious the characteristics of the horizontal line are. In conclusion, case study results confirm that the new model is reliable and practical and can provide accurate reservoir parameters as well as the size of the effectively stimulated area by volume fracturing and the conductivity of fracture network, which is conducive to evaluating the stimulation effect of volume fracturing and predicting the postfrac production performance.

Effects of proppant distribution in fracture networks on horizontal well performance

In this paper, we presented a coupled 3D finite element method model for the simulation of proppant transport in fracture networks and its effects on horizontal well performance. We used a mixture model, which have advantages to deal with two-phase flow containing a dispersed phase like solid particles, to simulate the proppant transport process in fracture networks. Then a tight oil reservoir model was established to evaluate the effect of the proppant distribution on the horizontal well performance. The effects of several factors, such as the proppant physical properties and injection parameters, were analyzed. The calculated results show that, in the fracture network, proppant accumulates at the intersections of cracks. Height of the proppant packed bed in natural fracture was about 30% smaller than that in the main hydraulic fracture, and the communication between hydraulic fractures leads to a larger proppant dune and higher conductivity. Besides, in a tight oil reservoir, the proppant distribution has a significant influence on the well performance. When the reservoir permeability is reduced to 0.05 mD, the productivity index fold of increase calculated including the proppant uneven distribution can be 47.7% larger than that calculated with idealized proppant distribution. Furthermore, the proppant physical properties and injection parameters are found to be correlated with the fracture network conductivity. Based on this analysis, optimum proppant injection conditions can be identified.

Effective hydraulic conductivity of discrete fracture network with aperture-length correlation

Determining effective hydraulic conductivity is critical to understand groundwater flow behavior in fractured rock masses and is required for large-scale numerical simulations. A new approach is developed to estimate the effective hydraulic conductivity of a discrete fracture network with aperture and trace length being stochastic and correlated. The aperture and length are assumed to follow a joint lognormal distribution. The average flowrate through the network is determined by integrating flowrate in the fracture ensemble with the laminar flow and non-linear flow being separately considered based on the Reynolds number. The effective hydraulic conductivity of the discrete fracture network is then determined from the idea that Darcy’s law still applies to the overall flow behavior through the network. For comparison, the simple average hydraulic conductivity is also developed based on the assumption that flow in all fractures is laminar and aperture and trace length are uncorrelated. Based on the developed approach, the effects of aperture and trace length uncertainty, their correlation degree, and non-linear flow characteristics on the ratio of effective hydraulic conductivity over simple average hydraulic conductivity are examined. The results demonstrate that the effective hydraulic conductivity can be either larger than or smaller than the simple average hydraulic conductivity depending on correlation level between aperture and trace length and the degree of non-linear effect in the network. Non-linear flow reduces the effective hydraulic conductivity of the fracture network. Correlation between aperture and trace length increases the effective hydraulic conductivity. Aperture uncertainty tends to reduce the effective hydraulic conductivity.

Discrete Fracture Modeling approach for simulating coupled thermo-hydro-mechanical effects in fractured reservoirs

We present a new formulation for modeling the coupled flow, thermal, and mechanical effects in real fractured subsurface formations. Natural fractures are represented explicitly as surfaces in contact with fluid between them. We use a finite volume method to discretize mass and heat conservation equations and a Galerkin finite element method to discretize mechanical equilibrium equations. We use the Nitsche approach to enforce fracture-contact constraints. The proposed formulation allows us to accurately evaluate fracture conductivity and volume change due to stress changes induced by variations in fluid pressure and temperature. To solve the resulting set of non-linear equations, we present a new sequentially implicit solution strategy based on a fixed-stress scheme for fractures, in addition to the established fully implicit approach. Our formulation is implemented within an existing general purpose research simulation platform that can account for complex physics such as multi-phase, multi-component flows. We show the convergence behavior of the sequential-implicit scheme for the problems considered.We demonstrate the utility of the formulation by considering the process of injecting cold water into a real fractured carbonate reservoir and evaluating the impact of resulting changes in formation pressure, temperature, and acting stresses on well bottom hole pressure measurements at the well. The goal of this application is to analyze the anomalously declining well pressure behavior observed during an actual short-term water-injection pilot operation towards informing the decision-making and preparation for potential large-scale waterflooding. We first perform a sensitivity analysis using a 2D conceptual model to assess key factors controlling the coupled effects for this problem: fracture and matrix properties, initial stress state, pressure- and temperature-induced stress changes and the propensity of fractures to slip, as well as Biot's coefficient. We then applied the framework on a 3D sector model of a fractured reservoir. We conclude that the observation was likely due to the substantial stress reduction caused by pressure and temperature changes, leading to slip events and a significant increase in fracture network conductivity near the injector. Thermal effects have less of an impact during the relatively brief pilot injection in this case but are expected to become important for long-term waterflooding.The application to a real waterflooding problem demonstrates the usefulness of the proposed thermo-hydro-mechanical framework for practical studies of real fractured reservoirs.

A heterogeneous model for simulating fluid flow in naturally fractured-vuggy carbonate reservoirs

In this paper, a heterogeneous model named matrix-fracture-vug (MFV), which considers the interactions of flow regimes in matrix, discrete natural fractures, large-scale fractures and vugs, is developed for simulating fluid flow in fractured-vuggy reservoirs. In the MFV model, coupling Darcy-Stokes equations are used to describe flow regime in matrix and vugs. Fluid flow follows the cubic law in each discrete natural fracture. An equivalent method is put forward in large-scale fractures. The flow mechanisms in fractured-vuggy reservoirs are analyzed, and the oil well productivity is demonstrated by investigating the influences of the matrix, fractures and vugs. The matrix permeability controls the production rate in the whole production process, and the conductivity of fracture network is another main influence factor. The cumulative production will increase due to the storage capacity of vugs in later period. This model can provide insights into the history matching and the production prediction for fractured-vuggy. [Received: August 4, 2016; Accepted: September 20, 2017]

Exploitation of fractured shale oil resources by cyclic CO2 injection

With shale oil reservoir pressure depletion and recovery of hydrocarbons from formations, the fracture apertures and conductivity are subject to reduction due to the interaction between stress effects and proppants. Suppose most of the proppants were concentrated in dominant fractures rather than sparsely allocated in the fracture network, the fracture conductivity would be less influenced by the induced stress effect. However, the merit of uniformly distributed proppants in the fracture network is that it increases the contact area for the injection gas with the shale matrix. In this paper, we address the question whether we should exploit or confine the fracture complexity for CO2-EOR in shale oil reservoirs. Two proppant transport scenarios were simulated in this paper: Case 1—the proppant is uniformly distributed in the complex fracture system, propagating a partially propped or un-propped fracture network; Case 2—the proppant primarily settles in simple planar fractures. A series of sensitivity studies of the fracture conductivity were performed to investigate the conductivity requirements in order to more efficiently produce from the shale reservoirs. Our simulation results in this paper show the potential of CO2 huff-n-puff to improve oil recovery in shale oil reservoirs. Simulation results indicate that the ultra-low permeability shales require an interconnected fracture network to maximize shale oil recovery in a reasonable time period. The well productivity of a fracture network with a conductivity of 4 mD ft achieves a better performance than that of planar fractures with an infinite conductivity. However, when the conductivity of fracture networks is inadequate, the planar fracture treatment design maybe a favorable choice. The available literature provides limited information on the relationship between fracture treatment design and the applicability of CO2 huff-n-puff in very low permeability shale formations. Very limited field test or laboratory data are available on the investigation of conductivity requirements for cyclic CO2 injection in shale oil reservoirs. In the context of CO2 huff-n-puff EOR, the effect of fracture complexity on well productivity was examined by simulation approaches.

A Heterogeneous Model for Simulating Fluid Flow in Naturally Fractured-vuggy Carbonate Reservoirs

In this paper, a heterogeneous model named matrix-fracture-vug (MFV), which considers the interactions of flow regimes in matrix, discrete natural fractures, large-scale fractures and vugs, is developed for simulating fluid flow in fractured-vuggy reservoirs. In the MFV model, coupling Darcy-Stokes equations are used to describe flow regime in matrix and vugs. Fluid flow follows the cubic law in each discrete natural fracture. An equivalent method is put forward in large-scale fractures. The flow mechanisms in fractured-vuggy reservoirs are analyzed, and the oil well productivity is demonstrated by investigating the influences of the matrix, fractures and vugs. The matrix permeability controls the production rate in the whole production process, and the conductivity of fracture network is another main influence factor. The cumulative production will increase due to the storage capacity of vugs in later period. This model can provide insights into the history matching and the production prediction for fractured-vuggy. [Received: August 4, 2016; Accepted: September 20, 2017]

Analytical model to simulate production of tight reservoirs with discrete fracture network using multi-linear flow

A common way to produce hydrocarbons from tight reservoirs is to use volume fracturing. After volume fracturing, the stimulated reservoir volume (SRV) always exists around the wellbore. To characterize the SRV, many work have been done using simulation methods. The Discrete Fracture Network (DFN) model is one of the commonly used simulation methods. Based on the simulated results of DFN model, this paper constructed a multi-linear flow model to analyze the pressure transient and rate transient behaviors in tight oil reservoirs with SRV, where the reservoir is divided into many regions including matrix system outside the fracture network, matrix system inside the fracture network, fracture network system. We formulates the 1-D flow solutions for each region, and then couple them by imposing flux and pressure continuity across the boundaries between regions. We solve the model with the linear flow model and using Laplace transform and Stehfest algorithm comprehensively. The model solution is verified with numerical simulation thoroughly. And we test the model with field cases to analyze fractured well performance in tight oil reservoir. History matching results are shown according to real production data. Sensitivity studies to quantify the key parameters affecting the well performance were performed finally. Five variables, which are fracture spacing, fracture network size, fracture network conductivity, matrix permeability and reservoir size, were investigated. The presented new model and obtained results can enrich the production performance analysis methods for tight oil reservoirs.