Dual-permeability Model Research Articles

Integration of Geological Model and Numerical Simulation Technique to Characterize the Remaining Oil of Fractured Biogenic Limestone Reservoirs

AbstractFine geological modeling leads to accurate reservoirs numerical simulations. Fractured biogenic limestone has abundant storage spaces and flow paths to accumulate oil and gas. The complexity and diversity of fractured biogenic limestone also lead to challenges in accurately characterizing its pore volume and remaining oil. This investigation aimed to enhance the understanding of fractured biotite reservoir properties via geological modeling. Numerical simulations were used to characterize the remaining oil during the late stage of field development. Considering the differences in porosity and permeability between fractures and matrix, a facies-controlled stochastic modeling technique was used to establish a dual-porosity and dual-permeability (DPDP) model for numerical simulation. Core information, logging data, and multiple seismic attributes were combined to guide low-level sequence fault interpretation for tectonic refinement. Based on classified seismic inversion, sedimentary phases were reconstructed. A discrete fracture network (DFN) model was obtained based on fracture occurrences and density models. The optimized discrete adjoint (ODA) algorithm was utilized to calibrate model parameters. The findings revealed that dense tectonic fractures develop in thick biogenic limestone areas. Combined with advanced reservoir simulation technology, these findings suggest that areas of thicker biogenic limestone were consistent with areas of higher fracture matrix conductivity multipliers. The remaining oil distribution patterns were investigated, and to deploy new wells was guided. Therefore, it is essential to better understand the tectonic characteristics of fractured biogenic limestone reservoirs and their remaining oil distribution patterns by integrating multiple sources of information and mastering advanced reservoir simulation technology for oilfield development.

Zeolite intervention in soil nitrate dynamics: insights from column experiments and modelling

This study aims to address the harmful effects of excessive nitrogen fertilizer by investigating the mobility-retardance effect of zeolite on nitrate movement in loam soil columns. Disturbed and undisturbed soil columns, treated with zeolite as well as control soil columns, were analysed over a span of three years. Breakthrough curves generated from the experiments were evaluated using the HYDRUS-1D code with mobile–immobile water (MIM) and dual-permeability (DP) models. Our findings highlight that zeolite application significantly reduced nitrate mobility, with recovery rates decreasing by 8% in disturbed and 11% in undisturbed columns. The DP model, which accurately reflects real soil water flow conditions, outperformed the MIM model in predictive accuracy. This research offers a novel long-term perspective on the benefits of zeolite in enhancing soil properties and mitigating nitrate leaching, recommending the DP model for superior prediction of contaminant transport in structured soils within the vadose zone.

Analysis of Carbon Dioxide Injectivity and Dynamic Storage Capacity in Shale Reservoirs

Abstract Carbon dioxide could be stored in unconventional shale reservoirs in supercritical state due to available pore volume, infrastructure, and injectivity. However, there is a lack of knowledge about the injectivity and storage capacity in shale reservoirs. In this manuscript, a two-dimensional dual-porosity, dual-permeability model was built to investigate CO2 injectivity and dynamic storage capacity spatially and temporally. Parametric studies are conducted to evaluate the effect of matrix permeability, fracture conductivity, fracture half length, operating conditions, and near-wellbore connectivity on storage factors. Systematic and comprehensive numerical experiments are carried out using random sampling to generate a probability distribution of CO2 storage factors and replacement ratio. Results showed the parameters with most impact to least impact on injectivity and storage factor: matrix permeability, near-wellbore connectivity, bottomhole pressure, fracture half length, and fracture conductivity. The methodology in this study provides a foundation to examine how CO2 storage factors change spatially and temporally in and outside the SRV. The new understanding can be applied to optimize field development, well spacing, and infill drilling to increase economic storage.

Effect of Wettability and Permeability on Pore-Scale of CH4–Water Two-Phase Displacement Behavior in the Phase Field Model

Hydraulic measures such as hydraulic slotting and hydraulic fracturing are commonly used in coal seam pressure relief and permeability enhancement. Two-phase flow patterns of CH4–water in pore-sized coal seams after hydraulic measures are critical to improve gas extraction efficiency. The phase field module in COMSOL Multiphysics™ 5.4 and the classical ordered porous media model were used in this paper. The characteristics of CH4–water two-phase immiscible displacement in coal seams under different capillary numbers (Ca) and viscosity ratios (M) were simulated and quantitatively analyzed. By changing the contact angle of the porous media, the flow patterns of CH4–water two-phase in coal with different wettability were simulated. Results show that wettability significantly affects the displacement efficiency of CH4. Additionally, by constructing a dual-permeability model to simulate the varying local permeability of the coal, the flow patterns of different Ca and M in dual-permeability media were further investigated. It is found that CH4 preferentially invades high-permeability regions, and the displacement efficiency in low-permeability regions increases with higher Ca and M, providing a reference for gas extraction from coal seams after hydraulic measures.

Analysis of Ultimate Gas Recovery in Shale Reservoirs

Abstract Horizontal wells with multistage fracture treatments enabled economic gas production from shale gas reservoirs. Recovery from a typical shale reservoir is usually quite low as numerous factors can affect the ultimate recovery. However, recovery factors inside and outside the stimulated reservoir volume (SRV), especially the variations spatially and temporally, are not yet fully understood as the numerical simulation of shale gas production is still challenging. In this study, a dual-porosity, dual-permeability model was built to investigate ultimate gas recovery and its spatial variations throughout the production period. Parametric studies were conducted to evaluate the effect of matrix permeability, fracture conductivity, fracture half length, and operating conditions on recovery factors. Systematic and comprehensive numerical experiments were carried out to generate a probability distribution of ultimate recovery factors. The results presented in this article provide insight into the impact that key parameters have on these recovery factors in and outside the SRV and the range of recovery factors one can expect from shale gas reservoirs. Fracture conductivity has the most impact on recovery in the SRV while matrix permeability can affect the recovery outside the SRV significantly. The expected recovery in the SRV is 24% in shale reservoirs. The methodology in this study provides a foundation to develop more reliable models in accurately forecasting ultimate gas recoveries spatially for shale gas reservoirs. The new understanding can be applied to optimize field development, well spacing, and infill drilling to increase economic recovery.

A Practical probabilistic history matching framework for characterizing fracture network parameters of shale gas reservoirs

Simulating fluid flow in complex fracture systems encountered in subsurface systems, such as those encountered in tight or shale gas reservoirs, presents considerable challenges. Sophisticated numerical techniques and characterization approaches are required to integrate static and dynamic data from multiple sources to account for the intricate interplay between fractures and the surrounding rock matrix. A novel workflow using an indicator-based probability perturbation method (PPM) is applied to characterize uncertain discrete fracture network parameters. The posterior probability distributions of primary and secondary fracture transmissivity, aperture, length, height, and intensity of the secondary fracture are estimated according to the production (flow) histories. A case study based on the Horn River shale gas reservoir is presented. A pilot point scheme is formulated to update the distributions of P32L. The forward modelling entails upscaling each fracture model into a dual-porosity dual-permeability model and performing multiphase flow simulation. This approach produces an ensemble of history-matched discrete fracture and upscaled models by incorporating static and dynamic data. The results demonstrate the utility of the developed method for estimating secondary fracture parameters, which are not inferrable from other static information alone. The inference of both primary and secondary fractures offers a more comprehensive characterization of the fracture networks in tight or shale gas reservoirs. Integrating a pilot point parameterization technique and a sequential simulation approach into the PPM framework presents significant novelties in contributing to a comprehensive and effective method of simulating fluid flow in complex fracture systems, addressing the challenges associated with non-linear relationships between fracture model parameters and the corresponding flow response.

Introducing a transition domain for describing the solute exchange between macropores/fractures and matrix in dual-permeability system

The dual-permeability model (DPM) is highly efficient for describing the solute transport with multiple flow paths in macroporous/fractured media. However, an accurate and efficient description of the solute exchange process between the macropores/fractures and matrix in the dual-permeability system still remains a challenge. Therefore, a new approach, the dual-permeability model with transition domain (DPMTD), is proposed under saturated conditions. DPMTD characterizes the boundary layer by dividing the part of the matrix blocks in contact with the macropores (or fractures) into the transition domain. This new method takes into account the effect of concentration distribution in the matrix on the solute exchange process without upgrading the dimension of equations. The expressions of the first-order mass transfer coefficient, which is used to describe the interdomain solute exchange in the DPMTD, for four defined aggregate geometries are obtained. A sand column experiment containing an artificial macropore is used to evaluate the performance of the DPMTD and DPM. The simulation results of the DPMTD and DPM reveal that the DPMTD captures the bimodal transport (especially the first peak) more effectively because it calculates the rapid solute exchange in the early time and the slow solute exchange in the later stage more accurately. Subsequently, we studied the effect of η, which indicates the volume proportion of the boundary layer to the dual-permeability media in the DPMTD, on results. In short, this study emphasizes the importance of the boundary layer, and provides a new efficient approach to describe solute exchange process between macropores (or fractures) and matrix in dual-permeability system.

Model Shows Computational Gains, Preserves Accuracy in Tight Rock EOR

_ This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper URTeC 3834855, “Advanced Dual-Porosity and Dual-Permeability Model for Tight Rock Integrated Primary Depletion and Enhanced Oil Recovery Simulation,” by Daegil Yang, SPE, Tyler Do, and Changdong Yang, SPE, Chevron, et al. The paper has not been peer reviewed. _ Discrete fracture or dual-porosity modeling has been widely adopted for tight rock simulation. To represent the complex fracture heterogeneity and simplify its characterization, the authors present in the complete paper a new simulation model to holistically optimize the tight rock reservoir completion, primary depletion, and enhanced oil recovery modeling and retain the injection mechanism and simplify the complex fracture characterization to enhance computational efficiency. The model enables users to characterize different properties in multiple regions. This tool will have broad applications in supporting asset-development decisions. Introduction Traditional dual-porosity, dual-permeability (DPDK) simulation incorporates microscale fracture characterization through the shape factor (matrix/fracture coupling), which offers a significant contact area for the gas/oil mixture to represent the field response reliably. However, its homogeneous fracture network cannot be used to optimize the completion design. The authors have developed what they refer to as the advanced DPDK (A-DPDK) simulation work flow to maintain heterogeneous fracture characterization and to simplify microfracture characterization. The work flow contains the following features: - A newly derived shape-factor algorithm that can represent the scale and heterogeneity of the fracture network - Local grid refinement (LGR) that accelerates the speed of computation (five-times-faster acceleration) and improves accuracy - A fracture-characterization feature that serves as a helpful diagnostic tool to assign a flexible cutoff value for both propped fractures (PF) and unpropped fractures to enhance simulation speed and robustness - A connected PF feature that can label the effective fracture region to simplify completion design work flow and prioritize reservoir simulation The authors validated the new features implemented in the work flow systematically and demonstrated the benefits of the proposed work flow. The authors also applied the work flow in one gas-injection pilot and successfully history-matched the primary depletion and the gas-injection response. Modeling Approach The A-DPDK model design is aimed at modeling a complex fracture network using a structured grid system while maintaining the background natural fracture. In the modeling process, the main fracture network is screened and identified and its transmissibility calculated. Then, the microfracture is calculated to matrix mass transfer. This can be numerically modeled using a DPDK framework. The geometry of the hydraulic fracture network is preserved explicitly as grid cells in the fracture domain. Also, in the matrix domain, the enhanced permeability region (EPR), which represents the microfracture, is included. The mass transfer between matrix cells and the EPR is modeled as a grid-cell connection (transmissibility), and the mass transfer between the hydraulic fracture cells and the microfractures is modeled as a grid-cell connection as well. A new way of calculating the coupling term that models the mass transfer between the hydraulic fracture and the EPR and the matrix is introduced.

Microfluidics investigation of the fracture/matrix interaction mechanisms during preformed particle gel (PPG) treatment in fractured porous media

Although water injection is one of the most common methods for enhancing the recovery from oil reservoirs, its effectiveness in severely heterogeneous porous media such as fractured rocks, is debatable. Preformed Particle Gel (PPG) treatment is one of the most promising methods which is considered for water shut-off in the near wellbore area or improving the sweep efficiency of the injected water deep in the reservoir. Recognizing the PPG transport mechanisms in fracture, fracture/matrix interactions during and after PPG treatment, and the contributing parameters on such mechanisms, is a prerequisite for designing an effective water shut-off process and possible enhanced oil recovery (EOR). With this aim, the dynamic behavior of PPG samples is studied in two different fractured porous media representing the near wellbore area (dual permeability model) and deep in the reservoir zones (single permeability model). During encroachment of the gel particles in fracture, the dehydration of gel produces a large volume of filtrate which sweeps the oil inside the matrix. PPG particles might go through deformation, shrinkage and/or breakage, before infiltrating into pores of matrix where they form an impermeable cake. The experimental results shows that formation of such cake, is one of the main affecting parameters in the performance of the conformance control and EOR. Additionally, the affecting parameters such as concentration of nano-silica (n-SiO2), width of fracture, particles size, ionic strength of brine and injection rate of gel were examined. The concentration of n-SiO2 affects the gel loss factor (ratio of loss modulus to storage modulus) and hence its encroachment behavior. The gel sample with 1 wt% n-SiO2 has the highest loss factor which makes it more favorable for water shut-off considering lower injection pressure and less volume required for treatment. The water shut-off treatment is more effective in the case of systems with wider fractures. Based on the size of the PPG particles, the plugging mechanisms of the fracture can be either direct plugging, bridge plugging or a combination of both mechanisms, however all the studied samples provided same degree of plugging efficiency in the performed experiments. Swelling the samples in brines with higher salinities reduces the required volume of gel, while the injection pressure remained unaffected. To reduce the required volume of gel, highest possible injection rate is recommended, since the shear thinning rheology of the gel damps increment of injection pressure. In the case of single permeability model, water shut-off treatment reduced the fracture conductivity effectively, so that in the subsequent flooding, the injected brine was diverted toward matrix and the displaced oil was recovered through the fracture. During water flooding stage after gel placement, the withstanding pressure of PPG must be taken into account to avoid gel rupture, movement and washout.

An improved dual-porosity dual-permeability modeling workflow for representing nonplanar hydraulic fractures

The Dual-Porosity Dual-Permeability (DPDK) model is commonly used for upscaling and simulating fractured reservoirs. However, many common upscaling approaches lead to disconnected fracture, particularly when simulating Discrete Fracture Networks (DFN) and nonplanar hydraulic fractures that are not aligned with the axes of corner-point grids supported by most reservoir simulation packages using the Two-Point Flux Approximation (TPFA) technique for flow and mass transfer calculations. This misalignment could result in inaccurate computed fluxes when fractures are disconnected in the upscaling process. Our previous works attempted to address this problem in DFNs by detecting misalignments and adjusting DPDK fracture parameters locally. However, such methods required explicit knowledge of the fracture coordinates. This paper introduces a novel approach based on area interpolation, which identifies disconnected fractures from fracture images without extracting fracture coordinates, significantly improving detection efficiency. This study primarily focuses on nonplanar fractures, aiming to simulate them using the DPDK model accurately. The simulations are compared with those obtained using the Embedded Discrete Fracture Model (EDFM). This work illustrates how nonplanar hydraulic fractures can be effectively simulated in a DPDK model. Our results demonstrate that the adjusted/corrected DPDK model can offer superior or comparable performance to an EDFM for simulating nonplanar fractures. The proposed method is flexible and readily applied in commercial simulation software.

Investigation of influence factors on CO2 flowback characteristics and optimization of flowback parameters during CO2 dry fracturing in tight gas reservoirs

CO2 dry fracturing is a promising alternative method to water fracturing in tight gas reservoirs, especially in water-scarce areas such as the Loess Plateau. The CO2 flowback efficiency is a critical factor that affects the final gas production effect. However, there have been few studies focusing on the flowback characteristics after CO2 dry fracturing. In this study, an extensive core-to-field scale study was conducted to investigate CO2 flowback characteristics and CH4 production behavior. Firstly, to investigate the impact of core properties and production conditions on CO2 flowback, a series of laboratory experiments at the core scale were conducted. Then, the key factors affecting the flowback were analyzed using the grey correlation method based on field data. Finally, taking the construction parameters of Well S60 as an example, a dual-permeability model was used to characterize the different seepage fields in the matrix and fracture for tight gas reservoirs. The production parameters after CO2 dry fracturing were then optimized. Experimental results demonstrate that CO2 dry fracturing is more effective than slickwater fracturing, with a 9.2% increase in CH4 recovery. The increase in core permeability plays a positive role in improving CH4 production and CO2 flowback. The soaking process is mainly affected by CO2 diffusion, and the soaking time should be controlled within 12 h. Increasing the flowback pressure gradient results in a significant increase in both CH4 recovery and CO2 flowback efficiency. While, an increase in CO2 injection is not conducive to CH4 production and CO2 flowback. Based on the experimental and field data, the important factors affecting flowback and production were comprehensively and effectively discussed. The results show that permeability is the most important factor, followed by porosity and effective thickness. Considering flowback efficiency and the influence of proppant reflux, the injection volume should be the minimum volume that meets the requirements for generating fractures. The soaking time should be short which is 1 day in this study, and the optimal bottom hole flowback pressure should be set at 10 MPa. This study aims to improve the understanding of CO2 dry fracturing in tight gas reservoirs and provide valuable insights for optimizing the process parameters.

Experimental Determination of Poroperm Properties of Fractured Porous Geomaterials within the Framework of Dual-Permeability Model

Experimental Determination of Poroperm Properties of Fractured Porous Geomaterials within the Framework of Dual-Permeability Model

Improved dual-permeability model for characterizing the mass transfer process inside matrix blocks

Improved dual-permeability model for characterizing the mass transfer process inside matrix blocks

Improved dual-permeability model for characterizing the mass transfer process inside matrix blocks

Improved dual-permeability model for characterizing the mass transfer process inside matrix blocks

A discrete unified gas kinetic scheme for simulating transient hydrodynamics in porous media with fractures

Tight gas reservoirs have typical characteristics of well-developed natural fractures, extremely low permeability, and low porosity. The flow in such media can be described by a dual-porosity dual-permeability (DPDP) model with the consideration of gas slippage and real gas effects. Based on this model, in this study, a discrete unified gas kinetic scheme is developed to describe the transient hydrodynamic behaviors in porous media with fractures. With an interporosity term, two kinetic equations are employed to capture the pressure propagation in matrix and fracture sub-systems, respectively. The proposed DUGKS can correctly recover the DPDP model through the Chapman–Enskog analysis. Unlike the traditional numerical methods, the velocity in DUGKS can be calculated locally by the non-equilibrium distribution functions. The presented method is verified by three typical problems, including the flow in a fractured porous medium, the flow around a vertical production well, and the flow around a fractured horizontal production well. The numerical results are in good agreement with the reference data. In the test, the global relative errors in pressures are on the order of 10−3. Moreover, the transient hydrodynamics in porous media with fractures are evaluated. The simulation results show that the slippage mainly occurs in the matrix, and this effect may result in a 20% increase in permeability. With the consideration of slippage and real gas effects, the predicted production is higher than that predicted by Darcy’s law. In addition, the results indicate that hydraulic fractures have a great impact on production.

Modelling preferential flow induced by dynamic changes of desiccation cracks: A comparative numerical study

Quantitative investigation on the preferential flow induced by desiccation cracks (PF-DC) remains a great challenge due to the soil shrinking-swelling behavior. This work presents a series of comparative numerical studies to investigate the accuracy and substitutability of different models in simulating the water flux, hydrological response and crack evolution induced by PF-DC. As a comparative study, an effective dynamic dual-permeability model (DDPM) we recently developed and validated was regarded as a benchmark model. Three numerical experiments were conducted to (i) compare the difference among the single-domain model (SDM), rigid dual-permeability model (RDPM) and DDPM; (ii) test the sensitivity of the DDPM to the shrinking-swelling parameters; (iii) test the rationality of a “lighter” dynamic DPM (LDPM) only considering the proportion changes of each domain while neglecting the variation of hydraulic properties. The results showed that compared to the DDPM, the SDM overestimated the water content under low-rainfall intensity while underestimating the water content under high-intensity rainfall and failed to capture the early increase of water content in deep soils induced by PF-DC. The RDPM greatly overestimated the total water content and water storage capacity of the crack domain, which was not suggested to be used in the surface runoff or flood forecast. The DDPM is overall not sensitive to the shrinking-swelling parameters, indicative of relatively loose accuracy requirements in measuring the soil shrinking-swelling parameters. The LDPM can be a tentative alternative option for the DDPM, but it is better not to use it to evaluate the surface runoff or use it under long-term extreme drought. In conclusion, the prediction errors without considering crack evolution and variation of hydraulic properties of each domain (RDPM) are the highest, then followed by the only considering crack evolution (LDPM) and uncertainties of shrinking-swelling parameters.

Lattice Boltzmann method for solute transport in dual-permeability media

Dual-permeability models are currently under active investigation for predicting the flow and transport of pollutant concentration in porous media. The basic idea of these models is usually to separate the medium into two distinct flow regions with separate hydraulic and solute movement properties. Most of the dual-permeability approaches presented to date assume the reaction terms to be independent of space. For local reaction processes in soils, however, the depth effects are important and should be incorporated into the dual-permeability models. To reveal the transport phenomenon in such case, the best way is to obtain an exact solution with a suitable analytical approach, but it may be hard or even impossible for this general scenario. As such, this paper seeks an alternative method, and propose a lattice Boltzmann method for solute transport in dual-permeability media. The Chapman–Enskog analysis shows that the present model can recover the governing equations correctly. The capability and accuracy of this model is first verified by two problems: the non-reactive mass transfer in dual-permeability porous media, and the solute transport in a depth-dependent soil. With this model, we further studied the contaminant transport in dual-permeability soil with depth-dependent reaction rates. The numerical results show that when the exchange coefficient is relatively smaller, there are usually two peaks for the breakthrough curves (BTCs), whereas it degenerates to a single peak as the exchange coefficient increases. In addition, we note that the distributions of the concentration in different domains are nearly the same for a larger exchange coefficient. As for the pore water velocity, it is found that when the difference in the pore water velocity in the two domains is significant, the BTC exhibits a bimodal distribution. However, there is only one peak for the BTCs when the above difference is insignificant. Further, as compared with the constant-reaction rate cases, we observe that the BTCs obtained for the media with depth-dependent rates lie in the intermediate zone defined by the above two extremes. Finally, we adopt the current approach to simulate the solute transport in an Andisol and observe that the difference between the numerical and experimental results is insignificant, indicating our approach is capable in modeling solute transport in porous media.

Effects of dynamic changes of desiccation cracks on preferential flow: experimental investigation and numerical modeling

Abstract. Preferential flow induced by desiccation cracks (PF-DC) has been proven to be an important hydrological effect that could cause various geotechnical engineering and ecological environment problems. Investigation on the PF-DC remains a great challenge due to the soil shrinking–swelling behavior. This work presents an experimental and numerical study of the PF-DC considering the dynamic changes of desiccation cracks. A soil column test was conducted under wetting–drying cycles to investigate the dynamic changes of desiccation cracks and their hydrological response. The ratios between the crack area and soil matrix area (crack ratio), crack aperture and depth were measured. The soil water content, matrix suction and water drainage were monitored. A new dynamic dual-permeability preferential flow model (DPMDy) was developed, which includes physically consistent functions in describing the variation of both porosity and hydraulic conductivity in crack and matrix domains. Its performance was compared to the single-domain model (SDM) and rigid dual-permeability model (DPM) with fixed crack ratio and hydraulic conductivity. The experimental results showed that the maximum crack ratio and aperture decreased when the evaporation intensity was excessively raised. The self-closure phenomenon of cracks and increased surficial water content was observed during low-evaporation periods. The simulation results showed that the matrix evaporation modeled by the DPMDy is lower than that of the SDM and DPM, but its crack evaporation is the highest. Compared to the DPM, the DPMDy simulated a faster pressure head building-up process in the crack domain and higher water exchange rates from the crack to the matrix domain during rainfall. Using a fixed crack ratio in the DPM, whether it is the maximum or the average value from the experiment data, will overestimate the infiltration fluxes of PF-DC but underestimate its contribution to the matrix domain. In conclusion, the DPMDy better described the underlying physics involving crack evolution and hydrological response with respect to the SDM and DPM. Further improvement of the DPMDy should focus on the hysteresis effect of the soil water retention curve and soil deformation during wetting–drying cycles.

Investigating the Behavior of Permeable and Impermeable Reservoirs in Southern of Iraq

The effect of hydraulic fracturing on the permeability and fluid flow of various Iraqi oil storage cores has been studied. Rumaila, Majnoon, and Zubair fields with different permeability were included in this study. Experiments were performed to determine the breaking pressure of the permeable core. Therefore, numerical and experimental results were compared to test the constant pressure on the impermeable core. Finite Volume Method (EbFVM) corresponding to the Dual Porosity Dual Permeability Model (DPDP) was used. A fractured reservoir in the Iraqi fields was studied for its single-phase fluid flow behavior. To represent the pressure distributions, ANSYS-CFX program was used. The comparisons between the fractured and non-fractured cores has been presented. In this paper, the pressure for permeable cores of Rumaila field has been determined and verified during the experimental and numerical simulation due to its lower fracture pressure. Hence, the required pressure has been determined for impermeable cores of Majnoon and Zubair fields due to the difficulties to measure such high pressure. The results show that the expected pressure to make a flow for the core belongs to the Majnoon field reaches to 1.724×107 Pa (2500 psi), while the expected pressure for the fluid to flow into the core belongs to the Zubair field reaches 1.379×108 Pa (20000 psi).

Re-Fracturing vs. CO2 Huff-n-Puff Injection in a Tight Shale Reservoir for Enhancing Gas Production

Field production data indicate that the shale gas production rate decreases sharply after a few years of the first fracking. Feasible enhanced gas recovery (EGR) approaches are very necessary to be investigated. In this study, we compared re-fracturing with a huff-n-puff gas injection scheme in a shale gas reservoir for EGR. A fully compositional simulation approach coupled with a dual porosity and dual permeability model is used. The gas production performances by using different fracturing fluids (i.e., slickwater and supercritical CO2) are evaluated. The effects of huff-n-puff parameters and matrix permeability on the gas production rate and carbon sequestration are investigated. The results show that using a re-fracturing approach yields a better recovery performance than the huff-n-puff gas injection method. Re-fracturing using supercritical CO2 performs better than using slickwater because the former can create complex three-dimensional fracture networks. Huff-n-puff CO2 injection can enhance the gas recovery effectively in ultra-tight formations. In a relatively high permeable formation, viscous flow instead of adsorption-desorption isotherms becomes the primary mass transfer mechanisms, resulting in a lower gas recovery. Both the re-fracturing treatment and huff-n-puff CO2 injection are profitable from a long-term cash flowback perspective.