Dual Permeability Research Articles

Performance of preferential flow models in predicting infiltration through a remolded soil with artificial macropores

AbstractPreferential flow in soils contributes to water and contaminant leaching to groundwater and subsurface drains. At practical scales, preferential flow is often neglected due to the lack of consensus or guidance on how to simulate this process. Dual‐permeability (DP) approaches are a standard, but their applicability in practice is limited by the large number of parameters involved. The source‐responsive (SR) model simulates preferential flow as flow films along the walls of macropores that interact with the soil matrix. The objective of this study was to evaluate the ability of the SR model and a DP model with calibration limited to macropore parameters to simulate hydrologic variables of interest for practical applications. Infiltration experiments were conducted in a 150‐cm‐long by 50‐cm‐wide by 40‐cm‐deep soil column with vertical artificial macropores, with preferential flow being the most prevalent flow process. Two macropore configurations and various rainfall rates were tested. The DP model provided relatively accurate predictions of the bottom drainage rates, but inaccurate soil parameter estimates resulted in poor predictions of matrix flow. Critical limitations in the SR model formulation were highlighted, and the model was revised. The refined SR model provided accurate predictions of bottom drainage rates and water contents under steady‐state rainfall. The DP model with a reduced calibration appeared valid to estimate subsurface fluxes with negligible matrix flow. The SR model applicability is limited to steady‐state scenarios with negligible matrix flow. Critical developments are needed for the SR model to be applicable in practice.

Thermal simulation of shale gas recovery involving the use of microwave heating

Recent technological advancement in drilling for shale gas such as hydraulic fracturing, has meant that more gas can be recovered from the ultra-tight matrix of the shale formation. However, significant quantities of adsorbed gas are still left unproduced even with this breakthrough in accessing gas previously unattainable due to the low permeability of shale. In this paper, a coupled electromagnetic –thermal model has been developed to investigate the production of adsorbed gas from shale gas reservoirs using microwave heating. A dual porosity –dual permeability model is developed for the system of shale gas with account of both viscous and Knudsen diffusion in the matrix. Results from simulation indicated that microwave heating can improve cumulative production by 25% in a period of one year by accelerating desorption of the adsorbed gas. Further results also indicated higher penetration depth for microwave frequency of 915 MHz. This study provides useful insights into microwave assisted shale gas recovery.

Extension of the Gardner exponential equation to represent the hydraulic conductivity curve

Abstract The relative hydraulic conductivity curve K r (h) = K/K s is a key variable in soil modeling. This study proposes a model to represent K r (h), the so-called Gardner dual (GD) model, which extends the classical Gardner exponential model to h values greater than h o, the suction value at the inflection point of the K r (h) curve in the log-log scale. The goodness of fit of GD using experimental data from UNSODA was compared to that of the MVG [two-parameter (K ro , L) Mualem-van Genuchten] model and a corresponding modified MVG model (MVGm). In 77 soils without evidence of macropore flow, GD reduced the RMSE errors by 64% (0.525 to 0.191) and 29% (0.269 to 0.193) in relation to MVG and MVGm, respectively. In the remaining 76 soils, GD generally was less accurate than MVG and MVGm, since most of these soils presented evidence of macropore flow (dual permeability). GD has three parameters and two degrees of freedom, like MVG. Two of them allow the calculation of the macroscopic capillary length, a parameter from the infiltration literature. The three parameters are highly dependent on the K r (h) data measurement in a short wet suction range around h o, which is an experimental advantage.

Analysis of the Saltwater Wedge in a Coastal Karst Aquifer with a Double Conduit Network, Numerical Simulations and Sensitivity Analysis

We investigate the long-distance salinity in a dual permeability coastal karst aquifer with a double conduit network using a three-dimensional variable-density groundwater flow and multispecies transport SEAWAT model. Sensitivity analyses were used to evaluate the impact of the parameters and boundary conditions on the modeling saltwater wedge in a karstic aquifer situated in the Cuban land territory, including hydraulic conductivity, vertical anisotropy and salinity concentration; both in the conduits network and the fractured medium. These analyses indicated that hydraulic conductivity of the fractured medium and salt concentration were the ones that have a stronger effect on saltwater intrusion in a karstic aquifer. We also show results of the three-dimensional numerical simulations on groundwater salinity for different scenarios with the variabilities of the important parameters and compare results with electric conductivity profiles measured in a well.

Natural fractures within Knox reservoirs in the Appalachian Basin: characterization and impact on poroelastic response of injection

AbstractUnderstanding the distribution and orientation of natural fractures within Knox Groups is of significance in seeking potential CO2 storage zones with high practical storage capacity. Over 700 observations of natural fractures were interpreted on acquired resistivity and acoustic image logs collected at multiple well locations ranging in depth from 730 to 3900 m in the Knox Group interval on the western flank of Appalachian Basin. We evaluated the structural parameters of the fractures using statistical analysis. Natural fracture intensity was observed to increase up‐dip within the studied area. The present day maximum horizontal stress direction was derived using the interpretation of wellbore breakouts and drilling‐induced tensile fractures in image logs. Overall, a high percentage of fractures with varying dip directions were observed to strike subparallel to the contemporary maximum horizontal stress direction. Multiphase flow–geomechanics coupled numerical simulations and poromechanics analytical solutions were then used to study pressure and stress response of CO2 injection into the fractured Knox reservoirs. In addition, we applied a dual permeability model combined with a fracture activation model to study the permeability enhancement and its effect on injection mass increase. We also showed the line source injection solution can reasonably predict stress changes of CO2 injection into the deep saline formations. Results were analyzed to understand the potential effect of natural fractures in sandstone formations and fractured layers in thick carbonate formations on CO2‐injected mass, time‐dependent stress evolution, and the ratio of stress to pore pressure changes. © 2019 Society of Chemical Industry and John Wiley & Sons, Ltd.

Pore-scale study of counter-current imbibition in strongly water-wet fractured porous media using lattice Boltzmann method

Oil recovery from naturally fractured reservoirs with low permeability rock remains a challenge. To provide a better understanding of spontaneous imbibition, a key oil recovery mechanism in the fractured reservoir rocks, a pore-scale computational study of the water imbibition into an artificially generated dual-permeability porous matrix with a fracture attached on top is conducted using a recently improved lattice Boltzmann color-gradient model. Several factors affecting the dynamic countercurrent imbibition processes and the resulting oil recovery have been analyzed, including the water injection velocity, the geometry configuration of the dual permeability zones, interfacial tension, the viscosity ratio of water to oil phases, and fracture spacing if there are multiple fractures. Depending on the water injection velocity and interfacial tension, three different imbibition regimes have been identified: the squeezing regime, the jetting regime, and the dripping regime, each with a distinctively different expelled oil morphology in the fracture. The geometry configuration of the high and low permeability zones affects the amount of oil that can be recovered by the countercurrent imbibition in a fracture-matrix system through transition of the different regimes. In the squeezing regime, which occurs at low water injection velocity, the build-up squeezing pressure upstream in the fracture enables more water to imbibe into the permeability zone closer to the fracture inlet thus increasing the oil recovery factor. A larger interfacial tension or a lower water-to-oil viscosity ratio is favorable for enhancing oil recovery, and new insights into the effect of the viscosity ratio are provided. Introducing an extra parallel fracture can effectively increase the oil recovery factor, and there is an optimal fracture spacing between the two adjacent horizontal fractures to maximize the oil recovery. These findings can aid the optimal design of water-injecting oil extraction in fractured rocks in reservoirs such as oil shale.

Modeling the relationship of aeration, oxygen transfer and treatment performance in aerated horizontal flow treatment wetlands

Mechanical aeration is commonly used to improve the overall treatment efficacy of constructed wetlands. However, the quantitative relationships of air flow rate (AFR), water temperature, field oxygen transfer and treatment performance have not been analyzed in detail until today. In this study, a reactive transport model based on dual–permeability flow and biokinetic formulations of the Constructed Wetland Model No. 1 (CWM1) was developed and extented to 1) simulate oxygen transfer and treatment performance for organic carbon and nitrogen of two pilot–scale horizontal flow (HF) aerated wetlands (Test and Control) treating domestic sewage, and, 2) to investigate the dependence of oxygen transfer and treatment performance on AFR and water temperature. Both pilot–scale wetlands exhibited preferential flow patters and high treatment performance for chemical oxygen demand (COD) and NH4–N at AFRs of 128–700 L m−2 h−1. A reduction of the AFR in the Test system from 128 to 72 L h−1 m−2 substantially inhibited NH4–N removal. Conservative tracer transport as well as reactive transport of dissolved oxygen (DO), soluble and total chemical oxygen demand (CODs, CODt), NH4–N and NOx–N measured in pilot–scale experiments were simulated with acceptable accuracy (E1¯=0.39±0.26). An equation to estimate the volumetric oxygen transfer coefficient was found to be: kLa,20=0.511ln(AFR). Simulated treatment performance depended on kLa,20 in a non–linear manner. A local sensitivity analysis of the calibrated parameters revealed porosity, hydraulic permeability and dispersion length of the fast flow field as well as kLa,20 as most important. An optimal AFR for a spatially and temporally continuous aeration pattern for treatment wetlands treating similar influent was estimated to 150–200 L h−1 m−2. This study provides insights into aeration mechanisms of aerated treatment wetlands and highlights the benefits of process modeling for in–depth system analysis.

Viability of carbonated water injection (CWI) as a means of secondary oil recovery in heavy oil systems in presence and absence of wormholes: Microfluidic experiments

In this study, the performance of carbonated water injection (CWI) as a means of secondary oil recovery process was investigated. A series of flooding experiments were carefully designed and conducted in two state-of-the-art micromodels representing single and dual permeability porous media. The dual permeability micromodel is referring to a model with 17 high permeability channels mainly to mimic wormholes generated in unconsolidated sandstone reservoirs during sand production. Prior to CWI tests, waterflooding (WF) tests were carried out in both single and dual permeability micromodels saturated with two heavy crude oils (Type-I, °API = 20.44 and Type-II, °API = 15.49) to investigate the displacement performance of conventional and well known waterflooding technique. Next, through a series of flooding experiments performed at constant injection rate of qinj = 0.05 cm3/min and temperature of Texp = 21 °C, the effect of oil °API gravity on efficiency of CWI was examined. Results obtained for Type-I crude oil from a single permeability micromodel showed that the ultimate oil recovery of CWI can be increased by about 9% as compared to that of conventional WF. Furthermore, the analysis of the images taken during the displacement process of CWI showed wider distribution of frontal advancement compared to that of conventional WF when conducted in the same heavy oil saturated micromodel. It was also observed that for Type-II crude oil (°API = 15.49), the recovery factor was improved by 2.2% under the same conditions with that of conventional WF when performed in a single permeability micromodel. Therefore, the comparative evaluation of the performance of CWI conducted in two heavy oil systems to a single permeability micromodel showed 4.8% of improvement per one degree increase in oil °API gravity under the conditions of this study. Similarly, a series of experiments were conducted with both heavy oil samples in a dual-permeability micromodel where 17 high permeability channels representing dilated regions (or wormholes) were included in the model. The carbonated water injection implemented in the dual permeability micromodel saturated with heavy oil Type-II (°API = 15.49) resulted in 23.5% improvements in the recovery factor over single permeability case at nearly 1.6 PVs of injection at aforementioned experimental conditions and operations. Results of this study showed that CWI is a viable option for enhanced oil recovery in heavy oil reservoirs. Additionally, CWI has additional benefits through CO2 storage and carbon tax credits, though less than immiscible and miscible CO2 injection processes. Therefore, it is crucial to consider this relatively easier to implement alternate option prior to other costly enhanced oil recovery (EOR) methods.

Inflow performance relationship of vertical wells in fractured vuggy media during semi-steady state flow regime

The inflow performance relationship (IPR) is one of the essential key parameters that control the fluids production/injection rate from wells. The presence of the vugs in addition to fractures in carbonate reservoirs introduce many difficulties related the estimation of IPR of future wells. In this study, a novel analytical IPR of dual-permeability, triple porosity model is derived for the first time. The introduced IPR formula is derived for the standard scenario model of a vertical and fully penetrating well in a circular reservoir under single-phase flow of slightly compressible fluid. The three governing flow equations (matrix flow equation, fracture flow equation and interaction between vugs and other two continuum equation) are solved simultaneously as a system of differential equations for semi-steady state (SSS) flow regime. The generated SSS IPR is the same as Darcy's straight line IPR multiplied by an error parameter (E23) which is bounded between zero and one. A detailed investigation of the effect of the reservoir petro-physical parameters like storativities, inter-porosities and fracture to matrix permeability ratio are presented. The newly presented IPR of dual-permeability, triple porosity system can be reduced to sub-models IPRs by further modification of error parameter to fit sub-model as single permeability, triple porosity (E13) or dual permeability, dual porosity (E22). The presented IPR formula has the advantage of dividing the pressure drop of the fluid flow to two components, one for the internal resistance between different continuums (which is resented by E) and the other one is the radial flow in the same continuum toward/from well-bore. The generated IPR model is double verified using both cell pressure centred finite volume numerical simulation and conventional pressure transient analysis.

Integrated discrete fracture and dual porosity - Dual permeability models for fluid flow in deformable fractured media

Aiming at accuracy and computational efficiency, integrating discrete fracture and dual porosity-dual permeability models is a viable alternative to simulate flow in naturally fractured reservoirs with discontinuities of multiple lengths. However, previous works focus on the hydraulic problem only and do not take into account geomechanical effects. This study proposes a hydro-mechanical model using the finite element method (FEM) to represent the behavior of fracture networks with fractures of large, medium and small lengths. The methodology integrates the discrete fracture model (DFM) using interface elements, and the dual porosity/dual permeability (DPDP) model. Some synthetic applications compare the results of the models. A case study integrating both approaches is also performed. The results show that fractures of small and medium length enhance the permeability of naturally fractured reservoirs. Their presence within the porous medium results in greater fluid drainage and faster rate of pore pressure dissipation. The fractures contributed significantly to the mechanical behavior with impact on the stiffness of the rock mass system. Aperture variation of the fracture network influences fracture permeability and shows the stress shadowing effect. The results support the application of the proposed large-medium-small length fracture model to represent enhanced permeability of naturally fractured media.

Experimental and Numerical Investigations of Influence on Overland Flow and Water Infiltration by Fracture Networks in Soil

Preferential flow is common in clay or expansive clay soils, involving water bypassing a large portion of the soil matrix. Dye tracer experiment and numerical modeling are used to simulate the surface runoff and subsurface preferential flow patterns influenced by the soil fracture network of a relatively steep hillslope system (slope angle equals to 10 degrees). The result of the experiments indicates that part of the water is infiltrated through cracks, leading to the delay of the initial runoff-yielding time and reduction of the discharge of the surface runoff. The soil water flow is mainly in the matrix when the intensity of precipitation is low. With the increasing of precipitation, soil water movement may become in the form of preferential flow through cracks. In addition, the nonuniformity of soil water infiltration and the depth of the average water infiltration increase as the precipitation intensity increases. To this end, the complete coupling model was established by using the surface-matrix-crack (SMC) model to simulate water flow within discrete fracture as well as to simulate water flow in the soil matrix based on the concept of dual permeability using the traditional Richards’ equation. In this model, the “cubic law” of fluid motion in cracks within smooth parallel plates and the two-dimensional diffusion wave approximation to Saint-Venant equations with momentum term ignored (two-dimensional shallow water equations) were used. The model divides soil water infiltration into two forms and uses the overall method to calculate the exchange of water between the crack networks and matrix regions as well as the exchange water between surface runoff and infiltration water. Results indicate that the SMC model has better performance compared with the traditional equivalent continuum model when those models are used to simulate the surface runoff movement and the soil water movement in the presence of cracks.

Lessons learned from IOR pilots in Bakken formation by using numerical simulation

Bakken is the most productive formation among unconventional plays in North America. This formation has about 7.4 billion barrels of recoverable oil. However, the primary oil recovery is still low as 5–10%. Miscible natural gas and carbon dioxide (CO2) might be the most two potential strategies to improve oil recovery in such a complex play. In this study, some of the IOR pilots which have been conducted in Montana, North Dakota, and South Saskatchewan have been presented. The performance results of these pilots in US-Bakken versus Canadian-Bakken have been compared. Moreover, the reasons behind the successful IOR pilots in Canadian-Bakken versus US-Bakken have been discussed. Then, numerical simulation models have been constructed to mimic the results of some pilots. Two different compositional models have been built for oils of two different formations. Furthermore, two different models, single porosity model and dual permeability model have been created to match the performance of some pilots. Implementation of molecular diffusion mechanism has been conducted in both of single porosity and dual permeability model. Finally, the continuous miscible gases injection versus huff-n-puff protocols have been compared and investigated.The results showed that the performance of natural gases generally over-performed the CO2 injection technique's in Bakken formation. Although the diffusion flow is dominant in these types of reservoirs, the diffusivity of the injected CO2 into formation oil is slow due to the fact that CO2 has large molecules as compared with the small pore throats of these porous media. Accordingly, miscible CO2-EOR might not be beneficial in huff-n-puff operations as in continuous flooding process. However, the success of natural gases based EOR does not have that strong functionality of molar diffusivity. Therefore, their performance was much better than CO2 performance in the field scale of these tight formations. Furthermore, the numerical simulation of this study concluded that the spacing between the production wells and injection wells should be minimized, for the continuous flooding process of miscible-gases EOR, to enhance their performance. Although the permeability of Canadian-Bakken has a permeability of 1–2 order higher than the permeability of US-Bakken, the pilots' spacing between injectors and producers in Canadian Bakken is interestingly much shorter than that for US-Bakken, which might be the reason behind the EOR success in Canadian Bakken. Finally, the activatiown process of the highly intensive natural fractures might be the key to enhance the diffusivity of CO2-EOR. Otherwise, natural gases are highly recommended to be the most potential EOR in these types of reservoirs. This study explains how the diffusion mechanism affects the performance of different miscible gases to improve oil recovery in these plays since they are more complex and very different from conventional formations. Also, it suggests that CO2 flooding process would be a good practice to overcome the limitations of CO2-diffusion rate in these reservoirs if the conformance problems are wisely controlled.

Rate-Transient Analysis in Multifractured Horizontal Wells of Tight Oil Reservoir

SummaryMultifractured horizontal wells (MFHWs) have become the most commonly used technology for developing unconventional oil and gas reservoirs. Because unconventional reservoirs are currently the focus of exploration and exploitation around the world, a growing number of researchers and scholars are concentrating on production-performance evaluation of unconventional MFHWs to obtain the stimulated reservoir volume (SRV) or hydraulic-fracture properties, which are usually obtained from expensive reservoir tests or production logs. Rate-transient-analysis (RTA) techniques that use continuous-production and flowing-pressure data have proved to be convenient and applicable approaches to estimate the reservoir parameters and hydraulic-fracture properties. Although many cases or work flows of RTA have been previously studied, most of those works were performed for shale-gas or conventional reservoirs. Few studies on RTA have been conducted for MFHWs completed in tight oil reservoirs, particularly for actual field cases in which the usually scattered production data significantly increase the difficulty in analyzing the production performance.In this research, the authors focus on using convenient and economical methods (RTA techniques) to obtain the SRV parameters and hydraulic-fracture properties that characterize the fracturing-treatment effectiveness of an actual MFHW in a tight oil reservoir, which many engineers and technical personnel expect to achieve. A comprehensive work flow [including production-data filtering, flow-regime diagnosis, straight-line analysis, type-curve matching (TCM), analytical-model analysis (AMA), numerical-model analysis (NMA), and uncertainty and nonuniqueness analysis] has been developed to perform a production-performance analysis of an MFHW completed in a tight oil reservoir. In particular, two approaches for calculating the permeability of SRV (kSRV) and effective half-length of hydraulic fracture (Xf) have been introduced. Moreover, the dual permeability parameters, the storativity ratio, and the interporosity coefficient (ω and λ, respectively), have been derived to enter into the AMA model to improve the accuracy of history matching. With the combination of AMA and NMA, the estimated ultimate recovery (EUR) of an actual MFHW completed in a tight oil reservoir can be predicted. Considering the uncertainty and nonuniqueness of the original reservoir parameters or nature of the adopted methods, a probabilistic analysis using Monte Carlo simulation has been performed to address the uncertainty of the analysis results. In addition, a simplified application of the developed method has been introduced. To demonstrate the feasibility and practicability of the developed work flow, two field cases from an actual tight oil reservoir have been analyzed. The consistent analysis results for field cases validate the developed work flow and proposed methods.

Modified Extended Finite Element Methods for Gas Flow in Fractured Reservoirs: A Pseudo-Pressure Approach

Fluid flow in fractured porous media has always been important in different engineering applications especially in hydrology and reservoir engineering. However, by the onset of the hydraulic fracturing revolution, massive fracturing jobs have been implemented in unconventional hydrocarbon resources such as tight gas and shale gas reservoirs that make understanding fluid flow in fractured media more significant. Considering ultralow permeability of these reservoirs, induced complex fracture networks play a significant role in economic production of these resources. Hence, having a robust and fast numerical technique to evaluate flow through complex fracture networks can play a crucial role in the progress of inversion methods to determine fracture geometries in the subsurface. Current methods for tight gas flow in fractured reservoirs, despite their advantages, still have several shortcomings that make their application for real field problems limited. For instance, the dual permeability theory assumes an ideal uniform orthogonal distribution of fractures, which is quite different from field observation; on the other hand, numerical methods like discrete fracture network (DFN) models can portray the irregular distribution of fractures, but requires massive mesh refinements to have the fractures aligned with the grid/element edges, which can greatly increase the computational cost and simulation time. This paper combines the extended finite element methods (XFEM) and the gas pseudo-pressure to simulate gas flow in fractured tight gas reservoirs by incorporating the strong-discontinuity enrichment scheme to capture the weak-discontinuity feature induced by highly permeable fractures. Utilizing pseudo-pressure formulations simplifies the governing equations and reduces the nonlinearity of the problem significantly. This technique can consider multiple fracture sets and their intersection to mimic real fracture networks on a plain structured mesh. Here, we utilize the unified Hagen–Poiseuille-type equation to compute the permeability of tight gas, and finally adopt Newton–Raphson iteration method to solve the highly nonlinear equations. Numerical results illustrate that XFEM is considerably effective in fast calculation of gas flow in fractured porous media.

General hydro-geological impact of cleats on underground coal gasification

Potential aquifer contamination has been a huge environmental concern for the implementation of underground coal gasification (UCG) as coal seams are frequently overlaid by an aquifer. To explore the general impact of cleats on the mass transfer problems in UCG, particularly in the vertical direction, a dual-permeability (DP) cleat model was integrated into a 3-D numerical model which is dimensionally extensive to account for the hydrostatic effect of an aquifer. It was found that cleats favour UCG production, and the prime operational parameter, i.e., the injection pressure, plays a dominant role in governing vertical mass transport in UCG. Syngas production retains some constancy with variable geological settings unless a surge in the injection pressure occurs. Higher pressure injection generates higher peak rates but delayed production. At near-hydrostatic injection, gas species attain a weak presence in the overburden contrary to expectations based on key geological parameters. However, gas saturation in the cap rock increases appreciably under above-hydrostatic injection. The role of higher injection pressure becomes so overwhelming that variations or heterogeneity in geological parameters produce little difference in the transfer problems.

Role of molecular diffusion in heterogeneous, naturally fractured shale reservoirs during CO2 huff-n-puff

Shale reservoirs are characterized by high degree of heterogeneity and ultra-low matrix permeability. Natural fracture (both macro and micro) systems are important to increase the performance of shale reservoirs by providing flow path for the hydrocarbon from the nanopores in the matrix to the wellbore. Configurations of natural fractures also have significant implications for the recovery performance of shale gas and oil reservoirs. CO2 huff-n-puff or cyclic injection has been suggested to be a feasible way to recover oil from shales and the flow process is complex. Molecular diffusion is an important transport mechanism of the mixture of CO2 and oil, especially in tight formations. Based on these knowledge, various configurations of the natural fracture system in shale reservoirs with the dual porosity and dual permeability model were constructed, regarding Dykstra-Parsons (DP) coefficient and correlation length. Dykstra-Parson (DP) coefficient ranges from 0.40 to 0.78, and correlation length ranges from 50 ft to 3000 ft. Based on the geological setting of the Middle Bakken formation and the Bakken live oil PVT data, compositional models were performed to simulate the CO2 huff-n-puff process. CO2 injection begins after the primary recovery factor reaches 3% and both multiple-cycle and single-cycle of injection were investigated regarding the oil recovery performance and CO2 injectivity behavior. In the multiple-cycle scheme the period of one cycle is short; the injection, soak and production time are 10 days, 10 days and 100 days, respectively. In the single-cycle scheme, the period of one cycle is long, and gas injection volume is set to be constant with the soak time of 100 days. The impact of molecular diffusion during the huff-n-puff process is compared in different simulation scenarios. Findings in this work reveal the importance of the configuration of the pre-existing natural fracture system for the performance of the huff-n-puff process. Reservoir heterogeneity hampers primary production. However, during the puff production process, the negative impact of heterogeneity is less as the correlation length increases when the molecular diffusion is taken into account. There exists a threshold correlation length value wherein heterogeneity becomes favorable for improved oil recovery instead of hampering oil recovery, after taking into account of the molecular diffusion, which is approximately 1500 ft in this simulation study. The value of correlation length also affects the performance of multiple-cycle and single-cycle huff-n-puff processes differently because CO2 injectivity behavior is different in reservoirs characterized by different DP coefficients and correlation length: there exists a threshold time point when a longer correlation length begins to favor the injectivity, and the threshold time point is delayed for a scenario with a larger DP coefficient.

Efficient development strategies for large ultra-deep structural gas fields in China

Through analyzing the development of large ultra-deep structural gas fields in China, strategies for the efficient development of such gas fields are proposed based on their geological characteristics and production performance. According to matrix properties, fracture development degree and configuration between matrix and fractures, the reservoirs are classified into three types: single porosity single permeability system, dual porosity dual permeability system, and dual porosity single permeability system. These three types of gas reservoirs show remarkable differences in different scales of permeability, the ratio of dynamic reserves to volumetric reserves and water invasion risk. It is pointed out that the key factors affecting development efficiency of these gas fields are determination of production scale and rapid identification of water invasion. Figuring out the characteristics of the gas fields and working out pertinent technical policies are the keys to achieve efficient development. The specific strategies include reinforcing early production appraisal before full scale production by deploying high precision development seismic survey, deploying development appraisal wells in batches and scale production test to get a clear understanding on the structure, reservoir type, distribution pattern of gas and water, and recoverable reserves, controlling production construction pace to ensure enough evaluation time and accurate evaluation results in the early stage, in line with the development program made according to the recoverable reserves, working out proper development strategies, optimizing pattern and proration of wells based on water invasion risk and gas supply capacity of matrix, and reinforcing research and development of key technologies.

Coal permeability maps under the influence of multiple coupled processes

The evolution of coal permeability has been studied exhaustively and a broad array of permeability models developed. These models are normally derived under the assumption of fluid pressure equilibrium between matrix and fractures. Under this assumption, these models define coal permeability as a function of either gas pressure or effective stress. However, experimental observations indicate that coal permeability may change significantly under a constant observed gas pressure or assumed effective stress. The goal of this study is to resolve this contradiction. In this study, we hypothesize that coal permeability is closely related to the expansion of gas-invaded area/volume as a concentration front propagates from the fracture wall into the matrix. When this invaded volume/area is localized around the fracture, the gas-induced swelling reduces the coal permeability. When the area spreads throughout the entire matrix, gas-induced swelling may increase coal permeability. This important mechanism of transition from local (to the fracture) swelling to global (into the matrix medium) swelling is incorporated into an overlapping dual permeability approach. In this approach, the coal is characterized by a well-defined macroscopic model consisting of four overlapping/interpenetrating continua comprising: (1) coal matrix system; (2) coal fracture system; (3) gas flow in the matrix system; and (4) gas flow in the fracture system. These four continua are connected through a full set of cross-coupling relations, including (1) local force balance between the matrix and the fracture; (2) local deformation compatibility between the matrix and the fracture; and (3) mass exchange between the matrix and the fracture. We apply this approach to generate coal permeability maps under the influence of multiple coupled processes. For a particular coal sample, the permeability is bounded by the solutions for the free-swelling case (upper bound) and for the constant volume case (lower bound). The variations of permeability between the upper and lower bounds under a constant gas pressure are determined by the dynamics of matrix-fracture interactions. Current experimental measurements are bounded by these limits depending on the state of equilibrium between matrix and fractures. These model results are verified against experimental observations reported in the literature.

Three-dimensional and two-phase numerical simulation of fractured dry gas reservoirs

A significant percentage of hydrocarbon reservoirs around the world is fractured. Moreover, the major part of gas reservoirs in Iran is also fractured type, so the existence of an in-house software is necessary. In this study, an efficient, user-friendly, and indigenous simulation of a three-dimensional black oil fractured dry gas reservoir has been developed through IMPES method with the two-phase flow of gas and water. The presented simulator, which was written by C++ language and was known as fracture dry gas reservoir simulator, uses the implicit pressure and explicit saturation method for solving the equations. Also, effect of gravity pressure is neglected and effect of the capillary is considered in equations. By this simulator, we can investigate the dry gas reservoirs behavior with fractures. Darcy or non-Darcy fracture and matrix flow, Cartesian, cylindrical, and combination of Cartesian–cylindrical reservoir gridding, single porosity, dual porosity–single permeability, and dual porosity–dual permeability modeling are abilities of this simulator too. Additionally, this simulator is able to make outputs (such as pressure) at any given specific radius and time interval as numerical and/or graphical output in so little run time. Also, this simulator has PVT box and gridding box for doing the calculation of PVT and gridding. PVT box contains new correlations and EOS in comparison with another reservoir simulator. Gridding box makes us be able to simulate fractured dry gas reservoirs and hydraulically fractured well reservoirs too. Finally, the validity of this simulator was verified by comparing the simulation results with the other reservoir simulator (Eclipse) and showed a good compatibility between the developed software and Eclipse results in each time with different conditions such as various gridding conditions, various fluid data conditions and also various well configuration conditions.

Modeling sewage leakage and transport in carbonate aquifer using carbamazepine as an indicator

The Western Mountain Aquifer (Yarkon-Taninim) of Israel is one of the country's major water resources and partially flows through a karst system. During late winter 2013, maintenance actions were performed on a central sewage pipe that caused sewage to leak into the creek located in the study area. Carbamazepine (CBZ) was used as an indicator for the presence of sewage in the groundwater. The research goal was to develop a mathematical model for quantifying flow and contaminant transport processes in the karst/fractured-porous unsaturated zone and groundwater system. The model was used to simulate CBZ transport during and after an observed sewage leakage event. A quasi-3D dual permeability numerical model represents the 'vadose zone – aquifer' system, by a series of 1D vertical flow and transport equations solved in a variably-saturated zone and by 3D-saturated flow and transport equation in groundwater. The results of simulation showed that after the leakage stopped, significant amounts of CBZ were retained in the porous matrix of the unsaturated zone below the creek. Water redistribution and slow recharge during the dry summer season contributed to a continuous supply of CBZ to the groundwater in the vicinity of the creek and hundreds of meters downstream.