Porosity Dual Permeability Research Articles

Poroelastic Dual-Porosity Dual-Permeability Simulation of Pressure Transmission Test on Chemically Active Shale

AbstractThis paper presents the poroelastic dual-porosity dual-permeability analytical solutions simulating the pressure transmission test on chemically active shale, taking into account shale anis...

An efficient two-scale hybrid embedded fracture model for shale gas simulation

Natural and hydraulic fractures existence and state differs on a reservoir-by-reservoir or even on a well-by-well basis leading to the necessity of exploring the flow regimes variations with respect to the diverse fracture-network shapes forged. Conventional Dual-Porosity Dual-Permeability (DPDP) schemes are not adequate to model such complex fracture-network systems. To overcome this difficulty, in this paper, an iterative Hybrid Embedded multiscale (two-scale) Fracture model (HEF) is applied on a derived fit-for-purpose shale gas model. The HEF model involves splitting the fracture computations into two scales: (1) fine-scale solves for the flux exchange parameter within each grid cell; (2) coarse-scale solves for the pressure applied to the domain grid cells using the flux exchange parameter computed at each grid cell from the fine-scale. After that, the D dimensions matrix pressure and the (D-1) lower dimensional fracture pressure are solved as a system to apply the matrix-fracture coupling. HEF model combines the DPDP overlapping continua concept, the DFN lower dimensional fractures concept, the HFN hierarchical fracture concept, and the CCFD model simplicity. As for the fit-for-purpose shale gas model, various fit-for-purpose shale gas models can be derived using any set of selected properties plugged in one of the most popularly used proposed literature models as shown in the appendix. Also, this paper shows that shale extreme low permeability cause flow behavior to be dominated by the structure and magnitude of high permeability fractures.

Integration of Pressure-Transient Data in Modeling Tengiz Field, Kazakhstan—A New Way To Characterize Fractured Reservoirs

Summary A systematic work-flow to integrate pressure-transient data collected from single-well buildup tests in numerical reservoir-simulation models for a fracture/matrix system is presented. The results of its application in a sector model in the southeast region of Tengiz field in Kazakhstan are also discussed. The procedure starts with a selected numerical-simulation model, either a discrete fracture/matrix (DFM) model or a dual-porosity dual-permeability (DPDK) model, and follows with the analysis of a numerically generated buildup test to calculate the fracture spacing and shape factor of the model. Then, following the correlations between pressure-transient-analysis results and the average or representative values of the model-input parameters near the well, which contain the previously obtained fracture spacing and shape factor, the numerical-model parameters are adjusted in each iteration to match the pressure-transient behavior observed in the buildup test including the interporosity flow between matrix and fracture and the radial flow in the total system. Before field application, the numerical-simulation results from both DFM and DPDK models were validated against analytical pressure-transient solutions for a dual-porosity system. The gridding and time-steps were calibrated to reproduce the analytical transient behavior. Finally, the new work-flow was applied to a sector model of Tengiz field in the southeast region focusing on two wells. Following the developed work-flow, a DFM model was constructed, and its fracture and matrix properties were adjusted to honor buildup-test data at both wells and the transient data collected during a pulse test conducted between them. The study results show that the key factors of a DFM model on buildup transient response are the fracture permeability, fracture aperture, and matrix permeability in the well-drainage area, and the dominant parameters on pulse-test response are the fracture permeability and matrix porosity in the influence area between the two wells. Using the correlations quantitatively for each simulation step could reduce the total number of iterations needed to converge to the numerical solution. The modified model also generated flow distribution along the wellbore, consistent with production-logging data at one well. The resulting sector map of pressure change during buildup test indicates the area with well-connected fracture network. Dynamic transient data contain rich information about reservoirs, and the effective integration of dynamic and static data would have a big impact on reservoir management by potentially minimizing the number of wells to be drilled, maximizing the production, and optimizing recovery. The novelty of this study is the quantitative use of the correlations between pressure-transient-analysis results and the representative values of the input parameters in a numerical model to reduce the number of simulation iterations. Its application in Tengiz is also one of the rare examples in which single-well and multiple-well transient data, production logging, and image-log data are all available.

Effective Local-Global Upscaling of Fractured Reservoirs under Discrete Fractured Discretization

The subsurface flow in fractured reservoirs is strongly affected by the distribution of fracture networks. Discrete fracture models, which represent all fractures individually by unstructured grid systems, are thus developed and act as a more accurate way for fractured reservoir simulation. However, it is usually not realistic to directly apply discrete fracture models to simulate field scale models for efficiency reasons. There is a need for upscaling techniques to coarsen the high resolution fracture descriptions to sizes that can be accommodated by reservoir simulators. In this paper, we extended the adaptive local-global upscaling technique to construct a transmissibility-based dual-porosity dual-permeability model from discrete fracture characterizations. An underlying unstructured fine-scale grid is firstly generated as a base grid. A global coarse-scale simulation is performed to provide boundary conditions for local regions and local upscaling procedures are carried out in every local region for transmissibility calculations. Iterations are performed until the consistency between the global and local properties is achieved. The procedure is applied to provide dual-porosity dual-permeability (DPDK) parameters including coarse-scale matrix-matrix, fracture-fracture and matrix-fracture flux transmissibilities. The methodology is applied to several cases. The simulation results demonstrate the accuracy, efficiency and robustness of the proposed method.

Application of a smart mesh generation technique in gas condensate reservoirs: Auto-tune PVT package for property estimation

Accurate knowledge of static and dynamic characteristics of the reservoir plays a key role in precise evaluation of the field performance. Pressure and temperature variations of the reservoir as well as precipitation of complex components like asphaltene during reservoir production change its characteristics including fluid flow and reservoir permeability. This effect is more significant in gas condensate fractured reservoirs; therefore, application of a dynamic mesh for accurate simulation of the reservoir is inevitable. In this paper, a novel technique has been proposed for generating a dynamic mesh in which static and dynamic parameters of a gas condensate fractured reservoir are combined with the capability of updating. Static parameters including permeability distribution and the location of active wells were combined with fluid patterns in the reservoir. This approach led to generating an element size map, and subsequently was applied for unstructured mesh generation. Afterward, this technique was applied in a multi-phase flow compositional simulator. Moreover, an auto-tune PVT package was developed for properties estimation. The priority of this package was freely choosing the number of regression parameters for properties estimation. To evaluate the performance of the developed model, the results for this model were compared with those obtained by uniform grid model. A grouping technique was also developed in the compositional simulator, to optimize the computation algorithm in terms of the CPU time. It was found that the proposed method provides more accurate results for the recovery of gas reservoir compared with the uniform grid model. Moreover, it is faster and computationally less expensive than the fine model. In addition, the proposed model would provide us with a new and different approach for studying the flow and rock physics and simulating fractured reservoirs, which could be an alternative to dual porosity-dual permeability methods.

Understanding Shale Gas Flow Behavior Using Numerical Simulation

Summary Shale gas has changed the energy equation around the world, and its impact has been especially profound in the United States. It is now generally agreed that the fabric of shale systems comprises primarily organic matter, inorganic material, and natural fractures. However, the underlying flow mechanisms through these multiporosity and multipermeability systems are poorly understood. For instance, debate still exists about the predominant transport mechanism (diffusion, convection, and desorption), as well as the flow interactions between organic matter, inorganic matter, and fractures. Furthermore, balancing the computational burden of precisely modeling the gas transport through the pores vs. running full reservoir scale simulation is also contested. To that end, commercial reservoir simulators are developing new shale gas options, but some, for expediency, rely on simplification of existing data structures and/or flow mechanisms. We present here the development of a comprehensive multimechanistic (desorption, diffusion, and convection), multiporosity (organic materials, inorganic materials, and fractures), and multipermeability model that uses experimentally determined shale organic and inorganic material properties to predict shale gas reservoir performance. Our multimechanistic model takes into account gas transport caused by both pressure driven convection and concentration driven diffusion. The model accounts for all the important processes occurring in shale systems, including desorption of multicomponent gas from the organics' surface, multimechanistic organic/inorganic material mass transfer, multimechanistic inorganic material/fracture network mass transfer, and production from a hydraulically fractured wellbore. Our results show that a dual porosity, dual permeability (DPDP) model with Knudsen diffusion is generally adequate to model shale gas reservoir production. Adsorption can make significant contributions to original gas in place, but is not important to gas production because of adsorption equilibrium. By comparing triple porosity, dual permeability; DPDP; and single porosity, single permeability formulations under similar conditions, we show that Knudsen diffusion is a key mechanism and should not be ignored under low matrix pressure (Pematrix) cases, whereas molecular diffusion is negligible in shale dry gas production. We also guide the design of fractures by analyzing flow rate limiting steps. This work provides a basis for long term shale gas production analysis and also helps define value adding laboratory measurements.

NUMERICAL SIMULATION OF A NATURALLY FRACTURED RESERVOIR.

This research is concerned with the development of a numerical model for stratified normally fractured reservoirs. Three dimensional three phase flow black oil simulation model is adopted. The dual porosity-dual permeability model is used. The IMPES (Implicit Pressure Explicit Saturation) method is used to solve the difference equations. The Tertiary trap in K oil field (an Iraqi oil field) was simulated by the numerical model. The trap consists of six layers having different properties. Equally spaced Cartesian grids were used to divide each layer into 1600 cells in the x-y plane with the thickness as the dimension of each grid block in z direction. Applying the two IMPES pressure equations to each grid of the simulated domain resulting in a block seven diagonal coefficient matrix.

A New Methodology for Modelling of Sand Wormholes in Field Scale Thermal Simulation

Abstract Sand wormholes created by the concurrent production of sand and heavy oil are instrumental in improving oil rates and ultimate recovery. The wormholes form high permeability conduits for flow of oil and more sand. The wormholes may extend several hundred metres away from each well and connect with other wells' wormholes. Efforts have been made to predict the wormhole network based on growth of each wormhole's tip. In this paper, we use a fractal geostatistical method to pregenerate the wormhole network. This wormhole network is then incorporated into a full field thermal simulation model. A dual porosity-dual permeability grid is used, one for the reservoir pay and one for the wormhole network. The wormhole grid cells have the same pore volume as the wormholes and a sparse network structure. With this wormhole representation in the simulation model, we were able to match thermal responses of cold production wells from a steam injection pilot due to the wormholes conducting hot fluid from the steam injectors. As a result, this modelling concept for wormholes may be used to investigate post cold production thermal recovery methods as well as for thinner reservoirs not suitable for Steam Assisted Gravity Drainage (SAGD) where the wormholes may act as natural horizontal wells. Introduction Sand production occurs with heavy oil production in unconsolidated sand formations. If sand production is stopped with screens or filters, this often results in near total loss of production from the well. With the use of progressive cavity pumps, sand production can be encouraged, resulting in sand cuts that can be as high as 30 – 40% initially before dropping to about 5%. The production of sand results in open holes, whimsically called wormholes, that stretch far into the formation away from the well. The productivity of the well rises from the average 4 to 5 m3/d to as high as 15 to 20 m3/d as the wormholes form high permeability conduits for flow of oil and more sand. This production process is called Cold Heavy Oil Production with Sand or CHOPS. Many papers have been published on the mechanics of sand wormhole development. Recently, Y. Wang and C. Chen(1) describe a reservoir model coupled with a detailed wormhole propagation model. The model also incorporates slurry transport with three phase fluid flow. This appears to be a single well model. Research work at the Alberta Research Council on modelling cold production was published by Sawatzky et al.(2). They provide a review of cold production technology as well as their modelling efforts in combining a comprehensive sand production with a fluid flow simulator. It would appear that this too was a single well model predicting the development of wormholes from a well using criterion for sand failure at the tip of a wormhole. These two papers also list extensive bibliographies which will not be repeated here. We are, however, more concerned with the effect of a developed network of wormholes on recovery from a reservoir than with trying to predict the growth of each wormhole based on stresses at its tip.