Zhang, Na (Division of Sustainable Development, College of Science and Engineering, Hamad Bin Khalifa University) | Abushaikha, Ahmad Sami (Division of Sustainable Development, College of Science and Engineering, Hamad Bin Khalifa University)
A fully-implict mimetic finite difference method (MFD) for fractured carbonatereservoir simulation is presented. MFD, as a novel discritization, has been applied to many fields due to its local conservativeness and applicability of any shape of polygon. Here we extend it to fractured reservoirs. Our scheme is based on MFD method and discrete fracture model (DFM). This scheme supports general polyhedral meshes, which gives an advantage for reservoir simulation application. The principle of the MFD method and the corresponding numerical formula for discrete fracture model are described in details. In order to assure flux conservation, fully implicit method is employed. We test our method through some examples to show the accuracy and robustness.
Xu, Feng (RIPED / CNODC) | Li, Xianbing (RIPED) | Gong, Yiwen (The Ohio State University) | Lei, Cheng (RIPED) | Li, Xiangling (RIPED) | Yu, Wei (The University of Texas at Austin / Texas A&M University) | Miao, Jijun (The University of Texas at Austin / SimTech LLC) | Ding, Yutao (CNODC)
Natural fractures are commonly observed in the unconventional reservoir. Production history indicates that natural fractures have been playing an important role in the oil and gas development progress by improving the permeability of the reservoir and increasing the well productivity. In addition, inappropriate development strategies result in the unreasonable single well oil rate, early water breakthrough, severe damages to the unconventional reservoir and overwhelming economic losses when the fracture properties and distributions are not well understood before the development. Hence, it is of great importance to propose a powerful and efficient workflow to describe the fracture distribution clearly, including building a 3D fracture model, performing history matching and forecasting productions of the unconventional reservoir. In this study, we present a powerful and practical workflow through using Fracflow software and EDFM (Embedded Discrete Fracture Model) to build the 3D DFN (Discrete Fracture Network) model. The main methodology used to perform the fracture modelling allows rigorously handling of both hydraulic fractures and natural fractures that can be identified in an unconventional reservoir. This modelling allows computing the real geometrical fracture attributes (mainly orientation and density) and the spatial distribution of fractures. Fracture conductivity values will be calibrated through a comparison of the Kh(permeability thickness) from the well test to the Kh model computed from the upscaling of the fracture model. The mentioned model above will be built by means of a stochastic simulation constrained by the results of the static and dynamic fracture characterization. In the reservoir simulation phase, EDFM processor combining commercial reservoir simulators is fully integrated to perform history matching and production performance forecast of the unconventional reservoir. With a new set of formulations used in EDFM, the non-neighboring connections (NNCs) in the EDFM are converted into regular connections in traditional reservoir simulators, and the NNCs factors are linked with gridblock permeabilities. EDFM provides three kinds of NNC pairs, transmissibility factors, and the connections between fractures and wells. With the aid of the EDFM processor, we can obtain the number of additional grids, the properties of fracture grids, and the NNCs as the simulation input. From the proposed workflow, complex dynamic behaviors of natural fractures can be captured. This will further ensure the accuracy of DFMs and the efficiency offered by structured gridding. The practical workflow for the unconventional reservoir from modelling to simulation highlights the model constrained by the results of the static and dynamic fracture characterization, and the high efficiency to model discrete fractures through the revolutionary EDFM processor. Through this workflow, we can perform history matching effectively and simulate complex fractures including hydraulic fractures and naturally fractures. It potentially can be integrated into existing workflow for unconventional reservoirs for sensitivity analysis and production forecasting.
This paper describes the application and testing of innovative dual porosity flow diagnostics to quantitatively rank large ensembles of fractured reservoir models. Flow diagnostics can approximate the dynamic response of multi-million cell models in seconds on standard hardware. The need for new faster screening methods stems from the challenge of making robust forecasts for naturally fractured carbonate reservoirs. First order uncertainties including the distribution and properties of natural fractures, matrix heterogeneity and wettability can all negatively impact on recovery. A robust multi-realisation approach to production forecasting is often rendered impractical due to the time cost for simulating many models.
We have extended existing flow diagnostics techniques to dual porosity systems by accounting for the matrix-fracture exchange. New metrics combine the transfer rate with the advective time of flight in the fractures identifying risk factors for early water breakthrough and providing quantitative measures of dynamic heterogeneity.
We have compared ranking a large ensemble of synthetic fractured reservoir models using dual porosity flow diagnostics and using full-physics simulation. The synthetic ensemble explores a number of different geological concepts around the fracture distributions, wettability and matrix heterogeneity which can. Not only does the flow diagnostic ranking agree well with the cumulative oil ranking the run time for the flow diagnostics is <0.25% of the total simulation time. This significant reduction in the time to compare models allows more time to spend running full physics simulation on the important and geologically diverse cases that offer the most insight.
Due to numerical difficulties in conducting high fidelity simulation of recovery mechanisms in complex natural fracture systems, there are no published studies that address the impact of preserving details of the fracture networks. We used highly refined grids to conduct fine scale simulations of various recovery mechanisms in different complex fracture settings and compared the results to those obtained on simplified dual porosity dual permeability (DPDK) representations created by applying a consistent upscaling procedure.
Our study considers densely connected, sparsely connected, and isolated fracture networks that are extracted from a field-scale fractured carbonate reservoir model. Discrete fracture-matrix (DFM) models were constructed using an unstructured grid with refinement of the matrix rock near fractures. High-resolution simulations of spontaneous imbibition, gravity drainage, and viscous displacement recovery mechanisms were conducted on these DFM models. We also built equivalent DPDK models by using single phase flow-based upscaling and actual fracture geometry and distribution. The recovery mechanisms were simulated on these DPDK models and compared to high-resolution DFM models.
The fine scale simulations revealed that lateral viscous displacement recovery depends on the details of the fracture networks and can be significantly higher than those predicted from equivalent DPDK models. The DPDK models all predict the same recovery. For spontaneous imbibition, both fine scale and equivalent DPDK models show dependence on fracture geometry, but the DPDK models predict much higher rates. Fine scale and equivalent DPDK models agree reasonably for gravity drainage. These findings are explained by analyzing the matrix-fracture flows, and implications on efforts to improve shape factors in DPDK models and upscaling efforts in DFM models are discussed.
In an unconventional reservoir, the biggest challenge is to know how the natural fractures drain the reservoir as they have the greatest impact on production. But unfortunately very little information is available about them. Microseismics aid in building a picture of the fracture network, but give no information about fractures where actual fluid flow occurs. Production logging results give information around wellbore area only. Conventional rate transient analysis has major drawbacks, as long shut-in times are not possible and with dimensionless variables multiple results are possible. The method outlined in this paper overcomes these limitations using simplified assumptions.
The simulation modeling method uses dual porosity method as an idealization of the fracture network, which is the conventional wisdom, but with constant volume hydraulic fractures. This restricts the possible fracture lengths and the associated geometries of these hydraulic fractures, when modeled in 1D, 2D or 3D orientation. These HF-NF connectivity scenarios, using idealized fracture network of slabs (planar 1D HF-NF), matchstick (non-planar 2D HF-NF) and cubes (non-planar 3D HF-NF) is used to establish those fundamental connectivity scenarios where the fracture spacing can either be 1:1:1 (equidistant) or in the ratio 1:2:3. In order to assign permeability to the fractures, under these six different fundamental scenarios which have the same production performance, we follow the single block approach based on rate transient analysis. It also helps in establishing fracture permeability for other fracture connectivity variants such as 2D HF - 3D NF or 3D HF - 2D NF and with the two previously specified fracture spacings.
The results of this study, which essentially deals with the reservoir linear flow, are presented in the form of characteristic plots based on the ratio of average dimensionless pressure in the block with the square root of dimensionless time versus the dimensionless time for different fracture pressure declines. In each of fracture connectivity scenarios the solution rises to a discreet 1, 2, 3 value if idealized blocks are used or fall short of these values for non-idealized block combination depending on block geometry of NF. These conclusions are also shown by field models, analyzing actual history matched data.
Basic knowledge of the orientation of NF network gives better history match and prediction results. Also, with the help of a reservoir simulator one can assign physical meaning to different fracture spacings, which could be in the increasing or decreasing form. Rate transient analysis, using dimensionless parameters, fails to illustrate this fact. This helps a long way in establishing optimum fracture spacing with the same volume of proppant being pumped in the reservoir and known NF orientation.
Lv, Zuobin (Tianjin Branch of CNOOC Ltd.) | Huo, Chunliang (Tianjin Branch of CNOOC Ltd.) | Ge, Lizhen (Tianjin Branch of CNOOC Ltd.) | Xu, Jing (Tianjin Branch of CNOOC Ltd.) | Zhu, Zhiqiang (Tianjin Branch of CNOOC Ltd.)
JZS oilfield is an offshore metamorphic rock fractured buried hill oilfield. It was put into development in July 2010. The overall production situation of the oilfield is good, but some problems have been exposed. The main performance is as follows: It is difficult to accurately characterize the heterogeneity of fracture space distribution; In the numerical simulation of fractured reservoir, it is impossible to accurately describe and predict the fracture flow of fluid channeling in corner point grid system.
In order to solve the above problems, this study presents a new integrated fractured reservoir geological modeling and numerical simulation research method based on unstructured grid. There are three key aspects to this method. (1) The multi-scale (large, middle and small) discrete fracture system is established by combining outcrop measurement data with well point information and seismic attributes. On the basis of post-stack 3D seismic data, ants attributes are extracted, then the ant body results are transformed into large scale fractures; Using azimuth anisotropy attribute based on pre-stack inversion and combining the distribution orientation of large-scale fractures, the middle-scale fractures are established; According to the power law distribution relation between the cumulative frequency and the fracture length of large scale and small scale which based on outcrop observation, the imaging logging data and pre-stack inversion azimuth anisotropy attribute, small scale fractures are constructed by DFN technology.(2) For multi-scale fractures, the unstructured grid division technique is used to build a 3D model that conforms to the heterogeneity of dual media. In this study, a layered triangular prism grid generation technique is proposed. It is used to establish model of multi-scale fractures based on unstructured grid. Using large-scale fractures as a constraint, full 3D unstructured grid model is set up, and the discrete fracture model can accurately describe the fracture system and the coupling relationship between matrix and the fracture;(3)The triple-medium numerical simulation of the reservoir in the study area is carried out by using the automatic history fitting technology of ensemble kalman filter (EnKF). After several parameter adjustments, both the coincidence rate of the index and the fitting precision are higher than before.
Multi-scale discrete fracture model based on the large-scale fractures discretization processing, equivalent medium processing to middle and small scale fractures, keeps the seepage characteristic of the large-scale discrete fractures model and ensures the calculation efficiency. The results show that the new method has obvious advantages in computing speed and that the fitting effect is closer to the actual production performance.
Unstructured gridding has become an important subject matter in reservoir simulation. Its flexibility of grid generation and enhanced simulation accuracy have gained popularity in reservoir simulation, especially when modeling reservoir with complex wells and faults. In this work, unstructured gridding is being extended to model the complex discrete fracture network in unconventional reservoir simulation. The typical way of gridding in reservoir simulation is using structured grid due to the easiness of cell indexing but the drawback of zig-zag approximation of reservoir geometry is also apparent on the cells near well, fault or fracture. However, such challenge is addressed when using unstructured grid, where the grid cells can be generated conforming to the geometry without large extent of approximation. In this work, 2.5D unstructured PEBI gridding is being used to model the complex discrete fracture network where the fracture geometry can be straight line or irregular. Grid density is controlled by a multi-level scheme based on region of interest in the reservoir and geometry locations of well and fracture. Near-well and near-fracture flow modeling are being enhanced with the use of high resolution grids in the area close to wellbore and fracture pathway. Particularly in the near-fracture area, the unstructured gridding method generates Logarithmically Spaced Locally Refined (LSLR) grid to capture the transient in the ultralow-permeability shale, to satisfy the requirement to model the large fracture pressure gradient which is sensitive to stress changes.
This adaption of unstructured gridding method in modeling fracture in unconventional reservoir brings the gridding flexibility to model the complex fracture geometry. By using the fracture oriented grid density control scheme, pressure gradient change in near-fracture area can be modeled with enhanced accuracy. Benefits of using unstructured grid are demonstrated on simulation example by using unstructured grid and being compared with the structured grid.
This presented work introduces an enhanced way of complex fracture modeling in unconventional reservoir simulation by using unstructured gridding framework. It improves the grid generation efficiency and simulation accuracy, which is valuable in unconventional reservoir simulation and development.
Wu, Yonghui (China University of Petroleum, Beijing) | Cheng, Linsong (China University of Petroleum, Beijing) | Huang, Shijun (China University of Petroleum, Beijing) | Fang, Sidong (Sinopec Petroleum Exploration and Production Research Institute, Beijing) | Jia, Pin (China University of Petroleum, Beijing) | Wang, Suran (China University of Petroleum, Beijing)
Carbonate reservoirs comprise fractures, vugs, and cavities. Vugs have a large contribution to reserves of oil and gas, and the fractures provide effective paths for fluid flow in the reservoir. The triple-porosity (TP) model is an effective conceptual method for capturing rock matrix and vugs and the microfractures connecting them. However, these fractures and vugs are always nonhomogeneous. Macrofractures and vugs cannot be handled with a continuum scheme because of their low density and high conductivity.
In this approach, the TP conceptual model is implemented to characterize rock matrix, microvugs, and fractures. To capture the heterogeneity of fractures and vugs, macrofractures and vugs are represented explicitly with the discontinuum model. The boundaries of macrovugs and macrofractures are discretized into several elements. The boundary-element method (BEM) is used to handle flow into macrofractures and vugs. The finite-difference method is applied to handle flow within macrofractures. The flow within macrovugs is assumed to be pseudosteady state.
With a simple discretization of the boundaries of macrovugs and macrofractures, the proposed model is shown to efficiently simulate the behavior of fractured carbonate reservoirs with heterogeneity. The computational accuracy is demonstrated using an analytical model and numerical simulation. On the basis of the proposed model, the effect of the heterogeneity of macrofractures and vugs on pressure-transient behavior is analyzed. The results show that macrofractures and vugs cannot be handled with triple-continuum models analytically. There will be several “dips” on the derivative of the pressure curve if macrovugs are discretely handled. Also, discretely handling the fractures and vugs will make the calculated dimensionless pressure and the derivative pressure lower than those calculated with the triple-continuum models. After increasing the porosity of macrovugs, the pressure and the derivative will go down in the flow regimes dominated by macrovugs. The conductivity of macrofractures has a great impact on almost all the flow regimes except for boundary-dominated flow. Finally, a field case is used to show the application of the proposed semianalytical model.
The novelty of the new model is its ability to model the transient behavior of carbonate reservoirs with nonhomogeneous fractures and vugs. Furthermore, it provides an efficient method for characterizing the heterogeneity of multiscaled fractures and vugs.
A major challenge in carbonate reservoirs is the highly-fractured nature of the rock. The flow rate may be high or low depending on the targeted fracture clusters. In addition, it is possible that flow rates vary from one region of the reservoir to another. Smart wells furnished with smart completion strategy presents great prospects to produce such reservoirs intelligently, thereby, helping to deal with heterogeneities rather smartly. It is established that early water break-through occurs when multi-lateral wells are completed with constant choke settings, and therefore one way to mitigate this problem is using smart completions that manage the unexpected production through fractures, thereby increasing ultimate recovery. The early water breakthrough is obvious because if a lateral section intersects a clusters of fracture zone, there is a possibility that these fractures may connect with the water zone that may trigger the breakthrough. This can be managed by preferentially regulating production from manifold laterals.
The evident communication among the various laterals of the mother bore raises difficulty in optimizing the production from the variable productivity intervals. In theory, the optimization scheme of smart completion involves different constraints, nevertheless, the settings of the smart inflow control valve (ICV) is the single most important parameter that may prove to be the differentiating factor between a high producing well to a poorly producing one. This study engrosses its effort on the reservoir engineering characteristics of finding the optimum choke setting that would lead to maximum recovery.
Computational Intelligence through Particle Swarm Optimization (PSO) is utilized as the integral algorithm to determine the optimal ICV configuration for a fishbone well in a naturally fractured carbonate reservoir. A commercial black oil simulator was used to determine the objective function; whose role here is to evaluate the fitness of a configuration of the choke; this was carried out under a workflow programmed in the MATLAB programming language that coupled the optimization algorithm with the numerical simulator. A single fishbone well, having 15 laterals was studied in order to see the effect of the fracture network on the water breakthrough and consequent impact on recovery.
Three different scenarios are developed to see the impact of optimization; a base case employing only multilateral well technology without the smart well completion, a smart well completion scheme with no optimization and finally the optimized smart well completion. The results very sequentially clarify the need for not only optimization but also highlights the role of intelligent completions for wells in the reservoir being studied. It is evident that without using smart wells, the water breakthrough is relatively earlier and produces less hydrocarbons, but as the use of smart wells is incorporated, the results start improving and for complete optimization scheme of the ICVs, it is observed that the recovery has increased by almost 80% from 21% to 38%. Moreover, the time to water breakthrough and eventually the cumulative water cut has also been managed quiet significantly.
Xia, Yang (China University of Petroleum, Beijing) | Jin, Yan (China University of Petroleum, Beijing) | Chen, Mian (China University of Petroleum, Beijing) | Chen, Kang Ping (Arizona State University)
Unconventional reservoirs after formation-stimulation treatments are always characterized by complex fracture networks with a wide range of length scales and topologies. Accurate simulation on multiscale discrete-fracture/matrix interaction during transient productive flows for such reservoirs is challenging but important for reservoir evaluation, optimization, and management.
In this paper, we present a new enriched and explicit method for simulation on multiscale discrete-fracture/matrix modeling (EE-DFM) on structured grids to decouple the mesh conformity between the porous media and the fractures. A hybrid structured EE-DFM is first introduced, and enrichments for different scales of fracture segments are proposed to locally enrich the conventional approximation space for representing the pressure solution surrounding multiscale fracture networks. By appropriately selecting an asymptotic function to locally enrich the conventional approximation space, typical behavior of fluid flux around features in fractured media, such as discontinuities and singularities, can be directly captured. Simulation on complex multiscale fracture networks is achieved by using the superposition principle of the enrichments without introducing additional degrees of freedom and while maintaining computational efficiency. We demonstrate the accuracy and flexibility of the method by performing a series of case studies and comparing the results with simple analytical solutions as well as with conventional numerical solutions. The results of long-term well-performance case studies are used to show the good computational efficiency of the proposed method when the complexity of fracture networks is increased. The potential of the proposed method to be incorporated into the multicontinuum concept for solving nonlinear gas transport in a shale reservoir is presented. The present study provides a promising framework for real-field multiscale discrete-fracture models for unconventional-reservoir simulations.