Heterogeneous Fractured Reservoir Research Articles

Damage evolution characteristics of heterogeneous fractured sandstone reservoir under different fracturing fluids

AbstractTo investigate the coupling effect of in situ stress and fluid pore pressure and the propagation law of damaged area during hydraulic fracturing and gas fracturing in heterogeneous fractured reservoirs, according to the effective stress principle and the smooth Rankine stress criterion, this paper establishes a coupled fluid–solid‐damage mathematical model of heterogeneous rock layers and carries out numerical simulations on the characteristic field changes of rock layers under water and nitrogen fracturing. The results show that the continuous injection of nitrogen or water can cause an increase in pore pressure in natural fractures and rock matrices, leading to rock damage and an increase in porosity. Under the same parameters, the damage area and length of the rock mass during nitrogen fracturing are larger than those of hydraulic fracturing, and the changes in pore pressure, permeability, and porosity are consistent with the damage area. The pore pressure near the connected natural fractures is relatively high, resulting in tensile strain; the pore pressure at isolated fractures is relatively low, and some even produce compressive strain. During nitrogen fracturing, the damage evolution is less affected by the in situ stress and the matrix permeability, while hydraulic fracturing is more affected by them. The damage area is the smallest when the horizontal in situ stress is equal. When the initial permeability of the matrix is low, the damaged area mainly follows the natural fractures and is distributed in a strip shape. As the permeability of the matrix increases, the fracturing fluid can enter the matrix, and the damaged area is in the shape of a block.

Fast and Robust Prediction of Multiphase Flow in Complex Fractured Reservoir Using a Fourier Neural Operator

Predicting multiphase flow in complex fractured reservoirs is essential for developing unconventional resources, such as shale gas and oil. Traditional numerical methods are computationally expensive, and deep learning methods, as an alternative approach, have become an increasingly popular topic. Fourier neural operator (FNO) networks have been shown to be a hundred times faster than convolutional neural networks (CNNs) in predicting multiphase flow in conventional reservoirs. However, there are few relevant studies on applying FNO to predict multiphase flow in reservoirs with complex fractures. In the present study, FNO-net and U-net (CNN-based) were successfully applied to predict pressure and gas saturation fields for the 2D heterogeneous fractured reservoirs. The tested results show that FNO can accurately depict the influence of fine fractures, while the CNN-based method has relatively poor performance in the treatment of fracture systems, both in terms of accuracy and computational speed. In addition, by adding initial conditions and boundary conditions to the loss function of FNO, we prove the necessity of adding physical constraints to the data-driven model. This work contributes to improving the understanding of the applicability of FNO-net, and provides new insights into deep learning methods for predicting multiphase flow in complex fractured reservoirs.

Comparison of CO2 and water as working fluids for an enhanced geothermal system in the Gonghe Basin, northwest China

Because of the additional benefit of geological storage and the self-sustaining thermosiphon effect, CO2 instead of water as a working fluid for geothermal energy production has attracted much interest. In this study, based on the geological and geothermal conditions in the Gonghe Basin of China, a more realistic physical model is built by coupling the wellbore and the thermal reservoir. In our model, a novel dual-vertical well pattern and the heterogeneous fractured reservoir are considered. Based on the novel dual-vertical well pattern, the CO2– based enhanced geothermal system (EGS) can avoid premature thermal breakthrough. The results demonstrate that the CO2-EGS is more efficient than the water-EGS. The heat extraction rate of the CO2-EGS increased by 58% when compared to the water-EGS. However, the CO2-EGS results in drastic drops of production temperature in the wellbore (approximately 62 ℃) due to the strong Joule-Thomson effect. In addition, the sensitivity results suggest that the CO2-EGS is more suitable for developing in low permeability geothermal reservoirs. This work provides important references for the working fluid selection and well placement to develop the clean power generation in the Gonghe Basin geothermal field.

Evaluation of Open Fractures-Sonic Velocity Relation in Fractured Carbonate Reservoirs

Summary Rock physics evaluation of heterogeneous fractured reservoirs where such fractures are the main fluid conduits is necessary for production optimization and field development. In this regard, fracture parameters (i.e., aperture, density, etc.) play a significant role in acoustic wave velocities and propagation, which should be investigated. However, the effect of fracture parameters on sonic wave velocities and their propagation is relatively vague in fractured reservoirs. This study aims to evaluate the mentioned relation by integration of velocity deviation logs, image logs, conventional logs, sonic waveforms, core data, and thin sections in the four studied wells. The results of the velocity deviation logs and sonic waveforms indicate that fracture density and fracture aperture directly control their fluctuations. For example, results showed that zones with higher fracture aperture and lower fracture density, mainly in the dolomitic facies, exhibited more deviations (<−500) compared with the zones with higher fracture density and lower fracture aperture. Hence, the negative deviations on the velocity deviation log are not directly controlled by fracture density, and fracture aperture is the most effective factor on the negative deviation of the velocity deviation log. So, it seems that this parameter controls sonic waves scattering and reservoir behavior. It was found that open fractures and zones with higher porosity (>10%) would have a great impact on sonic wave velocities, attenuation, and other rock physics properties. Ultimately, it was confirmed that a simple but robust combination of the velocity deviation log with sonic waveforms can be used to delineate fractured zones with high fracture aperture (>0.1 mm) in the wells where core samples or image logs are not available.

A novel linear solver for simulating highly heterogeneous black oil reservoirs

A great deal of computational power and time is necessary for the simulation of highly heterogeneous fractured reservoirs with complicated geometry. Simulating such largescale complex reservoirs with both minimum time and maximum accuracy has consistently remained a topic of concern to reservoir simulation engineers worldwide. The currently used linear solvers in well-known commercial simulators that utilize classical methods such as Nested Factorization (NF) and Incomplete LU Factorization (ILU) as their preconditioners, all suffer from severe convergence problems in models with high heterogeneity and/or large number of non-neighbor connections. To overcome such problems, a novel Adaptive Algebraic Multi-grid algorithm (AAMG) is proposed to be used in a constrained pressure residual (CPR) preconditioner, abbreviated as CPR-AAMG, in order to solve the governing discretized three-dimensional partial differential equations. The implemented CPR preconditioner which uses AAMG as the preconditioner for the elliptic pressure equation, and the Blocked ILU for the hyperbolic saturation equations, is a robust way for damping both smooth pressure field and high frequency saturation field errors in giant reservoir models. The findings of the current study illustrate that the developed Biconjugate Gradient Stabilized (BiCG-Stab) solver preconditioned by CPR-AAMG is capable of achieving acceptable results of high efficiency and robustness in the SPE10 project which is renowned as an enormous challenge for linear solvers due to the highly heterogeneous porosity and permeability values. The novelty of the proposed CPR-AAMG preconditioner is its ability to solve three-dimensional black oil models of giant, complex and heterogeneous fractured reservoirs without any convergence problems with reduction in time and required computational power.

Discrete fracture networks modeling of shale gas production and revisit rate transient analysis in heterogeneous fractured reservoirs

Horizontal wells with multiple hydraulic fractures are necessary stimulation technique for economically developing tight and shale gas reservoirs. In such reservoirs, the conventional well-test techniques are not suitable because of ultralow formation permeability. Rate transient analysis (RTA) is the widely used tool for analyzing these reservoirs for the purpose of reserves estimation, hydraulic fracture stimulation optimization, and development planning. However, the conventional rate transient analysis is based on the models that were derived from idealistic assumptions for homogenous reservoirs. In this article, we first review the industry's common practice for rate transient analysis and discuss why the idealized conceptual model may not be adequate for analyzing production data from shale gas reservoirs. Then, a unified shale gas reservoir model based on Discrete Fracture Networks (DFN) is presented to investigate how each mechanism influences shale gas production and the corresponding rate transient behavior. It is found that shale gas production and rate transient behavior are significantly impacted by reservoir heterogeneity, fracture networks, non-Darcy flow, gas adsorption and completion efficiency. Short early-time linear flow with long transitional flow period is an indication of either existence of abundant complex fracture networks or heterogeneous completion with unevenly distributed hydraulic fractures. Consider the nature of non-unique results of RTA, information from other independent sources is required to achieve a consistent and holistic interpretation.

Streamline simulation of water-oil displacement in a heterogeneous fractured reservoir using different transfer functions

Main parts of oil and gas reserves are stored in fractured reservoirs. Simulation of multiphase flow in fractured reservoirs requires a large amount of calculations due to the complexity, reservoir scale and heterogeneity of the rock properties. The accuracy and speed of the streamline method for simulating hydrocarbon reservoirs at field scale make it more applicable than conventional Eulerian simulators using finite difference and finite element techniques. Conventional simulators for fractured reservoirs consume a great deal of time and expense and require powerful CPUs like supercomputers. This makes the development of a fast, powerful and precise simulation method of great importance. The present study was undertaken to develop a computational code as a streamline simulator to study waterflooding in a two-dimensional fractured reservoir with heterogeneous permeability using the Dual Porosity-Single Permeability (DPSP) model. In this simulator, the pressure equation is solved implicitly over an Eulerian grid and then the streamlines are generated using Pollock's semi-analytical method and are traced. At this point, the Time-Of-Flight (TOF) is developed and the saturation equations are mapped and solved explicitly along the streamlines. Next, the results are transferred back onto the Eulerian grid and the calculations are repeated until the simulation end time. In fractured reservoirs, the interaction between the matrix and fracture is included in the transfer functions. Transfer functions model fluid flow and production mechanisms between the matrix and fracture. They introduce source/sink equations between the matrix and fracture and they are distributed throughout the media. In the current study, a problem is simulated using streamline method and several important transfer functions. A new linear transfer function with a constant coefficient is introduced that is based on differences in water saturation between the matrix and fracture. The simulation results were then compared and a commercial software is applied to solve the same problem. The results of the streamline simulator were compared with those of the commercial software and showed appropriate accuracy for the newly introduced transfer function. The accuracy and efficiency of the streamline simulator for simulation of two-phase flow in fractured reservoirs using different transfer functions are confirmed and the results are verified.

Erratum to: Streamline simulation of water-oil displacement in a heterogeneous fractured reservoir using different transfer functions

Erratum to: Streamline simulation of water-oil displacement in a heterogeneous fractured reservoir using different transfer functions

Three-dimensional reservoir architecture modeling by geostatistical techniques in BD block, Jinhu depression, northern Jiangsu Basin, China

To reduce or avoid some of the ambiguities in a heterogeneous reservoir, a fine three-dimensional model would be inevitably established with the application of geostatistical techniques. BD oilfield is a low-permeability fractured reservoir with many fracture types, which composes a multi-azimuthal fracture system, causing strong anisotropy and heterogeneity. Moreover, fracture provides not only accumulation space for oil and gas but also channels for migration of hydrocarbons and water dashing and thus plays a leading role in controlling BD reservoir production. With the continuous exploitation of oil in reservoir for more than 30 years, BD oilfield has currently stepped into high water cut stage, exposing many problems such as low oil recovery, poor exploitation stability, rapid oil production decline, and one-way water intrusion. Therefore, a detailed reservoir characterization, constructed to describe reservoir behavior under strong water drive in a well-developed fractured reservoir, is urgently needed. In this study, combined with three-dimensional geostatistical techniques, an accurate and efficient reservoir parameter model that occurs in a strong heterogeneous fractured reservoir has been constructed through stratigraphic correlation and sedimentary facies analysis. Hence, all the study presented above will be available for well location, remaining oil potential-tapping and oil recovery improvement during the later study work.

Effect of operational parameters on SAGD performance in a dip heterogeneous fractured reservoir

Steam Assisted Gravity Drainage (SAGD) has been studied theoretically, experimentally and numerically as a promising EOR process. Most of the simulation works have been conducted microscopically in homogeneous non-dipping models. In this communication, the effect of operational parameters on SAGD performance is investigated in a dip heterogeneous naturally fractured reservoir (NFR) with oil wet rock using CMG-STARS thermal simulator. The results indicate that reservoir dip has unfavorable effects on SAGD performance due to overriding effect. Moreover, less oil saturation of matrix causes steam to penetrate into upper blocks. It has also been observed that reservoir thickness controls operational parameters. Furthermore, the results indicate that there is no need for more preheating due to desired heat communication between well pair. As it was expected, higher steam injection rate leads to more oil production. Besides, longer well pairs have no considerable effects on SAGD performance in dip reservoirs. Besides, because of quick reservoir depletion in injection at high pressure, SAGD is not recommended economically in thinner reservoirs.

Integrated reservoir characterization of a fractured basement reservoir

It is a considerable challenge to effectively develop hetero-geneous fractured reservoirs in complex structural settings. Here we present a case study of a fractured basement reservoir hosted in structural highs formed by fault-controlled blocks in a rift setting. A wide range of data were available to study the current reservoir. The seismic database includes a wide-azimuth data set, as well as an extensive set of derived attributes and structural interpretation. Azimuthal anisotropy, automatic fault detection, and rms amplitude proved to be most useful in the description of the fracture network, the fracture corridors, and a thin, permeable sandstone layer above the basement, respectively. An additional advantage of the wide-azimuth survey was that it provided an optimum illumination in complex structural settings such as the current case. To complete this large-scale data set, conventional log suites and image logs were acquired in most of the wells. Borehole image-log studies were conducted to interpret and recognize fracture features. Regarding dynamic information, flowmeter logs were acquired in addition to the production history. The main objectives of this integrated study were the creation of a conceptual model for well planning and to constrain the static and dynamic properties of the reservoir model.

Characterization of Tracer Transport in Heterogeneous Fractured Reservoir by a Streamline Approach on Unstructured Grids

This article presents a numerical analysis on anomalous transport behavior in a heterogeneous fractured porous reservoir using streamlines. The authors developed a streamline simulator with a direct quadrilateral mesh generator to investigate the correlated effects of hydrological properties. Quadrilateral grids were made by constructing boundary loops automatically. The mesh generator showed reliable shapes and did not need to construct another control volume for a conventional transport model. Solute was transported using a streamline approach on the irregular grids with various values of permeabilities between matrix and fracture. Breakthrough curve has a skewed characteristic similar at a real heterogeneous medium. The trajectories of streamline, the distribution of pressure, and the skewed breakthrough confirm the applicability of our model at both porous and fractured medium.

Making the Most of the Geometric Relationships Between Deviated Well Bores and Regional Natural Fractures

A randomly oriented, horizontal well bore azimuth has a 67% chance of intersecting more than 50% of those regional, vertical, natural fractures that it would intersect if it were normal to fracture strike. Similarly, if subsurface fracture strike can be determined to only within +30{degree}, a well bore can still be oriented to intersect 287% of the fractures. This percentage, or efficiency, is the sine of the angle between the well bore azimuth and fracture strike. If horizontal well bores are not an option, the sine-function relationship works to the operator's advantage in well bores with only moderate deviations. Thus, if subsurface fracture strike is known, a well bore can be deviated through the reservoir at 30{degrees} from vertical in the direction normal to fracture strike and will intersect 50% of the fractures that would be hit by a horizontal well bore of similar length with the same azimuth. Core from a 30{degree} well bore where fracture strike is unknown would still be extremely useful for fracture characterization because it significantly improves changes for recovering fractures in core; such a well bore has a 67% chance of a greater than or equal to 25% fracture-intersection efficiency. Moreover, fractures n deviated more » core can be oriented without an orientation survey by using bedding and the well-bore survey. An asymmetric scribe shoe (0{degree}-130{degree}-200{degree}) is valuable for determining uphole direction of the core. In both thin-bedded and heterogeneous fractured reservoirs, where fractures are confined to bedding, there is a quantifiable tradeoff between number of beds intersected and number of fractures intersected as the well bore deviates from vertical. An intermediate well-bore deviation may offer more drainage efficiency than horizontal or vertical wells and maximize opportunities for fracture characterization. « less