Hui, Mun-Hong (Chevron Energy Technology Company) | Dufour, Gaelle (Chevron Energy Technology Company) | Vitel, Sarah (Chevron Energy Technology Company) | Muron, Pierre (Chevron Energy Technology Company) | Tavakoli, Reza (Chevron Energy Technology Company) | Rousset, Matthieu (Chevron Energy Technology Company) | Rey, Alvaro (Chevron Energy Technology Company) | Mallison, Bradley (Chevron Energy Technology Company)
Traditionally, fractured reservoir simulations use Dual-Porosity, Dual-Permeability (DPDK) models that can idealize fractures and misrepresent connectivity. The Embedded Discrete Fracture Modeling (EDFM) approach improves flow predictions by integrating a realistic fracture network grid within a structured matrix grid. However, small fracture cells with high conductivity that pose a challenge for simulators can arise and ad hoc strategies to remove them can alter connectivity or fail for field-scale cases. We present a new gridding algorithm that controls the geometry and topology of the fracture network while enforcing a lower bound on the fracture cell sizes. It honors connectivity and systematically removes cells below a chosen fidelity factor. Furthermore, we implemented a flexible grid coarsening framework based on aggregation and flow-based transmissibility upscaling to convert EDFMs to various coarse representations for simulation speedup. Here, we consider pseudo-DPDK (pDPDK) models to evaluate potential DPDK inaccuracies and the impact of strictly honoring EDFM connectivity via Connected Component within Matrix (CCM) models. We combine these components into a practical workflow that can efficiently generate upscaled EDFMs from stochastic realizations of thousands of geologically realistic natural fractures for ensemble applications.
We first consider a simple waterflood example to illustrate our fracture upscaling to obtain coarse (pDPDK and CCM) models. The coarse simulation results show biases consistent with the underlying assumptions (e.g., pDPDK can over-connect fractures). The preservation of fracture connectivity via the CCM aggregation strategy provides better accuracy relative to the fine EDFM forecast while maintaining computational speedup. We then demonstrate the robustness of the proposed EDFM workflow for practical studies through application to an improved oil recovery (IOR) study for a fractured carbonate reservoir. Our automatable workflow enables quick screening of many possibilities since the generation of full-field grids (comprising almost a million cells) and their preprocessing for simulation completes in a few minutes per model. The EDFM simulations, which account for complicated multiphase physics, can be generally performed within hours while coarse simulations are about a few times faster. The comparison of ensemble fine and coarse simulation results shows that on average, a DPDK representation can lead to high upscaling errors in well oil and water production as well as breakthrough time while the use of a more advanced strategy like CCM provides greater accuracy. Finally, we illustrate the use of the Ensemble Smoother with Multiple Data Assimilation (ESMDA) approach to account for field measured data and provide an ensemble of history-matched models with calibrated properties.
Structural dip is the term used in borehole image and dipmeter interpretation to indicate the "tectonic" tilting in the vicinity of the wellbore. Structural dip, by definition, is the formation dip component that is caused by tectonic deformation such as folding, faulting, uplift and others.
Knowledge of the structural dip in the vicinity of the borehole is essential for several applications, including field structural modeling, well placement, geosteering of the lateral sections, and seismic data processing.
Traditionally, structural dip is computed from borehole image data using laminated shale dip based on the assumption that the laminated shale was deposited out of suspension and that the lamination was originally deposited as horizontal beds. This means that any tilting observed in laminated shale with "coherent" lamination is caused by tectonic tilting; hence, it can be used to compute the structural dip. There is nearly a consensus in the industry around this assumption, and the laminated shale dip is widely used to compute structural dip.
There are several geological settings under which laminated shale can form. Those are mostly subaqueous setting such as marine and lacustrine settings. Drilling through rocks deposited in such settings normally encounters sequences of laminated shale from which structural dip can be computed. However, rock formations deposited in subaerial environments often lacks settings under which laminated shale forms. Such environments are often dominated by sandstone lithologies deposited in high- energy settings this rich in sedimentary structures such as crossbedding. Due to absence of laminated shale sequences, computation of structural dip using the traditional approach is not possible.
This paper explains a technique that can be used to estimate structural dip from cross bedding on borehole images. It uses the geometrical relationship between the crossbedding surfaces and the lower set boundary of the corresponding crossbedding set. The line of intersection between these two surfaces is assumed to be horizontal at the time of deposition. Measuring multiple lines of intersections, plotting them on a stereonet, and fitting a great circle to them helps estimate the structural dip within the analyzed interval. The best- fitting great circle of these lines is believed to be a reasonable estimation of the structural dip.
This approach has been tested on few image log datasets with cross bedded sandstone facies and proved to be very close to the actual structural dip computation obtained from the shale facies in the same depositional sequence. This paper will illustrate some interpreted image log supporting this technique.
Huang, Jixiang (Lawrence Livermore National Laboratory) | Morris, Joseph P. (Lawrence Livermore National Laboratory) | Fu, Pengcheng (Lawrence Livermore National Laboratory) | Settgast, Randolph R. (Lawrence Livermore National Laboratory) | Sherman, Christopher S. (Lawrence Livermore National Laboratory) | Ryerson, Frederick J. (Lawrence Livermore National Laboratory)
Jixiang Huang, Joseph P. Morris, Pengcheng Fu, Randolph R. Settgast, Christopher S. Sherman, and Frederick J. Ryerson, Lawrence Livermore National Laboratory Summary A fully coupled finite-element/finite-volume code is used to model 3D hydraulically driven fractures under the influence of strong vertical variations in closure stress interacting with natural fractures. Previously unknown 3D interaction mechanisms on fracture-height growth are revealed. Slipping of a natural fracture, triggered by elevated fluid pressure from an intersecting hydraulic fracture, can induce both increases and decreases of normal stress in the minimum-horizontal-stress direction, toward the center and tip of the natural fracture, respectively. Consequently, natural fractures are expected to be able to both encourage and inhibit the progress of hydraulic fractures propagating through stress barriers, depending on the relative locations between the intersecting fractures. Once the hydraulic fracture propagates above the stress barrier through the weakened segment near a favorably located natural fracture, a configuration consisting of two opposing fractures cuts the stress barrier from above and below. The fluid pressure required to break the stress barrier under such opposing-fracture configurations is substantially lower than that required by a fracture penetrating the same barrier from one side. Sensitivity studies of geologic conditions and operational parameters have also been performed to explore the feasibility of controlled fracture height. The interactions between hydraulic fractures, natural fractures, and geologic factors such as stress barriers in three dimensions are shown to be much more complex than in two dimensions. Although it is impossible to exhaust all the possible configurations, the ability of a 3D, fully coupled numerical model to naturally capture these processes is well-demonstrated. Introduction Factors controlling hydraulic-fracture-height growth have been widely discussed in the literature (Naceur and Touboul 1990). Among them, in-situ-stress contrast between adjoining layers is recognized as one of the principal mechanisms that contain fractures in most scenarios. This is attributed to the fact that source-rock reservoirs are heterogeneous at very fine scales as a consequence of the depositional sequence and subsequent compaction. When a hydraulic fracture reaches a horizon where the stress contrast is high, it might not have the net pressure necessary for propagating into the higher-stress layer (Simonson et al. 1978). For normal-and strike/slip-stress environments, the hydraulic fracture opens against the minimum horizontal stress and propagation is largely within a vertical plane, with the minimum horizontal stress controlling vertical propagation.
Several recent studies have reported that proppant "bridging" (blocking) occurs at the interface between primary and secondary fractures. Such bridging blocks flow and significantly reduces the efficiency of proppant placement. The prevention of bridging is of great importance, but the criteria for bridging formation have yet to be determined. In this numerical study of proppant transport, we propose bridging formation criteria and analyze the associated distribution correlations that quantify the amount of proppant that migrates into the secondary fractures.
To model the complex interactions between proppant particles, fracturing fluids, and fracture walls, we use the discrete element method (DEM) coupled with computational fluid dynamics (CFD). We calibrate our model using widely accepted bed-load transport measurements. The simulation domain involves a "T-type" intersection of primary and secondary fractures. We investigate the effects of various proppant sizes and concentrations on bridging formation. In all cases, we investigate the occurrence of bridging and we quantify its impact by estimating the corresponding percentage of proppant reaching the secondary fractures.
Our simulation results show that the efficiency of proppant placement in the secondary fractures depends on the flow regime. In the suspension regime, proppant particles can be easily mobilized by the fluid drag force. This leads to a relative high proppant placement efficiency in the secondary fractures. When proppants are in the bed-load transport regime, kinetic energy transferred from the fluid drag force is dissipated by inter-particle collisions and the friction force. In this case, the amount of proppants entering the secondary fractures and the distance that proppants can cover are restricted compared to the case of proppants associated with suspension transport.
Our investigation reveals that two parameters are critical for the occurrence of proppant bridging (blocking) at the secondary fracture interface. These parameters are — the proppant concentration
Currently, the closure stress is often predicted using the conventional tangent method (i.e., G-function) or the variable compliance method. Both methods use several restrictive assumptions such as a single planar fracture. However, the hydraulic fracture often intersects rock fabric features such as bedding planes and/or natural fractures causing the pressure transient behavior to become drastically different compared to that of a single planar hydraulic fracture. Closure of the intersected natural fractures might precede that of the created HF which impacts the interpretation of the pressure derivate plots and also the closure stress. In this paper we present and use an advanced fracture diagnostic model that can help recognize the signatures of rock fabric features and their impact on estimation of the closure stress. An example field data is used to illustrate the potential impact on closure stress.
The new DFIT model consists of a fully coupled 3D hydraulic fracture simulator with the ability to handle the opening, propagation, and closure of natural factures so that the pre- and post-closure stress/deformation of both the hydraulic and natural fractures can be captured. Fracture propagation, HF-NF interaction, fracture intersection, and DFIT model are integrated into one simulator to provide a more realistic view of HF propagation and fracture diagnostics in naturally fractured reservoirs. The current model is developed without any major assumptions concerning the fluid flow, fracture deformation, and propagation path. Rock/fracture deformation is calculated using a boundary element formulation whereas the transport processes are solved using finite elements method.
Our results indicate that natural fractures affect the pre- and post- shut-in response of the hydraulic fracture in a number of ways. For example, the fracture propagation path, the pumping pressure profile, and interfering with the post shut-in pressure response. These factors, indeed, impact the estimation of the minimum horizontal stress which is a key parameter obtained from DFIT. Moreover, our results show how the normal stiffness of the fracture surface asperities can impact the minimum stress estimation. Closure of natural fractures is reflected in the slope of the pressure derivative and G-function plots so that correct interpretation of these signatures is essential to accurate extraction of the Shmin.
Closure of natural fractures is often viewed as a pressure depdendent leakoff mechanism that is reflected on the Gdp/dG curve. The closure behavior of HF-NF sets is, however, not explicitly modeled in the context of pressure transient analysis. Therefore, it is our objective to study the closure behavior of HF-NF sets using a 3D coupled simulator. This novel model is applied to actual field data to illustrate the potential impact on closure stress and to shed light on the subject of fracture diagnostics in naturally fractured reservoirs. Our results indicate that the closure behavior of hydraulic and natural fractures in a HF-NF set differs from that of an isolated fracture due to the effect of stress shadowing. Although the system stiffness method results in distinct signatures on the diagnostic curves, these signatures are not commonly observed in the field data. The absence of stiffness signatures in the field cases could be interpreted in two ways: 1) the closure mechanism assumed in the stiffness/compliance method differs from the actual fracture closure mechanism or 2) the stiffness of the hydraulic fracture is too low to cause any significant changes in the system stiffness after closure.
Micro-seismic data suggest that complex fracture networks are formed frequently in unconventional reservoirs due to the interaction of hydraulic fractures (HF) with natural fractures (NF). Understanding this interaction is critical for optimizing fracturing design. It is generally accepted that under certain conditions, a propagating HF can cause shear failure of a NF before intersecting with it. This fact is not accounted for in the development of the existing fracture interaction criteria. The goal of this study is to account for these dynamic interactions and present new criteria that define the conditions under which a HF will cross, kink, branch, or turn along a NF.
We have used our peridynamics-based poroelastic fracturing simulator in this study, which solves for rock displacements and fluid pressure in a fully coupled and implicit manner. Shear failure of the NF is modeled using a Mohr-Coulomb failure criterion. The frictional force on the NF surface is modeled implicitly. The stress distribution around the HF is monitored as the NF approaches it. Considering the effects of shear failure, different propagation behavior such as turning, and crossing are characterized as a function of in-situ stress ratio, angle of approach, NF characteristics, and matrix permeability. It should be noted that the peridynamics model used in this study does not require a crossing criterion as an input, rather it can predict the interaction behavior based on local poroelastic stresses.
The model is validated against analytical crossing criteria derived using Linear Elastic Fracture Mechanics (LEFM) by ignoring shear slippage prior to intersection and poroelasticity in our model. Recent experimental observations that show an increase in approach angle before intersection of a HF with a NF are also used to test the model. Shear failure of the NF before intersection results in relaxation of the stresses locally. This in turn leads to the HF bending towards the NF. Though these effects are found to be important in low permeability rocks (100 nD), they are more pronounced in high permeability rocks (10 mD). In high permeability rocks, poroelastic effects are much more significant, leading to greater stress relaxation and thus a near-orthogonal modified approach angle. When stress relaxation due to prior shear slippage of the NF is considered, the HF is more likely to turn along the NF. For low angles of approach and low stress ratios (1.0-1.1 for low permeability rocks and 1.0-1.2 for high permeability rocks), the crossing criteria derived in this study are considerably different from those derived using LEFM. However, for near-orthogonal angles of approach or high stress ratios, the crossing criteria do not change much.
The crossing criteria derived here can serve as direct inputs for discrete fracture network models simulating the growth of complex fracture networks (
Franquet, Javier Alejandro (Baker Hughes, a GE company) | Singh, Rudra Pratap Narayan (ADNOC offshore) | Diaz, Nerwing (Baker Hughes, a GE company) | Anurag, Atul (ADNOC offshore) | Balooshi, Mohamed Ali Al (ADNOC offshore) | Jefri, Ghassan Al (ADNOC offshore) | Hosany, Khalid Ibrahim M (ADNOC offshore) | Cesetti, Mauricio (ADNOC offshore) | Kindi, Rashid Khudaim Al (ADNOC offshore) | Zhunussova, Gulzira (Baker Hughes, a GE company) | Bradley, Tom (Baker Hughes, a GE company) | Kirby, Cliff (Baker Hughes, a GE company)
An injector well drilled from an artificial island in UAE left a non-magnetic fish during well control operations across lower Cretaceous reservoirs below the 9�?-in. casing shoe, exposing all upper Jurassic reservoirs flow units. The situation was a serious concern to field developing and reservoir integrity as aquifer, gas and many layers of oil reservoirs were connected through the borehole below the fish. It was decided to sidetrack around the fish to intersect the original 8½-in. open-hole section. The sidetrack was accomplished, but the first attempt to intersect the mother hole was unsuccessful. Therefore, an innovative solution was needed for detecting the mother hole to intersect it.
A combination of cross-dipole deep shear acoustic, high-resolution induction and orientation wireline measurements were advised. These measurements would be used to update the wellbore survey and to detect acoustic reflections from the mother hole for identifying its relative orientation with respect to the sidetrack hole. Detailed measurement-while-drilling (MWD) wellbore survey analyses were conducted for the original and sidetrack holes beside typical corrections, such as Sag and drillstring interference. The deep shear wave imaging data recorded in the side-track hole was processed at multiple X-dipole polarization directions to detect shear reflection from the mother-hole and back calculate its relative position.
The high-resolution induction data could not detect the fish from the sidetrack, but few dipole reflections of the mother hole were detected in two locations. The orientation of the reflectors was consistent with the revised wellbore survey analysis, and this information was used to make the directional drilling corrections required to intersect the mother hole. The use of deep shear wave imaging data to identify a nearby open hole was a non-conventional application of this technology, but it definitely facilitated directional drilling operations to successfully intersect a mother hole that cannot be left uncompleted. After the openhole intersection, a good borehole condition was encountered due to the non-damaging fluid system, allowing the well to be completed as per original plan. Achieving this challenging directional drilling objective was critical for the field development plan of these offshore UAE reservoirs.
This case study represents the first documented field experience of using deep shear wave imaging data in the petroleum industry for assisting directional drillers to intersect an open hole mother wellbore after sidetracking a fish.
Xu, Wenjun (Southwest Petroleum University) | Zhao, Jinzhou (Southwest Petroleum University) | Li, Yongming (Southwest Petroleum University) | Rahman, Sheik S (University of New South Wales) | Fu, Dongyu (Southwest Petroleum University) | Chen, Xiyu (Southwest Petroleum University)
Complex fracture network makes it possible for commercial exploition of shale gas by means of hydraulic fracturing. It was believed that the interaction between hydraulic fracture (HF) and natural fracture (NF) had a significant impact on HF complexity. In this paper, a new numerical model has been developed to investigate HF/NF intersection under different geological and engineering parameters. Displacement discontinuity method (DDM) and finite volume method (FVM) are used to numerically model and solve the problem of coupled rock deformation, fluid flow, interface slipping, and opening associated with HF propagation and its interaction with NF. In addition, the model also considers the effects of fracture fluid leak-off. Based on the model, sensitivity analyses of key influence parameters are implemented. The numerical model results provide detailed quantitative information on fracture-geometry evolution, interfacial stress distribution and injection-pressure history. The simulation results show that the HF tends to cross the NF under the conditions of high principal stress difference, high intersection angle, high interfacial friction, high injection rate, high fracturing fluid viscosity and low initial conductivity of the NF. Moreover, the morphology of HF is significantly affected by two engineering parameters, the injection rate and the viscosity of the fracturing fluid. The effect of these two engineering parameters on the morphology of HF can be expressed as the product of them. The same value of the product results in the same HF morphology at the times of same injected-fluid volumes. In addition, the injection pressure curves can also help determine whether a crossing HF is developed when a HF interacts with a NF. The numerical model provides an effective approach for quantitatively analyzing the development of various types of HF/NF interaction behavior. It allows us to gain a better insight to the performance of hydraulic fracturing treatments in naturally fractured reservoirs.
Wang, Chen (Nagasaki University) | Jiang, Yujing (Nagasaki University) | Liu, Richeng (China University of Mining and Technology) | Liu, Jiankang (Nagasaki University) | Zhang, Zhenyu (Chongqing University) | Sugimoto, Satoshi (Nagasaki University)
In coalbed methane recovery, oil exploitation and geothermal resources utilization, the exploitation is always accompanied with a two-phase flow process in the fracture network. To quantitatively describe the two-phase flow hydraulic properties in intersecting-fractures, in this study, a gas-water two-phase flow experiment was conducted in a smooth 3D intersecting fracture model. The results show that: at a certain water flow rate, the two-phase pressure drop increases nonlinearly with respect to the gas flow rate, which is different from previous results of the two-phase flow in rough single fractures. It is believed that this nonlinearity is induced by the strong inertial effect of water in the intersecting fracture. The Martinelli-Lockhart model is not only effective for describing the two-phase flow in single fractures, but also for the two-phase flow in intersecting fracture. Since the Martinelli-Lockhart model considers the inertial forces, which is quite significant in the intersecting fracture, the good fitting results are obtained. This study provides basis for further investigation on the two-phase flow characteristics in the fracture network.
Two-phase flow in fractures is a key issue in many engineering applications such as gas-oil flow in the oil exploitation, the gas-water flow in the coalbed methane recovery and the steam-water flow in the geothermal energy development. Consequently, the two-phase flow in fractures are required to be better understood. Existing studies on two-phase flow include the displacement mechanisms and simultaneous flow of two phases in the fractures or porous media. For the simultaneous two-phase flow, the flow characteristics in a single fracture are well investigated by many researchers. Different from the single-phase flow, the two-phase flow in the fracture is not only influenced by the coherent fracture properties like the fracture roughness, but the gas-water interactions (Corey, 1954; Dana, 1999; Dong, 2008). However, the two-phase flow characteristics in fracture networks or the intersecting fracture still remain to be deeply investigated. Due to the inertial effect and the turbulence induced energy loss, fluid flow in the intersecting fracture shows quite different properties to that in the single fracture. At a fracture intersection, the inertial effect usually induces backflow regions, and correspondingly induces nonlinearity of flow. Even in laminar flow state, the flow’s nonlinearity exists due to the influence of the fracture intersection (Kosakowski and Berkowitz, 1999). On the other hand, available studies on two-phase flow in intersections mainly focus on the separation of two phases, which is induced by the inertia difference of two phases (Seeger et al, 1986; Li et al, 2017); but less studies are conducted on the hydraulic properties of two-phase flow in intersecting fractures. This is because two-phase flow is turbulent in most cases, and the mechanism of the flow nonlinearity induced by the intersection, such as the backflow, cannot be directly studied by Navier-Stokes equation (NS equation). About the two-phase flow in the fracture network, though the NS equation and VOF method can simulate the two-phase flow in the fracture network (Zhang et al, 2018), the NS equation cannot account for the nonlinearity and additional energy loss induced by the interactions between two phases in the turbulent state, especially at the fracture intersections. Consequently, the influence mechanisms of fracture intersections on the hydraulic characteristics of two-phase flow are still not well understood. As a basis for studying the gas-water flow in the fracture networks, an experiment was conducted in a 3D smooth intersecting fracture model to obtain the pressure-drop characteristics. This experiment provides a basis for further studies to understand the flow behavior in the fracture network.
During hydraulic fracturing, the interaction of hydraulic fractures with natural fractures can result in the formation of complex fracture networks. In the past these interactions have been captured in hydraulic fracturing models using crossing criteria developed based on two-dimensional geometries. In this work, we investigate the interaction of hydraulic fractures and natural fractures in three-dimensions and demonstrate that there can be significant differences in the observed interactions.
A hydraulic fracturing simulator is presented that solves the coupled fluid flow and geomechanics problem for three-dimensional fractures. The simulator captures the physics of fracture growth and the intersection of hydraulic fracture with pre-existing discrete fracture network. The model employs a robust algorithm to account for the stress relaxation due to the slippage of natural fractures. The displacement of failed natural fracture elements is calculated rigorously. The model allows the partial failure of three-dimensional natural fractures and accurately calculates the stresses acting on the plane of the natural fracture.
It is shown that a natural fracture inclined at an angle to an approaching hydraulic fracture experiences compression in one region (due to the stress shadow of the growing hydraulic fracture) and tension in other regions (in front of the approaching hydraulic fracture tip). The generated stresses can fail the natural fracture partially. The failure of the natural fracture relaxes the stresses around it, which can modify the direction of propagation of the approaching hydraulic fracture. In addition, if the elliptical front of the hydraulic fracture crosses an intact planar natural fracture, the three-dimensional geometry results in a line of intersection (between natural fracture and hydraulic fracture). This can lead to failure of the natural fracture even after the elliptical front has partially crossed the natural fracture. Such an interaction can allow the hydraulic fracture to both cross the natural fracture and activate (or dilate) it. These effects cannot be captured by two-dimensional simulations. This work improves our understanding of the interaction between hydraulic fractures and natural fractures. The novel results provide new insights into the mechanisms responsible for the complexity that is often observed in hydraulic fractures.