Multiple Fracture Sets Research Articles

Seismic Shear Wave Anisotropy in Cracked Rocks and an Application to Hydraulic Fracturing

AbstractSubsurface rocks often contain cracks/fractures with various orientations: aligned, conjugated, and randomly oriented, giving rise to different types of seismic anisotropy. We develop an effective approach for the elastic wave‐scattering theory to accurately calculate anisotropic properties in the presence of single and/or multiple fracture sets. Two specific models, the equivalent aligned crack system and the equivalent orthogonal crack system, are considered for the calculations. The equivalent aligned crack system generates significant anisotropy, while the equivalent orthogonal crack system exhibits weak anisotropy due to the interaction of cracks with different orientations. The theory is applied to interpret acoustic anisotropy measurements acquired in hydraulically fractured formations, where theoretical predictions and measurements are in good agreement.

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.

Elastic wave propagation in fractured media using the discontinuous Galerkin method

We have formulated and implemented a discontinuous Galerkin method (DGM) for elastic wave propagation that allows for discontinuities in the displacement field to simulate fractures or faults. The approach is based on the interior-penalty formulation of DGM, and the fractures are simulated using the linear-slip model, which is incorporated into the weak formulation by including an additional term that is similar to the penalty term but uses the fracture compliance instead of an arbitrary penalty parameter. We have calibrated our results against an analytic solution of fracture-induced anisotropy for a set of elongated horizontal fractures, and we have evaluated numerical examples that simulate the reflection and transmission of waves at a fracture and at fracture interface waves. This method can further be used with models containing intersecting fractures and multiple fracture sets in 2D or 3D domains.

New insights into lithology and hydrogeology of the northern Newark Rift Basin

AbstractThe marginal facies of the Triassic rift basins in the eastern United States are poorly documented, particularly on the hinge or hanging wall margins. This study presents a lithological description and multiscale petrophysical analysis of basement rocks, overlying marginal facies of the early synrift strata, and the basal contact of the Palisade Sill that were drilled and cored in the northeastern part of the Newark Basin, near its terminus. The expression of the Stockton Formation differs from that in the central basin in having thinner layers, with uncertain temporal relationship to the type area. The bottom 50 m is lithologically distinct with brick‐red to dark‐purple mudstones and sandstones, abundant gypsum‐filled fractures, and a thin zone with anomalously high uranium concentration, not associated with organic‐rich mudstones as other occurrences in the basin. The crystalline basement is apparently Fordham gneiss, overlain by a thin sandstone layer and a dark‐purple hydrophilic mudstone. Despite the abundance of coarse‐grained strata and multiple sets of tectonic fractures, hydraulically transmissive zones are sparse, and do not uniquely correlate to fracture and/or matrix characteristics. Enhanced transmissivity may exist along intrusion boundaries due to enhanced thermal fracturing, but more hydraulic data are needed to verify it. Comparison of petrophysical data in two boreholes ∼210 m apart shows no direct correlation of individual lithological units and their hydraulic properties, although the overall formation characteristics are similar. The results highlight challenges for outcrop correlation at the marginal edges of the rift basins and estimating reservoir properties of these heterogeneous formations.

Monitoring hydraulic fracturing complexity and containment with time-lapse, multi-component and microseismic data, Pouce Coupe, Alberta

Fracture complexity occurs when the hydraulic fracturing process causes multiple sets of natural fractures to open in a reservoir. Keeping these sets open is another problem as they must be propped to stay open and communicate with the well bore. Fracture complexity can be monitored and it could have a significant effect on well orientations and completions. Stresses and natural fractures can create conditions favourable for generating multiple fracture sets. Generally, if we can tell where the natural fractures are prior to the drilling and completions, we can take advantage of the natural fractures to increase effective permeability and create greater conductivity to the well bore. Monitoring to see if the fractures are propped and remain conductive over time can be accomplished with shear wave splitting and birefringence. Hydraulic fracture containment during the hydraulic fracturing process is especially relevant to optimizing the effectiveness of hydraulic fracture treatments. Many reservoirs have issues related to height growth and containment within the zone. Monitoring containment is important for purposes of increasing the recovery factor in shale reservoirs. Monitoring technologies can be used to assess containment issues associated with reservoirs affected by fault and natural fracture systems.

The Alegre Lineament and its role over the tectonic evolution of the Campos Basin and adjacent continental margin, Southeastern Brazil

The structural framework and tectonic evolution of the sedimentary basins along the eastern margin of the South American continent are closely associated with the tectonic framework and crustal heterogeneities inherited from the Precambrian basement. However, the role of NW-SE and NNW-SSE structures observed at the outcropping basement in Southeastern Brazil and its impact over the development of those basins have not been closely investigated. In the continental region adjacent to the Campos Basin, we described a geological feature with NNW-SSE orientation, named in this paper as the Alegre Fracture Zone (AFZ), which is observed in the onshore basement and can be projected to the offshore basin. The main goal of this work was to study this structural lineament and its influence on the tectonic evolution of the central portion of the Campos Basin and adjacent mainland. The onshore area was investigated through remote sensing data joint with field observations, and the offshore area was studied through the interpretation of 2-D seismic data calibrated by geophysical well logs. We concluded that the AFZ occurs in both onshore and offshore as a brittle deformation zone formed by multiple sets of fractures that originated in the Cambrian and were reactivated mainly as normal faults during the rift phase and in the Cenozoic. In the Campos Basin, the AFZ delimitates the western side of the Corvina-Parati Low, composing a complex fault system with the NE-SW faults and the NW-SE transfer faults.

Mapping folds and fractures in basement and cover rocks using UAV photogrammetry, Cape Liptrap and Cape Paterson, Victoria, Australia

Brittle and ductile deformation of alternating layers of Devonian sandstone and mudstone at Cape Liptrap, Victoria, Australia, resulted in upright folds with associated fold accommodation faults and multiple fracture sets. Structures were mapped at the Fold Stack locality at Cape Liptrap using high-resolution aerial photographs acquired by a digital camera mounted on an unmanned aerial vehicle (UAV). Subsequent photogrammetric modelling resulted in georeferenced spatial datasets (point cloud, digital elevation model and orthophotograph) with sub-cm resolution and cm accuracy, which were used to extract brittle and ductile structure orientation data. An extensive dataset of bedding measurements derived from the dense point cloud was used to compute a 3D implicit structural trend model to visualise along-strike changes of Devonian (Tabberabberan) folds at the Fold Stack locality and to estimate bulk shortening strain. This model and newly collected data indicate that first generation shallowly south-southwest plunging upright folds were gently refolded about a steeply plunging/subvertical fold axis during a Devonian low-strain north–south shortening event. This also led to the local tightening of first generation folds and possibly strike-slip movement along regional scale faults. In order to distinguish fractures associated with Devonian compression from those that formed during Cretaceous extension and later inversion, we compared the five fracture sets defined at Cape Liptrap to previously mapped joints and faults within the overlying sedimentary cover rocks of the Cretaceous Strzelecki Group (Gippsland Basin), which crop out nearby. An east-southeast trending fracture set that is not evident in the Strzelecki Group can be linked to the formation of Devonian folds. Additionally, hinge line traces extracted from the Fold Stack dataset are aligned parallel to a dominant fracture set within the overlying cover sediments. This suggests that basement structures (folds and coeval parallel faults) have an important influence on fault and joint orientations within Cretaceous cover rocks.

A study of changes in deep fractured rock permeability due to coupled hydro-mechanical effects

This paper presents a numerical study of the hydro-mechanical behaviour of a fractured rock domain at 1000m depth below the land surface as a function of different levels of fluid pore pressure. A 2D fractured rock domain is adopted based on data obtained from outcrop mapping, displaying multiple fracture sets, fracture intersections, dead-end and curved fractures. A continuum based numerical model is used to evaluate the effects of compressive boundary stresses, cracking by tension failure in the intact rock and fractures and shear displacement along fractures on its equivalent permeability. Two in situ stress boundary conditions are considered: an isotropic case SR1 with the two horizontal boundary compressive stresses having the same magnitude, and an anisotropic case SR2 with the ratio between these compressive stress components set to be 2. In the SR2 case, changes in the local stress and stress ratio distributions due to different fluid pore pressure levels are anisotropic and more significant than in the SR1 case, because of tension failures in the intact rock forming bridges between fractures. These failure regions opened new flow connections between fractures and thereby caused important anisotropic changes in the flow paths, and significant decrease in local gradients of fluid pore pressure. The equivalent permeability increases sharply when the fluid pore pressure is approximately 90% of the magnitude of the minimum stress at the boundaries of the fractured rock domain. Results show that the equivalent permeability of the fractured rock domain is most sensitive to the fractures normal stiffness, the permeability of the tension failure regions and the power-law exponent for permeability change.

Estimating the fracture density of small-scale vertical fractures when large-scale vertical fractures are present

Fractures in reservoirs significantly affect reservoir flow properties in subsequent years, which means that fracture characteristics such as preferred orientation, crack density or fracture compliance, what filling is in the fractures and so on are of great importance for reservoir development. When fractures are vertical, aligned and their dimensions are small relative to the seismic wavelength, the medium can be considered to be an equivalent horizontal transverse isotropic (HTI) medium. However, geophysical data acquired over naturally fractured reservoirs often reveal the presence of multiple fracture sets. We investigate a case where there are two vertical sets of fractures having differing length scales. One fracture set has length scale that is much smaller than the seismic wavelength but the other has length scale that is similar to the seismic wavelength. We use synthetic data to investigate the ability to infer the properties of the small-scale fractures in the presence of the large-scale fracture set. We invert for the Thomsen-type anisotropic coefficients of the small-scale fracture set by using the difference of the P wave amplitudes at two azimuths, which makes the inversion convex. Then we investigate the influence of the presence of the large-scale fractures on our ability to infer the properties of the small-scale fracture set. Surprisingly, we find that we can reliably infer the fracture density of the small-scale fractures even in the presence of large-scale fractures having significant compliance values. Although the inversion results for Thomsen-type anisotropic coefficients of small-scale fractures for one model are not good enough to figure out whether it is gas-filled or fluid-filled, we can find a big change of Thomsen-type anisotropic coefficient between the models in which small-scale fractures are filled with gas and fluid.

Applications of fractured continuum model to enhanced geothermal system heat extraction problems

This paper describes the applications of the fractured continuum model to the different enhanced geothermal systems reservoir conditions. The capability of the fractured continuum model to generate fracture characteristics expected in enhanced geothermal systems reservoir environments are demonstrated for single and multiple sets of fractures. Fracture characteristics are defined by fracture strike, dip, spacing, and aperture. The paper demonstrates how the fractured continuum model can be extended to represent continuous fractured features, such as long fractures, and the conditions in which the fracture density varies within the different depth intervals. Simulations of heat transport using different fracture settings were compared with regard to their heat extraction effectiveness. The best heat extraction was obtained in the case when fractures were horizontal. A conventional heat extraction scheme with vertical wells was compared to an alternative scheme with horizontal wells. The heat extraction with the horizontal wells was significantly better than with the vertical wells when the injector was at the bottom.

Impact of multi-set fracture pattern on the effective permeability of fractured porous media

Abstract In fractured porous media, a significant contribution to flow is made through fracture–matrix networks. These networks create flow channels which play an important role in overall fluid transport. Previous fracture simulation studies were mostly done with stochastic patterns. In contrast, the analysis of geomechanically generated discrete fracture data sets that closely render naturally occurring systems, whilst account for flow through matrix and fractures simultaneously was presented in this study. The used propagation algorithm provides similar results to physical experiments. The impact of multiple superposed fracture sets within geological formations, created by multiple deformation events, on the effective permeability has been analysed. A 2D fracture-matrix medium was simulated and effective permeability computed using a finite element based method. Specifically, the impact of certain detailed fracture characteristics, such as density, mean length, spacing, connectivity and matrix permeability on the flow was measured. Results indicated the increase of effective permeability in multiple-sets of fracture sets. Fractures superimposed at different angles to the main set, parallel to the flow, increase connectivity between main flowlines and neighbouring fracture clusters. Thus, an increase in connectivity leads to higher effective permeability of media and increased probability of percolation. Permeability anisotropy was also analysed in this study. An expression for the characterisation of anisotropic effective permeability was proposed and simulated permeability was compared to analytical predictions.

Seismic characterization of reservoirs with asymmetric fractures

Variations of reflection amplitude with offset and azimuth are sensitive to the presence of natural and induced fractures. We tested inversion for fracture compliance matrix components from wide azimuth noisy synthetic PP-reflection data. The model was a fractured reservoir with monoclinic symmetry, formed by two sets of vertical asymmetric fractures embedded in a VTI background. The fractures (joints) were assumed to be vertical, with noncircular shape and/or with asymmetric shear compliance. Results of synthetic inversion showed that an incorrect assumption about fracture shear symmetry (e.g., treating asymmetric fractures as rotationally invariant fractures) can cause considerable error in estimation of the fracture compliance matrix. Components of effective second- and fourth-rank fracture compliance matrices for a medium with monoclinic symmetry (which takes into account layering and multiple fracture sets) can be used as attributes related to the characteristics of the fractured medium. Monte Carlo simulation was used to test the effect of uncertainties in the a priori information (about background VTI parameters of unfractured rock), as they affect inversion for these attributes. According to this analysis, the direction of fast shear-wave polarization was inverted robustly in the Monte Carlo simulation. Although the average values of the components of fracture compliance matrices obtained from Monte Carlo simulation were in agreement with the actual values used for forward modeling, individual values obtained in Monte Carlo simulation were sensitive to uncertainties in the background properties in general. Because the elastic properties of background VTI media without fractures (or other azimuthally variable features) do not cause azimuthal changes in reflection coefficient variation with offset, simultaneous inversion for background properties and fracture tensor components require additional constraints.

Seismic characterization of naturally fractured reservoirs using amplitude versus offset and azimuth analysis

ABSTRACTP‐wave seismic reflection data, with variable offset and azimuth, acquired over a fractured reservoir can theoretically be inverted for the effective compliance of the fractures. The total effective compliance of a fractured rock, which is described using second‐ and fourth‐rank fracture tensors, can be represented as background compliance plus additional compliance due to fractures. Assuming monoclinic or orthotropic symmetry (which take into account layering and multiple fracture sets), the components of the effective second‐ and fourth‐rank fracture compliance tensors can be used as attributes related to the characteristics of the fractured medium. Synthetic tests indicate that using a priori knowledge of the properties of the unfractured medium, the inversion can be effective on noisy data, with S/N on the order of 2. Monte Carlo simulation was used to test the effect of uncertainties in the a priori information about elastic properties of unfractured rock. Two cases were considered with Wide Azimuth (WAZ) and Narrow Azimuth (NAZ) reflection data and assuming that the fractures have rotationally invariant shear compliance. The relative errors in determination of the components of the fourth‐rank tensor are substantially larger compared to the second‐rank tensor, under the same assumptions.Elastic properties of background media, consisting in horizontal layers without fractures, do not cause azimuthal changes in the reflection coefficient variation with offset. Thus, due to the different nature of these properties compared to fracture tensor components (which cause azimuthal anomalies), simultaneous inversion for background isotropic properties and fracture tensor components requires additional constraints.Singular value decomposition (SVD) and resolution matrix analysis can be used to predict fracture inversion efficacy before acquiring data. Therefore, they can be used to determine the optimal seismic survey design for inversion of fracture parameters. However, results of synthetic inversion in some cases are not consistent with resolution matrix results and resolution matrix results are reliable only after one can see a consistent and robust behaviour in inversion of synthetics with different noise levels.

Modelling electrical conductivity for earth media with macroscopic fluid‐filled fractures

ABSTRACTEffective‐medium theories for either highly conductive or more resistive electrical inclusions in a moderately conducting background medium are presented for modelling macroscopic (i.e., large‐scale) fluid‐filled fractures or cracks in a potential reservoir rock or granular medium. Conductive fluids are most often brine and the resistive fluids of interest are oil, gas, air and/or CO2. Novel features of the presentation for conductive fluids include results for both non‐interacting inclusions (using a Maxwell approximation) and for interacting inclusions (via a self‐consistent effective‐medium scheme). The anisotropic analysis is specifically designed to handle reservoirs with multiple orientations (usually three orthogonal sets) of oblate spheroidal cracks/fractures, while also having arbitrary aspect ratios. But these aspect ratios are strictly <1, thus excluding spherical pores and simple granular media – both already widely studied by others. Results show that the self‐consistent approximation depends on fracture aspect ratio α and that this approximation becomes important when fracture porosity is about φ= 1% for aspect ratio α≃ 0.05, or φ= 3% for aspect ratio α≃ 0.10. It is shown that the self‐consistent analysis is most important when the fractures have a very small aspect ratio — the inferred reason being that the fracture (or crack) number density (ρc≡φ/α) then becomes very high and the fracture relative spacing correspondingly very small for any fixed value of porosity (but with decreasing values of the aspect ratio). Hybrid methods (combining self‐consistent and non‐self consistent formulas) are also developed to deal with high volume fractions and multiple sets of fractures having different aspect ratios. Whenever possible and appropriate, the results are also compared to rigorous bounds, including the Wiener bounds and the Hashin‐Shtrikman bounds, in order to provide one type of partial validation of the methods being developed.

Characterizing and modeling natural fracture networks in a tight carbonate reservoir in the Middle East: A methodology

Fractured reservoirs are challenging to handle because of their high level of heterogeneity. In particular, natural fractures have a significant impact on well performance and water production. Therefore, understanding their significance through fracture characterization is helpful in well placement and field development. This paper presents a best practice methodology for building a 3D stochastic fracture model using a Middle Eastern tight carbonate field example. This model is generated through the analysis and integration of data including cores, borehole images (BHI), logs, mud losses, production logs, well test data and 3D seismic data. The impact of lithology on fracture occurrence was quantified based on rock-typing. Rock-types are distributed in a 3D geological model using a high resolution sequence stratigraphic framework. The length, dip angle and orientation of fractures, together with the shale content of the facies where they occur, were defined to sort the tectonic fractures from the non-tectonic (diagenetic) ones. It was found that multiple sets of tectonic diffuse fractures are generally associated with cleaner limestone units. Altogether, three sets of diffuse fractures were identified from BHI data: NE-SW, EW and NW-SE. In addition, large-scale fracture corridors, including sub-seismic faults identified from seismic analysis, were detected and calibrated with cores and BHI. The final model incorporates two scales of tectonic fractures with a direct bearing on field production behavior: diffuse fractures and large fracture corridors. Fracture calibration was performed using production logs and well production data. Permeability at wells was computed in the 3D fracture model and matched with real build-up data. These data were then used to propagate 3D fracture properties (fracture porosity, fracture permeability and equivalent block size) in the upscaled geological model, for constructing a full-field reservoir simulation model. Few changes of the fracture properties were needed to obtain a good history match, indicating that the fracture model produced is robust.

Fault linkage and damage zone architecture in tight carbonate rocks in the Suez Rift (Egypt): implications for permeability structure along segmented normal faults

Abstract A field study focusing on fracture systems in a fault linkage zone from the Suez Rift, Egypt, is presented to elucidate the role of fault linkage zones in the permeability structure of segmented normal faults in tight carbonate rocks. Fracture systems in the linking damage zone show significantly increased structural complexity compared to that typical of isolated faults. The linkage zone is characterized by high fracture frequencies and multiple fracture sets of different orientations. Notably, pervasive fracture corridors strike at high angles to the fault trend and are interpreted to have formed during the latest evolutionary stages of what is interpreted as a breached relay. The structural observations indicate that along segmented normal faults in carbonate rocks, fault linkage zones represents locations of progressively increased cross- and along-fault permeability through the stages of relay growth and breaching. Our findings, in combination with previously published work, indicate that fault linkage zones represent localized conduits not only for increased fluid flow across faults, but also (vertically) within fault zones. Appreciating this has wide-ranging implications for understanding fluid transport in carbonate rocks and other naturally fractured lithologies.

Characterizing production‐induced anisotropy of fractured reservoirs having multiple fracture sets

ABSTRACTSince natural fractures in petroleum reservoirs play an important role in determining fluid flow during production, knowledge of the orientation and density of fractures is required to optimize production. This paper outlines the underlying theory and implementation of a fast and efficient algorithm for upscaling a Discrete Fracture Network (DFN) to predict the fluid flow, elastic and seismic properties of fractured rocks. Potential applications for this approach are numerous and include the prediction of fluid flow, elastic and seismic properties for fractured reservoirs, model‐based inversion of seismic Amplitude Versus Offset and Azimuth (AVOA) data and the optimal placement and orientation of infill wells to maximize production. Given that a single fracture network may comprise hundreds of thousands of individual fractures, the sheer size of typical DFNs has tended to limit their practical applications. This paper demonstrates that with efficient algorithms, the utility of Discrete Fracture Networks can be extended far beyond mere visualization.

Seismic characterization of reservoirs with multiple fracture sets using velocity and attenuation anisotropy data

Abstract Knowledge about the spatial distribution of the fracture density and the azimuthal fracture orientation can greatly help in optimizing production from fractured reservoirs. Frequency-dependent seismic velocity and attenuation anisotropy data contain information about the fractures present in the reservoir. In this study, we use the measurements of velocity and attenuation anisotropy data corresponding to different seismic frequencies and azimuths to infer information about the multiple fracture sets present in the reservoir. We consider a reservoir model with two sets of vertical fractures characterized by unknown azimuthal fracture orientations and fracture densities. Frequency-dependent seismic velocity and attenuation anisotropy data is computed using the effective viscoelastic stiffness tensor and solving the Christoffel equation. A Bayesian inversion method is then applied to measurements of velocity and attenuation anisotropy data corresponding to different seismic frequencies and azimuth to estimate the azimuthal fracture orientations and the fracture densities, as well as their uncertainties. Our numerical examples suggest that velocity anisotropy data alone cannot recover the unknown fracture parameters. However, an improved estimation of the unknown fracture parameters can be obtained by joint inversion of velocity and attenuation anisotropy data.

Modeling elastic properties and assessing uncertainty of fracture parameters in the Middle Bakken Siltstone

A statistical rock-physics technique, based on well data that provides estimates and associated uncertainty of fracture density in the Middle Bakken Siltstone, is presented. Geologic and hydrocarbon-charging history of the Middle Bakken indicate multiple sets of fractures that justify treating this unit as elastically isotropic. The generalized n-phase self-consistent model relates the elastic properties to composition, matrix porosity, and fracture porosity, where an assigned aspect ratio and volumetric fraction corresponds to each input. The modeling of bulk density as a function of total porosity supplies deterministic estimates of the composition. Analysis of in situ stress and pore-stiffness calculations provide a range of fracture aspect ratios, corresponding to open fractures. Stochastic simulation of fracture porosity initiates the statistical nature of the technique. This treatment of fracture porosity enables the rock-physics model to be treated statistically through multiple realizations. Modeling results explain the measured bulk and shear moduli, with the bulk modulus more accurately described, and the results also provide statistical estimates of fracture porosity. Calculations using these estimates of fracture porosity, along with fracture aspect ratios, result in statistical estimates of fracture density for each depth value in the Middle Bakken unit. Values of fracture density fall within imposed limits (< 0.10). The results and technique demonstrated here could be applied to field seismic data to identify locations of increased fracture density. These locations might indicate areas of increased permeability in the Middle Bakken Siltstone.

Improved characterization of fault zones by quantitative integration of seismic and production data

This paper proposes a method for the parameterization and characterization of fault facies models including a fault core and a fault damage zone containing either fractures or deformation bands, typically associated with carbonate and sandstone reservoirs, respectively. We represent the faulted reservoir models with a relatively small number of parameters and focus on the inverse problem; that is, how to estimate transmissibility of the fault core and the parameters of the fractures or deformation bands that determine the effective stiffness and permeability tensors in the damage zone. Our workflow is based on a consistent stiffness-permeability model for the fractured or composite porous media in the damage zone, and a Bayesian (Monte Carlo Markov chain) method of inversion, which provides information about uncertainties as well as the most likely values of the model parameters. For simplicity, we have assumed that the damage zone consists of a single set of fractures or deformation bands that are parallel with the (vertical) fault core, but the forward modelling part of our workflow can easily be extended to deal with more complex situations involving multiple sets of fractures and/or deformation bands that are characterized by different shapes and orientations. The results of our numerical experiments suggest that one can indeed obtain an improved characterization of fault zones by quantitative integration of seismic AVAZ and production data using the workflow presented in this paper.