Peter H. Hennings

Combining Outcrop Data and Three-Dimensional Structural Models to Characterize Fractured Reservoirs: An Example from Wyoming

Combining a detailed outcrop characterization of fracture and fault occurrence with attributes from a three-dimensional model of an anticlinally folded clastic reservoir body, we determine which characteristics of the structural form and evolution are most closely related to the development of important reservoir-scale structures. Our example reservoir body studied is the Frontier Formation 1 sandstone in Oil Mountain, an asymmetric anticline on the western flank of Casper arch in central Wyoming. The three-dimensional model of the structure was constructed using an iterative scheme designed to maximize interpretation accuracy and precision. The model was analyzed to determine the spatial variance in morphologic and kinematic attributes. Using a quantitative testing approach, we found that the intensity of tectonically produced fractures is closely related spatially to rate of dip change and total curvature, with the former having the strongest correlation. This folding is a low-strain process compared to tear faulting, which has the strongest spatial correlation to larger strains. The location and magnitude of these higher strain areas can be adequately predicted by three-dimensional restoration and forward modeling of the upper bounding surface of the reservoir body. We use these results to build a predictive model for fault and fracture distribution at Oil Mountain and to discuss how this approach can aid in the exploitation of analogous producing reservoirs.

Improving curvature analyses of deformed horizons using scale-dependent filtering techniques

Fractures, which are common structural heterogeneities in geological folds and domes, impact the charge, seal, and trapping potential of hydrocarbon reservoirs. Because of their effects on reservoir quality, the numerical prediction of fractures has recently been the focus of petroleum geoscientists. A horizons curvature is commonly used to infer the state of deformation in those strata. It is assumed that areas of elevated calculated curvatures underwent elevated deformation, resulting in a concentration of fractures and faults there. Usually, curvatures are calculated from spatial data after sampling the continuous horizon at discrete points. This sampled geometry of the horizon includes surface undulations of all scales, which are then also included in the calculated curvatures. Including surface undulations of all scales in the curvature analysis leads to noisy and questionable results. We argue that the source data must be filtered prior to curvature analysis to separate different spatial scales of surface undulations, such as broad structures, faults, and sedimentary features. Only those surface undulations that scale with the problem under consideration should then be used in a curvature analysis. For the scale-dependent decomposition of spatial data, we test the suitability of four numerical techniques (Fourier [spectral] analysis, wavelet transform filtering, singular value decomposition, factorial kriging) on a seismically mapped horizon in the North Sea. For surfaces sampled over a regular grid (e.g., seismic data), Fourier (spectral) analysis extracts meaningful curvatures on the scale of broad horizon features, such as structural domes and basins.

Relationship between fractures, fault zones, stress, and reservoir productivity in the Suban gas field, Sumatra, Indonesia

It is becoming widely recognized that a relationship exists between stress, stress heterogeneity, and the permeability of subsurface fractures and faults. We present an analysis of the South Sumatra Suban gas field, developed mainly in fractured carbonate and crystalline basement, where active deformation has partitioned the reservoir into distinct structural and stress domains. These domains have differing geomechanical and structural attributes that control the permeability architecture of the field. The field is a composite of Paleogene extensional elements that have been modified by Neogene contraction to produce basement-rooted forced folds and neoformed thrusts. Reservoir-scale faults were interpreted in detail along the western flank of the field and reveal a classic oblique-compressional geometry. Bulk reservoir performance is governed by the local stress architecture that acts on existing faults and their fracture damage zones to alter their permeability and, hence, their access to distributed gas. Reservoir potential is most enhanced in areas that have large numbers of fractures with high ratios of shear to normal stress. This occurs in areas of the field that are in a strike-slip stress style. Comparatively, reservoir potential is lower in areas of the field that are in a thrust-fault stress style where fewer fractures with high shear-to-normal stress ratios exist. Achieving the highest well productivity relies on tapping into critically stressed faults and their associated fracture damage zones. Two wellbores have been drilled based on this concept, and each shows a three- to seven-fold improvement in flow potential.

Complex fracture development related to stratigraphic architecture: Challenges for structural deformation prediction, Tensleep Sandstone at the Alcova anticline, Wyoming

Fracture prediction in subsurface reservoirs is critical for exploration through exploitation of hydrocarbons. Methods of predicting fractures commonly neglect to include the stratigraphic architecture as part of the prediction or characterization process. This omission is a critical mistake. We have documented a complex heterogeneous fracture development within the eolian Tensleep Sandstone in Wyoming, which arguably is one of the least complex reservoir facies. Fractures develop at four scales of observation: lamina-bound, facies-bound, sequence-bound, and throughgoing fractures that span the formation. We documented a detailed facies and fracture-intensity model using LIDAR-scanned outcrops located at the Alcova anticline in central Wyoming. Through this characterization, we reveal the existence of a striking variability in fracture intensity caused by original depositional architecture, overall structural deformation, and diagenetic alteration of the host rock.

Damage and plastic deformation of reservoir rocks: Part 2. Propagation of a hydraulic fracture

The aim of part 2 is to understand the development of complex hydraulic fractures (HFs) that are commonly observed in the field and in experiments but are not explained by most models. Our approach uses finite element simulations and a numerical rheology developed in part 1 to model damage fracturing, the fracturing process by damage propagation in a rock with elastic–plastic damage rheology. Using this rheology and a dynamic solution technique, we investigate the effect of far-field stresses and pressure distribution in the fracture on the geometric complexity of the fractures. The model is for the vertical propagation of an HF segment into an overlying bed located far from borehole effects. The layer is 2.3 m (7.5 ft) tall, has elastic–plastic damage rheology, and contains a 0.3-m (1-ft)–tall initial vertical fracture. Vertical and horizontal tectonic loads of 50 MPa (7252 psi) and 10 to 45 MPa (1450–6527 psi) are established, and then an internal fracture pressure of 10 MPa/s (1450 psi/s) is applied until the layer fails. The simulated fracturing is sensitive to the stress state and generated patterns range from single straight fractures to treelike networks. Reducing differential stress increases the injection pressure required to fracture and promotes off-plane damage, which increases fracture complexity. Consecutive periods of nonuniform weakening followed by unstable rupture generate multiple branches and segments. We find that the processes that form HF complexity occur under a range of in-situ reservoir conditions and are likely to contribute to complex far-field fracture geometry and enhanced network connectivity.

A scaling law to characterize fault-damage zones at reservoir depths

We analyze fracture-density variations in subsurface fault-damage zones in two distinct geologic environments, adjacent to faults in the granitic SSC reservoir and adjacent to faults in arkosic sandstones near the San Andreas fault in central California. These damage zones are similar in terms of width, peak fracture or fault (FF) density, and the rate of FF density decay with distance from the main fault. Seismic images from the SSC reservoir exhibit a large basement master fault associated with 27 seismically resolvable second-order faults. A maximum of 5 to 6 FF/m (1.5 to 1.8 FF/ft) are observed in the 50 to 80 m (164 to 262 ft) wide damage zones associated with second-order faults that are identified in image logs from four wells. Damage zones associated with second-order faults immediately southwest of the San Andreas Fault are also interpreted using image logs from the San Andreas Fault Observatory at Depth (SAFOD) borehole. These damage zones are also 50–80 m wide (164 to 262 ft) with peak FF density of 2.5 to 6 FF/m (0.8 to 1.8 FF/ft). The FF density in damage zones observed in both the study areas is found to decay with distance according to a power law . The fault constant is the FF density at unit distance from the fault, which is about 10–30 FF/m (3.1–9.1 FF/ft) in the SSC reservoir and 6–17 FF/m (1.8–5.2 FF/ft) in the arkose. The decay rate ranges from 0.68 to 1.06 in the SSC reservoir, and from 0.4 to 0.75 in the arkosic section. This quantification of damage-zone attributes can facilitate the incorporation of the geometry and properties of damage zones in reservoir flow simulation models.

Multivariate fracture intensity prediction: Application to Oil Mountain anticline, Wyoming

The geometric characteristics of natural fractures significantly impact the hydraulic behavior of fractured reservoirs. Prediction of fracture geometry is therefore important for reservoir development decisions and production forecasting. Although many geometric, kinematic, mechanical, geomechanical, petrophysical, sedimentary, and geophysical attributes correlate to fracture intensity, typically, only the attribute with the highest absolute value correlation is chosen to be carried forward to influence prediction. We employ a geostatistical Bayesian updating approach that quantitatively accounts for multiple important attributes together impacting fracture geometry prediction. The resulting models are more representative of the true geological complexity. This methodology is applied to the Oil Mountain anticline outcrop near Casper, Wyoming.

A Method To Implement Permeability Anisotropy Associated With Fault Damage Zones in Reservoir Simulation

In this study, we present a method to incorporate the effects of fault damage zones (DZs) in a reservoir-simulation model. Permeability anisotropy associated with fault DZs depends on many factors, including the geometry of the faults in the reservoir and the associated dimension and density of fractures in the DZs. To model permeability anisotropy caused by fault DZs, we start by using geomechanically constrained discrete fracture models of DZs. Then, we use the orientation and size of the faults with reference to the grid axes to incorporate the effect of permeability anisotropy in the simulation grid. In this case study, in which faults are formed in an extensional regime, DZs show increased permeability along the strike of the fault and in the vertical direction, but there is no significant change in the permeability perpendicular to the faults. Inclusion of DZs in the simulation model shows significant improvement in the history matching in comparison to a base reservoir-simulation model with no DZs. Further, we analyze the uncertainty of the DZ modeling in the reservoir simulation by simulating multiple equiprobable models.