Appendix B: How we Use Various Seismic Attributes to Predict Natural Fracture Intensity in the Subsurface, After Nelson (2006)

Summary The Duvernay Formation is an unconventional reservoir characterized by induced seismicity and fluid migration, with natural fractures likely contributing to both cases. An alpine outcrop of the Perdrix and Flume formations, correlative with the subsurface Duvernay and Waterways formations, was investigated to characterize natural fracture networks. A semiautomated image-segmentation and fracture analysis was applied to orthomosaics generated from a photogrammetric survey to assess small- and large-scale fracture intensity and rock mass heterogeneity. The study also included manual scanlines, fracture windows, and Schmidt hammer measurements. The Perdrix section transitions from brittle fractures to en echelon fractures and shear-damage zones. Multiple scales of fractures were observed, including unconfined, bedbound fractures, and fold-relatedbed-parallel partings (BPPs). Variograms indicate a significant nugget effect along with fracture anisotropy. Schmidt hammer results lack correlation with fracture intensity. The Flume pavements exhibit a regionally extensive perpendicular joint set, tectonically driven fracturing, and multiple fault-damage zones with subvertical fractures dominating. Similar to the Perdrix, variograms show a significant nugget effect, highlighting fracture anisotropy. The results from this study suggest that small-scale fractures are inherently stochastic and that fractures observed at core scale should not be extrapolated to represent large-scale fracture systems; instead, the effects of small-scale fractures are best represented using an effective continuum approach. In contrast, large-scale fractures are more predictable according to structural setting and should be characterized robustly using geological principles. This study is especially applicable for operators and regulators in the Duvernay and similar formations where unconventional reservoir units abut carbonate formations.

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High-resolution stratigraphic characterization of natural fracture attributes in the Woodford Shale, Arbuckle Wilderness and US-77D Outcrops, Murray County, Oklahoma

Interpretation ◽

10.1190/int-2017-0056.1 ◽

2018 ◽

Vol 6 (1) ◽

pp. SC29-SC41 ◽

Cited By ~ 3

Author(s):

Sayantan Ghosh ◽

John N. Hooker ◽

Caleb P. Bontempi ◽

Roger M. Slatt

Keyword(s):

Natural Fracture ◽

Fracture Aperture ◽

Aperture Size ◽

Fracture Density ◽

Area Formula ◽

Woodford Shale ◽

Fracture Spacing ◽

Spacing Ratio ◽

Fracture Intensity ◽

Bed Thickness

Natural fracture aperture-size, spacing, and stratigraphic variation in fracture density are factors determining the fluid-flow capacity of low-permeability formations. In this study, several facies were identified in a Woodford Shale complete section. The section was divided into four broad stratigraphic zones based on interbedding of similar facies. Average thicknesses and percentages of brittle and ductile beds in each stratigraphic foot were recorded. Also, five fracture sets were identified. These sets were split into two groups based on their trace exposures. Fracture linear intensity (number of fractures normalized to the scanline length [[Formula: see text]]) values were quantified for brittle and ductile beds. Individual fracture intensity-bed thickness linear equations were derived. These equations, along with the average bed thickness and percentage of brittle and ductile lithologies in each stratigraphic foot, were used to construct a fracture areal density (number of fracture traces normalized to the trace exposure area [[Formula: see text]]) profile. Finally, the fracture opening-displacement size variations, clustering tendencies, and fracture saturation were quantified. Fracture intensity-bed thickness equations predict approximately 1.5–3 times more fractures in the brittle beds compared with ductile beds at any given bed thickness. Parts of zone 2 and almost entire zone 3, located in the upper and middle Woodford, respectively, have high fracture densities and are situated within relatively organic-rich (high-GR) intervals. These intervals may be suitable horizontal well landing targets. All observed fracture cement exhibit a lack of crack-seal texture. Characteristic aperture-size distributions exist, with most apertures in the 0.05–1 mm (0.00016–0.0032 ft) range. In the chert beds, fracture cement is primarily bitumen or silica or both. Fractures in dolomite beds primarily have calcite cement. The average fracture spacing indices (i.e., bed thickness-fracture spacing ratio) in brittle and ductile beds were determined to be 2 and 1.2, respectively. Uniform fracture spacing was observed along all scanlines in the studied beds.

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The Stratigraphy of Pre-Tertiary Economic Basement in South Jambi B Block, South Sumatra Basin

10.29118/ipa21-g-271 ◽

2021 ◽

Keyword(s):

Significant Contribution ◽

Fracture Network ◽

Natural Fracture ◽

Fracture Density ◽

The South ◽

The North ◽

Fracture Intensity ◽

Parent Rocks ◽

Major Fault ◽

Essential Function

As one of the most promising plays, the Pre-Tertiary basement play holds a significant contribution to the latest success of exploration efforts in the South Sumatra Basin, which then includes the South Jambi B Block. Yet, the natures of the Pre-Tertiary unit in this block remains unsolved. Lithology variability, spatial irregularity, genetic ambiguity, and different reservoir characteristic are indeterminate subjects in the block are the main focus here. The ultimate goals of this study are to better characterize the unit and gain more understanding in calibrating the remaining potential. Based on this study, The Pre-Tertiary units are mainly originated from layered marine-deltaic sedimentary parent rocks with carbonate, intruded by spotty granite where the concentration of each parent rocks varies at the north, the middle, and southern part. Secondly, both lithology heterogeneity and natural fracture density create distinctive reservoir deliverability at each structure. The storage concept is an essential function of natural fracture intensity and diversity, supported by matrix porosity that varies across a different succession of lithology. Lastly, this study observes that major fault orientation is essential in constructing the fracture network. Evidence from several image logs across the study area concludes that most of the interpreted fractures are oriented subparallel to the major faults. The northern belt area is relatively affected by NW-SE Neogene structure, where the southern area is recognized to be affected by both Neogene compression and pre-existing Paleogene structure.

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Factors influencing fractures networks within Permian shale intervals in the Cooper Basin, South Australia

The APPEA Journal ◽

10.1071/aj11016 ◽

2012 ◽

Vol 52 (1) ◽

pp. 213 ◽

Cited By ~ 2

Author(s):

Hani Abul Khair ◽

Guillaume Backé ◽

Rosalind King ◽

Simon Holford ◽

Mark Tingay ◽

...

Keyword(s):

Compressive Strength ◽

Positive Curvature ◽

Seismic Attributes ◽

Gas Production ◽

Natural Fracture ◽

Seismic Survey ◽

Critical Parameters ◽

Fracture Density ◽

High Fracture ◽

Cooper Basin

The future success of both enhanced (engineered) geothermal systems and shale gas production is reliant on the development of reservoir stimulation strategies that suit the local geo-mechanical conditions of the prospects. The orientation and nature of the in-situ stress field and pre-existing natural fracture networks in the reservoir are among the critical parameters that will control the quality of the stimulation program. This study provides a detailed investigation into the nature and origin of natural fractures in the area covered by the Moomba–Big Lake 3D seismic survey, in the southwest termination of the Nappamerri Trough of the Cooper Basin. These fractures are imaged by both borehole image logs and complex multi-traces seismic attributes (e.g. dip-steered most positive curvature and dip-steered similarity), are pervasive throughout the cube, and exhibit a relatively consistent northwest–southeast orientation. Horizon extraction of the seismic attributes reveal a strong variation in the spatial distribution of the fractures. In the acreage of interest, fracture density is at its highest in the vicinity of faults and on top of tight antiforms. This study also suggests a good correlation between high fracture density and high gamma ray values. The correlation between high fracture density and shale content is somewhat counterintuitive, as shale is expected to have a higher tensile and compressive strengths at shallow depths and typically contain fewer fractures (Lin, 1983). At large depths, however—and due to sandstone diagenesis and cementation—shale has lower tensile and compressive strength than sandstone and is expected to be more fractured (Lin, 1983). A similar correlation has been noted in other Australian Basins (e.g. Northern Perth Basin). Diagenetic effects, pore pressure, stiffness, variations in tensile versus compressive strength of the shale and the sandstone may explain this disparity.

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Correlating distributed acoustic sensing (DAS) to natural fracture intensity for the Marcellus Shale

10.1190/segam2017-17675576.1 ◽

2017 ◽

Cited By ~ 2

Author(s):

Payam Kavousi ◽

Timothy Carr ◽

Thomas Wilson ◽

Shohreh Amini ◽

Collin Wilson ◽

...

Keyword(s):

Marcellus Shale ◽

Natural Fracture ◽

Acoustic Sensing ◽

Fracture Intensity ◽

Distributed Acoustic Sensing

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Impact of lithofacies variations and structural changes on natural fracture distributions

Interpretation ◽

10.1190/int-2017-0138.1 ◽

2018 ◽

Vol 6 (4) ◽

pp. T873-T887 ◽

Cited By ~ 14

Author(s):

Benmadi Milad ◽

Roger Slatt

Keyword(s):

Seismic Data ◽

Horizontal Well ◽

Natural Fracture ◽

3D Seismic ◽

Natural Fractures ◽

Structural Effects ◽

Thin Sections ◽

Fracture Intensity ◽

The Impact ◽

3D Seismic Data

Understanding and predicting the impact of lithofacies changes and structural effects on fracture distributions is vitally important to optimize a drilling location and orientation. To evaluate and model fracture intensity of the Late Ordovician-Silurian-Early Devonian Hunton Group carbonates in Oklahoma, natural fractures were studied at different scales using borehole images, three outcrops (two horizontally bedded outcrops and one anticline outcrop), and seismic data. Natural fractures identified from eight horizontal well borehole images include conductive (open), partially open, mineralized (closed), and induced fractures. Four fracture sets were identified from borehole images and from the two horizontally bedded outcrops. A 3D fracture intensity model was populated, from the fracture intensity logs at the boreholes, and compared with a 3D lithofacies model. Principal component analysis from lithology logs produced input to a self-organizing map to classify and cluster electrofacies. Thin sections and borehole images corroborate the electrofacies around the wellbores, whereas 3D seismic data were used as constraints to build a 3D lithofacies model. A 3D lithofacies model resulted from the extrapolation of the lithofacies from the well scale to the regional seismic scale. In this study area, lithofacies and structure are interrelated and control fracture distributions. Lithofacies is the primary control, whereas structure is the secondary control. Three lithofacies (wackestone, mudstone, and mud-dominated wackestone) were identified. A positive relationship between the fracture intensity and the presence of wackestone was observed at well locations and in the mapped subsurface area. The other two lithofacies do not exhibit high fracture abundance. Structural effects influence fracture distributions near faults and positive curvature areas in the subsurface measured on the 3D seismic data. For the Hunton Anticline outcrop exposure, there was a positive linear relationship between fracture intensity and changes in curvature for the mudstone and mud-dominated wackestone and an exponential relationship for the wackestone textures. The integration of lithology and structure from multidisciplinary, multiscalar data (i.e., outcrops, image logs, and 3D seismic) helps to identify and predict the fractured zones in the Hunton carbonates and can be used for horizontal well planning as well as stimulation programs. More importantly, this study proposes a generic model to predict the variability of fractures at different scales of curvatures combined with lithology changes and can be used for other carbonate reservoirs.

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Seismic data conditioning and orthotropic rock-physics-based inversion of wide-azimuth P-wave seismic data for fracture and total organic carbon characterization in a north Kuwait unconventional reservoir

Geophysics ◽

10.1190/geo2017-0673.1 ◽

2018 ◽

Vol 83 (4) ◽

pp. B229-B240 ◽

Cited By ~ 6

Author(s):

Rajive Kumar ◽

Prashant Bansal ◽

Bader S. Al-Mal ◽

Sagnik Dasgupta ◽

Colin Sayers ◽

...

Keyword(s):

Organic Carbon ◽

Total Organic Carbon ◽

Seismic Data ◽

Rock Physics ◽

Seismic Inversion ◽

P Wave ◽

Natural Fracture ◽

Reservoir Properties ◽

Fluid Saturation ◽

Fracture Intensity

Optimization of production from unconventional reservoirs requires estimates of reservoir properties such as porosity, total organic carbon (TOC) content, clay content, fluid saturation, and fracture intensity. The porosity and TOC content help to determine reservoir quality, and the natural fracture intensity provides information important for the completion strategy. Because shale reservoirs display intrinsic anisotropy due to layering and the partial alignment of clay minerals and kerogen with the bedding plane, the minimum acceptable representation of the anisotropy of naturally fractured shale-gas reservoirs is orthotropy, in which a set of vertical compliant fractures is embedded in a vertical transverse isotropic (VTI) background medium. Full-azimuth seismic data are required to characterize such reservoirs and to invert for the anisotropic elastic properties. Orthotropic inversion uses azimuthally sectored seismic data stacked according to the incident angle. Even for high-fold acquisition, this azimuth/angle grouping can result in low-fold angle stacks. Orthotropic amplitude-variation-with-offset-and-azimuth (AVOAz) inversion requires seismic preconditioning techniques that ensure proper primary amplitude preservation, noise attenuation, and data alignment, and a workflow implemented for the construction of an orthotropic rock-physics model. This model integrates well and core data to estimate reservoir properties using the results of the AVOAz inversion. The seismic inversion results include the P- and S-impedance and parameters quantifying the azimuthal anisotropy. The rock model assumes a VTI kerogen-rich layer, containing aligned vertical fractures, and it uses prestack orthotropic AVOAz inversion results to predict porosity, TOC, and fracture intensity.

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Relationships between lineal fracture intensity and chemical composition in the Marcellus Shale, Appalachian Basin

Interpretation ◽

10.1190/int-2018-0221.1 ◽

2019 ◽

Vol 7 (4) ◽

pp. SJ33-SJ43 ◽

Cited By ~ 1

Author(s):

Keithan G. Martin ◽

Liaosha Song ◽

Payam Kavousi ◽

Timothy R. Carr

Keyword(s):

Chemical Composition ◽

Marcellus Shale ◽

Negative Relationship ◽

Natural Fracture ◽

Filling Material ◽

Natural Fractures ◽

Rock Composition ◽

Hydraulic Stimulation ◽

Fracture Intensity ◽

The Relationship

Within mudrock reservoirs, brittle zones undergo failure during hydraulic stimulation, creating numerous artificial fractures which enable hydrocarbons to be liberated from the reservoir. Natural fractures in mudrock reduce the tensile strength of the host rock, creating planes of weaknesses that are hypothesized to be reactivated during hydraulic stimulation. Combined, brittleness and natural fractures contribute to creating more abundant and complex fracture networks during hydraulic stimulation. Research efforts toward quantifying rock brittleness have resulted in numerous mineral-/compositional-based indices, which are used during petrophysical analysis to predict zones most conducive to hydraulic stimulation. In contrast, investigations on the relationship between chemical composition and core-scale natural fractures are limited. For this study, we collected high-resolution energy-dispersive X-ray fluorescence (XRF) data, calibrated with a wave-dispersive XRF, from a Marcellus Shale core. Additionally, we characterized corescale natural fractures in terms of length, width, in-filling material or lack thereof, and orientation. Following the characterization, we transformed the natural fracture data into a continuous P10 (lineal fracture intensity) curve, expressed as the number of fractures per a one-half foot window. Using these data sets, we investigated the relationship between rock composition and natural fracture intensity. Regression analyses recorded positive relationships between natural fracture intensity and calcium, silicon/aluminum, and total organic carbon (TOC), and negative relationships with silicon and aluminum. Aluminum recorded the strongest (negative) relationship ([Formula: see text]) with natural fracture intensity. To access the degree to which natural fractures can be predicted based on chemical composition, we applied a partial least-squares analysis, a multivariate method, and recorded an [Formula: see text]. Our study illustrates that although numerous factors are responsible for natural fracture genesis, such fractures predictively concentrate in areas of similar chemical composition, largely in zones with low aluminum concentrations.

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Fracture Characterization in Deep Gas Reservoirs to Identify Fracture Enhanced Flow Units, Offshore Abu Dhabi

10.2118/207646-ms ◽

2021 ◽

Author(s):

Jialiang Hu ◽

Pradeep Menon ◽

Amna Al Yaqoubi ◽

Mohamed Al Shehhi ◽

Mahmoud Basioni ◽

...

Keyword(s):

Large Scale ◽

Poisson Ratio ◽

Fracture Network ◽

Open Fractures ◽

Natural Fracture ◽

Abu Dhabi ◽

Small Scale ◽

Upward Movement ◽

Flow Units ◽

Fracture Intensity

Abstract High gas flow rates in deep-buried dolomitized reservoir from an offshore field Abu Dhabi cannot be explained by the low matrix permeability. Previous permeability multiplier based on distance to major faults is not a solid geological solution due to over-simplifying reservoir geomechanics, overlooking folding-related fractures, and lack of detailed fault interpretation from poor seismic. Alternatively, to characterize the heterogeneous flow related with natural fractures in this undeveloped reservoir, fracture network is modelled based on core, bore hole imager (BHI), conventional logs, seismic data and test information. Limited by investigation scale, vertical wells record apparent BHI, and raw fracture interpretation cannot represent true 3D percolation reflected on PLT. To overcome this shortfall, correction based on geomechanics and mechanical layer (ML) analysis is performed. Young's modulus (E), Poisson ratio (ν), and brittleness index are calculated from logs, describing reservoir tendency of fracturing. Other than defining MLs, bedding plane intensity from BHI is also used as an indicator of fracture occurrence, since stress tends to release at strata discontinuity and forms bed-bounded fractures observed from cores. Subsequently, a new fracture intensity is generated from combined geomechanics properties and statistics average of BHI-derived fracture occurrence within the ML frame, which improves match with PLT and distinguishes fracture enhance flow intervals consistently in all wells. Seismic discontinuity attributes are used as static fracture footprints to distribute fractures from wells to 3D. The final hybrid DFN comprises large-scale deterministic zone-crossing fractures and small-scale stochastic bed-bounded fractures. Sub-vertical open fractures are dominated by NE-SW wrenching fractures related with Zagros compression and reactive salt upward movement. There is no angle rotation of fractures in different fault blocks. Open fractures in other strikes are supported by partial cements and mismatching fracture walls on computerized tomography (CT) images. ML correlation shows vertical consistence across stratigraphic framework and its intensity indicates fracture potential of vertical zones reflected by tests. Fracture-enhanced flow units are further constrained by a threshold in both combined geomechanics properties and statistics average of raw BHI fracture intensity in ML frame. As a result, final fracture network maps reservoir brittleness and flow potential both vertically and laterally, identifying fracture regions along folding axis not just major faults, evidenced by wells and seismic. According to the upscaling results, the case study reveals a type-III fractured reservoir, where fractures contribute to flow not to volume. Fracture network enhances bed-wise horizontal communication but also opens vertical feeding channels. Fracture permeability is mainly influenced by aperture and intensity, while aspect ratio, fracture length, and proportion of strikes and dips mainly influence permeability distribution rather than absolute values. This study provides a production-oriented characterization workflow of natural fracture heterogeneity based on correction of raw BHI in undeveloped fields.

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