Large-scale natural fracture network patterns: Insights from automated mapping in the Lilstock (Bristol Channel) limestone outcrops

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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Modelling large-scale fractured reservoirs efficiently for geothermal energy and groundwater flow

10.5194/egusphere-egu2020-9278 ◽

2020 ◽

Author(s):

Simon Oldfield ◽

Mikael Lüthje ◽

Michael Welch ◽

Florian Smit

Keyword(s):

Fluid Flow ◽

Geothermal Energy ◽

Large Scale ◽

Fractured Reservoirs ◽

Fracture Network ◽

Natural Fracture ◽

Fracture Networks ◽

Persistent Problem ◽

Fracture Evolution ◽

Rapid Generation

Large scale modelling of fractured reservoirs is a persistent problem in representing fluid flow in the subsurface. Considering a geothermal energy prospect beneath the Drenthe Aa area, we demonstrate application of a recently developed approach to efficiently predict fracture network geometry across an area of several square kilometres.Using a strain based method to mechanically model fracture nucleation and propagation, we generate a discretely modelled fracture network consisting of individual failure planes, opening parallel and perpendicular to the orientation of maximum and minimum strain. Fracture orientation, length and interactions vary following expected trends, forming a connected fracture network featuring population statistics and size distributions comparable to outcrop examples.Modelled fracture networks appear visually similar to natural fracture networks with spatial variation in fracture clustering and the dominance of major and minor fracture trends.Using a network topology approach, we demonstrate that the predicted fracture network shares greater geometric similarity with natural networks. Considering fluid flow through the model, we demonstrate that hydraulic conductivity and flow anisotropy are strongly dependent on the geometric connection of fracture sets.Modelling fracture evolution mechanically allows improved representation of geometric aspects of fracture networks to which fluid flow is particularly sensitive. This method enables rapid generation of discretely modelled fractures over large areas and extraction of suitable summary statistics for reservoir simulation. Visual similarity of the output models improves our ability to compare between our model and natural analogues to consider model validation.

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Field experimental design for pesticide leaching – a modified large-scale lysimeter

Geological Survey of Denmark and Greenland Bulletin ◽

10.34194/geusb.v7.4830 ◽

2005 ◽

Vol 7 ◽

pp. 41-44

Author(s):

Bertel Nilsson ◽

Jens Aamand ◽

Ole Stig Jacobsen ◽

René K. Juhler

Keyword(s):

Large Scale ◽

Preferential Flow ◽

Fracture Network ◽

Transport Processes ◽

Natural Fracture ◽

Field Scale ◽

Flow Paths ◽

Undisturbed Soil ◽

Flow And Transport ◽

Preferential Flow Paths

Recent research on Danish groundwater has focused on clarifying the fate and transport of pesticides that leach through clayey till aquitards with low matrix permeability. Previously, these aquitards were considered as protective layers against contamination of underlying groundwater aquifers due to their low permeability characteristics. However, geological heterogeneities such as fractures and macropores have been recognised as preferential flow paths within low permeable clayey till (e.g. Beven & Germann 1982). The flow velocities within these preferential flow paths can be orders of magnitude higher than in the surrounding clay matrix and pose a major risk of transport of contaminants to the underlying aquifers (e.g. Nilsson et al. 2001). Previous studies of transport in fractured clayey till have focused on fully saturated conditions (e.g. Sidle et al. 1998; McKay et al. 1999). However, seasonal fluctuations of the groundwater table typically result in unsaturated conditions in the upper few metres of the clay deposits, resulting in different flow and transport conditions. Only a few experiments have examined the influence of unsaturated conditions on flow and solute (the dissolved inorganic and organic constituents) transport in fractured clayey till. These include smallscale laboratory column experiments on undisturbed soil monoliths (e.g. Jacobsen et al. 1997; Jørgensen et al. 1998), intermediate scale lysimeters (e.g. Fomsgaard et al. 2003) and field-scale tile drain experiments (e.g. Kjær et al. 2005). The different approaches each have limitations in terms of characterising flow and transport in fractured media. Laboratory studies of solute transport in soils (intact soil columns) are not exactly representative of field conditions due to variations in spatial variability and soil structure. In contrast, field studies hardly allow quantification of fluxes and mechanisms of transport. Column and lysimeter experiments are often limited in size, and tile-drain experiments on field scale do not provide spatial resolution and often have large uncertainties in mass balance calculations. Thus, in order to represent the overall natural fracture network systems on a field scale with respect to acquiring insights into flow and transport processes, the lysimeter needs to be larger than normal lysimeter size (< 1 m3). A modified large-scale lysimeter was therefore constructed by the Geological Survey of Denmark and Greenland (GEUS) at the Avedøre experimental field site 15 km south of Copenhagen (Fig. 1). This lysimeter consisted of an isolated block (3.5 ×3.5 ×3.3 m) of unsaturated fractured clayey till with a volume sufficient to represent the overall preferential flow paths (natural fracture network) within lowpermeable clayey till at a field scale.

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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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Numerical Simulation of Complex Fracture Network Development by Hydraulic Fracturing in Naturally Fractured Ultratight Formations

Volume 6: Polar and Arctic Sciences and Technology; Offshore Geotechnics; Petroleum Technology Symposium ◽

10.1115/omae2013-11084 ◽

2013 ◽

Cited By ~ 3

Author(s):

Hannes Hofmann ◽

Tayfun Babadagli ◽

Günter Zimmermann

Keyword(s):

Fracture Network ◽

Natural Fracture ◽

Fracture Networks ◽

Network Development ◽

Complex Fracture ◽

Fracture Patterns ◽

Fracture Systems ◽

Fracture Development ◽

Complex Fracture Network ◽

Treatment Designs

The creation of large complex fracture networks by hydraulic fracturing is imperative for enhanced oil recovery from tight sand or shale reservoirs, tight gas extraction, and Hot-Dry-Rock (HDR) geothermal systems to improve the contact area to the rock matrix. Although conventional fracturing treatments may result in bi-wing fractures, there is evidence by microseismic mapping that fracture networks can develop in many unconventional reservoirs, especially when natural fracture systems are present and the differences between the principle stresses are low. However, not much insight is gained about fracture development as well as fluid and proppant transport in naturally fractured tight formations. In order to clarify the relationship between rock and treatment parameters, and resulting fracture properties, numerical simulations were performed using a commercial Discrete Fracture Network (DFN) simulator. A comprehensive sensitivity analysis is presented to identify typical fracture network patterns resulting from massive water fracturing treatments in different geological conditions. It is shown how the treatment parameters influence the fracture development and what type of fracture patterns may result from different treatment designs. The focus of this study is on complex fracture network development in different natural fracture systems. Additionally, the applicability of the DFN simulator for modeling shale gas stimulation and HDR stimulation is critically discussed. The approach stated above gives an insight into the relationships between rock properties (specifically matrix properties and characteristics of natural fracture systems) and the properties of developed fracture networks. Various simulated scenarios show typical conditions under which different complex fracture patterns can develop and prescribe efficient treatment designs to generate these fracture systems. Hydraulic stimulation is essential for the production of oil, gas, or heat from ultratight formations like shales and basement rocks (mainly granite). If natural fracture systems are present, the fracturing process becomes more complex to simulate. Our simulation results reveal valuable information about main parameters influencing fracture network properties, major factors leading to complex fracture network development, and differences between HDR and shale gas/oil shale stimulations.

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Stochastic discrete fracture network modeling in shale reservoirs via integration of seismic attributes and petrophysical data

Interpretation ◽

10.1190/int-2020-0210.1 ◽

2021 ◽

pp. 1-50

Author(s):

Yongchae Cho

Keyword(s):

Seismic Data ◽

Stochastic Approach ◽

Fracture Network ◽

Natural Fracture ◽

Well Logs ◽

Fracture Model ◽

Well Log ◽

Discrete Fracture ◽

Discrete Fracture Network Modeling ◽

Fracture Network Modeling

The prediction of natural fracture networks and their geomechanical properties remains a challenge for unconventional reservoir characterization. Since natural fractures are highly heterogeneous and sub-seismic scale, integrating petrophysical data (i.e., cores, well logs) with seismic data is important for building a reliable natural fracture model. Therefore, I introduce an integrated and stochastic approach for discrete fracture network modeling with field data demonstration. In the proposed method, I first perform a seismic attribute analysis to highlight the discontinuity in the seismic data. Then, I extrapolate the well log data which includes localized but high-confidence information. By using the fracture intensity model including both seismic and well logs, I build the final natural fracture model which can be used as a background model for the subsequent geomechanical analysis such as simulation of hydraulic fractures propagation. As a result, the proposed workflow combining multiscale data in a stochastic approach constructs a reliable natural fracture model. I validate the constructed fracture distribution by its good agreement with the well log data.

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Modeling the Effect of a Natural Fracture Network and its Properties on Multi-Stage Stimulation

Proceedings of the 9th Unconventional Resources Technology Conference ◽

10.15530/urtec-2021-5285 ◽

2021 ◽

Author(s):

Branko Damjanac ◽

Maurilio Torres ◽

Christine Detournay

Keyword(s):

Fracture Network ◽

Natural Fracture ◽

Multi Stage

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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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How do we see fractures? Quantifying subjective bias in fracture data collection

10.5194/se-2018-135 ◽

2019 ◽

Author(s):

Billy J. Andrews ◽

Jennifer J. Roberts ◽

Zoe K. Shipton ◽

Sabina Bigi ◽

Maria C. Tartarello ◽

...

Keyword(s):

Data Collection ◽

Fracture Network ◽

Natural Fracture ◽

Minimum Length ◽

Considerable Variability ◽

Fracture Data ◽

Personal Bias ◽

Geological Models ◽

Subjective Bias ◽

The Impact

Abstract. The characterisation of natural fracture networks using outcrop analogues is important in understanding sub-surface fluid flow and rock mass characteristics in fractured lithologies. It is well known from decision-sciences that subjective bias significantly impacts the way data is gathered and interpreted. This study investigates the impact of subjective bias on fracture data collected using four commonly used approaches (linear scanlines, circular scanlines, topology sampling and window sampling) both in the field and in workshops using field photographs. Considerable variability is observed between each participant's interpretation of the same scanline, and this variability is seen regardless of geological experience. Geologists appear to be either focussing on the detail or focussing on gathering larger volumes of data, and this innate personality trait affects the recorded fracture network attributes. As a result, fracture statistics derived from the field data and which are often used as inputs for geological models, can vary considerably between different geologists collecting data from the same scanline. Additionally, the personal bias of geologists collecting the data affects the size (minimum length of linear scanlines, radius of circular scanlines or area of a window sample) required of the scanline that is needed to collect a statistically representative amount of data. We suggest protocols to recognise, understand and limit the effect of subjective bias on fracture data biases during data collection.

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