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

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.

Geomechanical and Fracture Network Interpretation of a Devonian Outcrop

2021 ◽  
pp. 1-16
Author(s):  
Scott McKean ◽  
Simon Poirier ◽  
Henry Galvis-Portilla ◽  
Marco Venieri ◽  
Jeffrey A. Priest ◽  
...  
Keyword(s):  
Large Scale ◽  
Multiple Scales ◽  
Fracture Network ◽  
Natural Fracture ◽  
Small Scale ◽  
Nugget Effect ◽  
Schmidt Hammer ◽  
Unconventional Reservoir ◽  
Fracture Anisotropy ◽  
Fracture Intensity

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.

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

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.

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

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

<p>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.</p><p>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.</p><p>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.</p><p>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.</p><p>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.</p>

scholarly journals Characterization of VHF radar observations associated with equatorial Spread F by narrow-band optical measurements

2004 ◽  
Vol 22 (9) ◽  
pp. 3129-3136 ◽  
Author(s):  
R. Sekar ◽  
D. Chakrabarty ◽  
R. Narayanan ◽  
S. Sripathi ◽  
A. K. Patra ◽  
...  
Keyword(s):  
Large Scale ◽  
Temporal Variations ◽  
Density Fluctuations ◽  
Optical Measurements ◽  
Small Scale ◽  
Upward Movement ◽  
Vhf Radar ◽  
Equatorial Spread F ◽  
Spread F ◽  
Airglow Intensity

Abstract. The VHF radars have been extensively used to investigate the structures and dynamics of equatorial Spread F (ESF) irregularities. However, unambiguous identification of the nature of the structures in terms of plasma depletion or enhancement requires another technique, as the return echo measured by VHF radar is proportional to the square of the electron density fluctuations. In order to address this issue, co-ordinated radar backscatter and thermospheric airglow intensity measurements were carried out during March 2003 from the MST radar site at Gadanki. Temporal variations of 630.0-nm and 777.4-nm emission intensities reveal small-scale ("micro") and large-scale ("macro") variations during the period of observation. The micro variations are absent on non-ESF nights while the macro variations are present on both ESF and non-ESF nights. In addition to the well-known anti-correlation between the base height of the F-region and the nocturnal variation of thermospheric airglow intensities, the variation of the base height of the F-layer, on occasion, is found to manifest as a bottomside wave-like structure, as seen by VHF radar on an ESF night. The micro variations in the airglow intensities are associated with large-scale irregular plasma structures and found to be in correspondence with the "plume" structures obtained by VHF radar. In addition to the commonly observed depletions with upward movement, the observation unequivocally reveals the presence of plasma enhancements which move downwards. The observation of enhancement in 777.4-nm airglow intensity, which is characterized as plasma enhancement, provides an experimental verification of the earlier prediction based on numerical modeling studies.

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

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.

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

2021 ◽  
Author(s):  
Rahul Prabhakaran ◽  
Janos Urai ◽  
Giovanni Bertotti ◽  
Christopher Weismüller ◽  
David Smeulders
Keyword(s):  
Large Scale ◽  
Fracture Network ◽  
Natural Fracture ◽  
Automated Mapping ◽  
Network Patterns

Hydro-Mechanical Modeling of the Year 2000 Hydraulic Stimulation of GPK2 Well, Soultz-sous-Forêts, France

2021 ◽  
Author(s):  
Dariush Javani ◽  
Jean Schmittbuhl ◽  
Francois Cornet
Keyword(s):  
Mechanical Behavior ◽  
Large Scale ◽  
Fracture Network ◽  
P Wave ◽  
Scale Model ◽  
Small Scale ◽  
Hydraulic Stimulation ◽  
Year 2000 ◽  
Small Scale Model ◽  
Stimulation Of

&lt;p&gt;&amp;#160;Hydraulic stimulation of pre-existing fractures and faults plays a significant role in improving hydraulic conductivity of the fracture network around injection and production wells in geothermal reservoirs. It is therefore important to characterize the hydro-mechanical behavior of the faults against fluid injection. The Soultz-sous-For&amp;#234;ts site (France) has been an EGS pilot site where several major hydraulic stimulations have been performed and are well documented (https://cdgp.u-strasbg.fr/ and https://tcs.ah-epos.eu/).&lt;/p&gt;&lt;p&gt;Here we use the 3DEC numerical modeling tool (Itasca) to analyze the year 2000 stimulation of GPK2 well where large scale seismic anomalies have been evidenced during the different stages of the stimulation using 4D-P-wave tomography (Calo et al, 2011). The specificity of the approach is to combine two modeling at different scales. First, a small-scale model (100x100x100 m&lt;sup&gt;3&lt;/sup&gt;) is built to analyze the effective mechanical response of a stochastic discrete fracture network (DFN) following the statistical features of the observed fracture network (Massart et al, 2010). Second, a large-scale numerical model of the Soultz-sous-For&amp;#234;ts reservoir (5000x5000x5000 m&lt;sup&gt;3&lt;/sup&gt;) containing the largest faults of the reservoir defined by Sausse et al., 2010, is developed including regional stresses. The objective is to constrain the large-scale mechanical properties of the surrounding matrix around the fault from the small-scale model, in particular, its hydro-mechanical behavior in terms of non-linear elastic response related to the stochastic DFN. As a first step only the largest fault (GPK3-FZ4770) is considered. The first stage of the stimulation is modelled as a constant flow rate of 30 ls&lt;sup&gt;-1&lt;/sup&gt; of water injected into the fault at the depth of approximately 4.7 km. We explored the effect of the normal and shear stiffness of the fault on the dynamical response of pore pressure along the fracture and the onset of slip. It is found that the increase of the aperture of the fault during the injection shows a slow migration (~2 cm/s) owing to poro-elastic effects. Also generated fluid pressure throughout the fault shows a long period oscillating behavior (~5 hr) sensitive to the magnitude of the fracture normal stiffness.&lt;/p&gt;

Methodology and application of shale-reservoir natural fracture modeling based on microseismic monitoring data

2020 ◽  
Vol 8 (4) ◽  
pp. SP167-SP174
Author(s):  
Ziwei Liu ◽  
Jiapeng Wu ◽  
Wenzhong Han ◽  
Yonggui Zhang ◽  
Zhenyong Li ◽  
...  
Keyword(s):  
Large Scale ◽  
Oil And Gas ◽  
Microseismic Monitoring ◽  
Natural Fracture ◽  
Fracture Model ◽  
Monitoring Data ◽  
Small Scale ◽  
Shale Oil ◽  
Fracture Modeling ◽  
Shale Reservoir

Fracturing is a key factor for shale oil and gas enrichment and high production. An accurate fracture model can effectively guide shale oil and gas exploration and development. The establishment of a natural fracture model must address the challenges of difficult data acquisition and poor representativeness of data points. To solve these problems, we have developed a method of shale-reservoir natural fracture modeling based on microseismic monitoring data. This method includes three steps. First, we establish an initial natural fracture model based on scale classification, vertical stratification, and genetic classification. Second, the shape and density of the hydraulic fractures are interpreted by microseismic monitoring data to calibrate the initial model of the shale reservoir natural fractures. Third, we verify the rationality of the model by assessment of the fracture porosity and permeability values. The results show that it is possible to calibrate the natural fracture density model using the fracture shape and density as determined by microseismic monitoring. And we predict that an ideal hydraulic fracture network can be formed when the body density of the natural fracturing is greater than 0.3 m2/m3. The crude production of wells is negatively correlated with the development of large-scale structural fractures and positively correlated with small-scale structural fractures. The well trajectory should run through small-scale fracture development sections as much as possible, avoiding large-scale, high-angle fracture areas. This method provides a new approach to model natural fractures in shale reservoirs that has wide applicability and can be used for modeling shale oil and gas reservoirs.

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