Natural Fracture Modeling in Unconventional Dadaş-1 Member for 3d Seismic Survey: 131 Case Study, Turkey

Date

2023-10-27

Author

Yılmaz, İsmail Ömer
Orlov, Artem
Özkul, Canalp
Bensenouci, Fethi
Yazaroğlu, Mehmed
Mengen, Ahmet Ergün

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Traditional description of unconventional reservoir likeany natural fracture reservoirs relies heavily on qualityand analysis of image logs and core data at discrete welllocations. These data provide high vertical resolutioninformation but soon becomes challenging to use andpropagate away from the borehole. The presentedmodeling process is generally based on pure stochasticworkfl ow that tries to achieve realistic 3D model offractured reservoir by matching the well information,in-situ stress and capture inter-well heterogeneityusing 3D seismic data. This workfl ow has beentested on unconventional natural fracture reservoir inDiyarbakir basin where late Silurian – lower Devonianage Dadas-1 organic rich shale member exhibits bothlow porosity and extremely low matrix permeability.Acting as one of the main source rocks in SE Turkey,it represents a self-sourced unconventional play. Theinterpretation of image logs and core samples revealsclusters of fractures suggesting a naturally fracturereservoir type 1. This study aims at using an integratedapproach spanning from seismic interpretation to imagelog data analysis and 3D geomechanics to develop adiscrete fracture network model (DFN) and to providenew insights into distribution of hydrocarbons sincefractures is solely responsible for making this reservoirproducible(Figure 1). In addition, a derived DFN modeloff ers an opportunity to improve a reservoir modeling(static and dynamic), to provide the basis for design ofan optimum well placement, stimulation, completion,production and could serve as a guide on how toimprove the seismic acquisition/resolution to highlightvaluable fracture zones.METHODS, PROCEDURES, PROCESSThis integrated study uses borehole image logdata acquired in the Dadas-1 member interval of 3exploration wells: A, B and C, 3D seismic volumeand 3D geomechanical model. Fracture modeling wasperformed using a fracture modeling software thatcalculates fracture permeability, porosity and matrixblock size on 3D reservoir grids by constructing theDFN model. The main steps of the workfl ow were: 1).to use previously interpreted image log data and classifythe natural fractures by fracture sets using dip azimuthdistribution. The wellbore fracture data is dominantlystriking in E-W and N-S directions with a large numberhaving a high (> 60 degree) dip angle. Important tonote is that the statistical likelihood of intersecting high(>50 degree) angled fractures is reduced by drillingvertical wells, suggesting that the vertical wells usedin this study may be underestimating the true fracturedensity; 2) evaluate possible fracture drivers, definedas any 3D properties that can be sensitive to or capturedirectly fracture intensity information in the interwellspace. The fracture drivers used in our workfl oware various post-stack seismic attributes: Variance,Curvature, Chaos, Ant-Tracking, Sweetness and etc.All tested seismic attributes are used as input to a multiscalestatistical correlation analysis where previouslyderived 1D intensity logs using image logs werematched. Because seismic domain comes with inherentresolution limitations compared to borehole data thefracture intensity logs were generated with diff erentwindow filter size to evaluate the best scaling factor foroptimizing correlation with the seismic domain. Thebest fracture drivers for the total intensity log beforesplitting on sets appear to be 3D Curvature (≈0.66correlation factor), Chaos (≈0.43 correlation factor)and fl atness (≈0.55). These 3 seismic cubes supervisedby interpreted intensity values at well locations wereused to derive 3D fracture intensity cube (or 3Dfracture driver). The QC crossplot between interpretedand predicted intensity logs shows correlation value0.88; 3) to review this analysis in the context of theseismic structural interpretation and regional tectonicframework. Since the fracture distribution and densityrelate to the tectonic features (faults), Ant-tracking3D seismic attribute was used to derive seismicallyresolved faults/fractures. All captured by Ant-trackingdiscontinuities were split into two tectonic sets basedin the strike direction and relationship to tectonicevents: Set-1 fault polygons in black that have West-East orientation and formed during 1st tectonic eventand Set-2 fault polygons in red that striking in North-South and formed during 2nd tectonic period (Figure2); 4) to employ 3D geomechanical model to determinethe likelihood of natural fractures undergoing tensilereactivation. This model does not consider variablessuch as fracture plane roughness, cementation, pressurevariation, or the possibility of crystal bridging, whichhas been shown to enable fractures to remain open andpermeable albeit not preferentially aligned with σ1.Importantly, all fracture types (conductive, partiallyconductive and resistive) were used for the modeling.Natural fractures in shale, as weak planes of mechanicalheterogeneity, can reactive and widen the treatmentzone, aff ect propagation and intensity of artificialfractures. Even the cemented fractures, i.e. mineralveins, can considerably contribute to eff icient hydraulicfracture treatment, because of the weak chemical bondbetween the fracture-filling minerals and their wallrocks that can be easily broken apart.

URI

https://hdl.handle.net/11511/107654

Collections

Department of Geological Engineering, Conference / Seminar