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

Creative Commons License

Yilmaz I. Ö., Orlov A., Özkul C., Bensenouci F., Yazaroğlu M., Mengen A. E.

21th International Petroleum and Natural Gas Congress and Exhibition of Turkey, Ankara, Turkey, 27 October - 29 November 2023, pp.131-132

  • Publication Type: Conference Paper / Summary Text
  • City: Ankara
  • Country: Turkey
  • Page Numbers: pp.131-132
  • Middle East Technical University Affiliated: Yes


Traditional description of unconventional reservoir like

any natural fracture reservoirs relies heavily on quality

and analysis of image logs and core data at discrete well

locations. These data provide high vertical resolution

information but soon becomes challenging to use and

propagate away from the borehole. The presented

modeling process is generally based on pure stochastic

workfl ow that tries to achieve realistic 3D model of

fractured reservoir by matching the well information,

in-situ stress and capture inter-well heterogeneity

using 3D seismic data. This workfl ow has been

tested on unconventional natural fracture reservoir in

Diyarbakir basin where late Silurian – lower Devonian

age Dadas-1 organic rich shale member exhibits both

low porosity and extremely low matrix permeability.

Acting as one of the main source rocks in SE Turkey,

it represents a self-sourced unconventional play. The

interpretation of image logs and core samples reveals

clusters of fractures suggesting a naturally fracture

reservoir type 1. This study aims at using an integrated

approach spanning from seismic interpretation to image

log data analysis and 3D geomechanics to develop a

discrete fracture network model (DFN) and to provide

new insights into distribution of hydrocarbons since

fractures is solely responsible for making this reservoir

producible(Figure 1). In addition, a derived DFN model

off ers an opportunity to improve a reservoir modeling

(static and dynamic), to provide the basis for design of

an optimum well placement, stimulation, completion,

production and could serve as a guide on how to

improve the seismic acquisition/resolution to highlight

valuable fracture zones.


This integrated study uses borehole image log

data acquired in the Dadas-1 member interval of 3

exploration wells: A, B and C, 3D seismic volume

and 3D geomechanical model. Fracture modeling was

performed using a fracture modeling software that

calculates fracture permeability, porosity and matrix

block size on 3D reservoir grids by constructing the

DFN model. The main steps of the workfl ow were: 1).

to use previously interpreted image log data and classify

the natural fractures by fracture sets using dip azimuth

distribution. The wellbore fracture data is dominantly

striking in E-W and N-S directions with a large number

having a high (> 60 degree) dip angle. Important to

note is that the statistical likelihood of intersecting high

(>50 degree) angled fractures is reduced by drilling

vertical wells, suggesting that the vertical wells used

in this study may be underestimating the true fracture

density; 2) evaluate possible fracture drivers, defined

as any 3D properties that can be sensitive to or capture

directly fracture intensity information in the interwell

space. The fracture drivers used in our workfl ow

are various post-stack seismic attributes: Variance,

Curvature, Chaos, Ant-Tracking, Sweetness and etc.

All tested seismic attributes are used as input to a multiscale

statistical correlation analysis where previously

derived 1D intensity logs using image logs were

matched. Because seismic domain comes with inherent

resolution limitations compared to borehole data the

fracture intensity logs were generated with diff erent

window filter size to evaluate the best scaling factor for

optimizing correlation with the seismic domain. The

best fracture drivers for the total intensity log before

splitting on sets appear to be 3D Curvature (≈0.66

correlation factor), Chaos (≈0.43 correlation factor)

and fl atness (≈0.55). These 3 seismic cubes supervised

by interpreted intensity values at well locations were

used to derive 3D fracture intensity cube (or 3D

fracture driver). The QC crossplot between interpreted

and predicted intensity logs shows correlation value

0.88; 3) to review this analysis in the context of the

seismic structural interpretation and regional tectonic

framework. Since the fracture distribution and density

relate to the tectonic features (faults), Ant-tracking

3D seismic attribute was used to derive seismically

resolved faults/fractures. All captured by Ant-tracking

discontinuities were split into two tectonic sets based

in the strike direction and relationship to tectonic

events: Set-1 fault polygons in black that have West-

East orientation and formed during 1st tectonic event

and Set-2 fault polygons in red that striking in North-

South and formed during 2nd tectonic period (Figure

2); 4) to employ 3D geomechanical model to determine

the likelihood of natural fractures undergoing tensile

reactivation. This model does not consider variables

such as fracture plane roughness, cementation, pressure

variation, or the possibility of crystal bridging, which

has been shown to enable fractures to remain open and

permeable albeit not preferentially aligned with σ1.

Importantly, all fracture types (conductive, partially

conductive and resistive) were used for the modeling.

Natural fractures in shale, as weak planes of mechanical

heterogeneity, can reactive and widen the treatment

zone, aff ect propagation and intensity of artificial

fractures. Even the cemented fractures, i.e. mineral

veins, can considerably contribute to eff icient hydraulic

fracture treatment, because of the weak chemical bond

between the fracture-filling minerals and their wall

rocks that can be easily broken apart.