--> --> ABSTRACT: Characterization and Modeling of Tight Fractured Carbonate Reservoir of Najmah-Sargelu Formation, Kuwait, by Nath, Prabir K.; Singh, Sunil K.; Abu-Taleb, Reyad; Prasad, Raghav; Khan, Badruzzaman; Bader, Sara; #90155 (2012)
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Characterization and Modeling of Tight Fractured Carbonate Reservoir of Najmah-Sargelu Formation, Kuwait

Nath, Prabir K.; Singh, Sunil K.; Abu-Taleb, Reyad; Prasad, Raghav; Khan, Badruzzaman; Bader, Sara
Prospect Evaluation Team, KOC, Kuwait, Kuwait.

Najmah Sargelu Formation of Oxfordian-Kimmeridgian age has good commercial production potential of oil and gas in Kuwait. The formation consists of argillaceous limestone and kerogen and is characterized by low matrix porosity and considerable fracture porosity. The fracture porosity is related to micro, meso and mega fractures. The open fractures play an important role in terms of producibility, since the fracture permeability is far more significant compared to the storage capacity of the fracture and matrix porosity.

This paper presents the workflow used for analyzing and integrating multidisciplinary data sets in order to develop an integrated 3D property and fracture model with the goal of reducing exploration drilling risk and optimizing reservoir appraisal and development. Core data, wire line log, sequence stratigraphic framework, seismic grid, acoustic impedance volume were used to build a robust 3D geo-statistical facies and property model. The distribution of internal properties and heterogeneity has been quantitatively described as the relationship of a reservoir facies within sequence stratigraphic framework. Three sets of sub-vertical conductive fractures interpreted from image log and core data, record strike 30 -60, 90 - 120 and 165-195 degree . Integration of the facies, core fracture data, and image logs are used to quantify and to rank fracture contents. A set of fracture intensity models was generated as a property model by a Sequential Gaussian Simulation and Neural Network and co-krigged with ant-track and Previous HitcoherencyNext Hit volume. The major fracture sets were modeled as a combined DFN (Discrete Fracture Network) and IFM (Implicit Fracture Model) using geological (facies, porosity and fracture intensity) and seismic (ant-track and Previous HitcoherencyTop) drivers. Correlation with mud loss and gain data, well site gas analysis data, production data and analog were studied in order to understand fluid conductivity of modeled fracture network. The well test analysis is used to understand the main flow mechanism occurring in the reservoir.

The integrated 3D model explains the distribution of storage and maximum drainage area connected through fracture network within the reservoir. This has attained a prudent solution for exploration and appraisal challenges of type-II carbonate reservoir.

 

AAPG Search and Discovery Article #90155©2012 AAPG International Conference & Exhibition, Singapore, 16-19 September 2012