A Study of microfacies and diagenetic processes of the Asmari Formation in Khesht Oil Field with emphasis on reservoir characteristic: a case study from Zagros basin, Fars, SW Iran

Abstract

Abstract:The Oligo-Miocene Asmari Formation is the most known oil reservoir in the southwest of Iran and the Middle East. In the present study, in order to understand the reservoir quality controlling factors of the Asmari Formation, detailed petrographic studies were carried out in the Khesht Oil Field to identify microfacies, diagenetic processes affecting these microfacies and their paragenetic sequence. Six carbonate microfacies are indicated based on about two hundred microscopic thin section analyses from core samples in this field deposited in tidal flat and lagoon sub-environments on a ramp type platform. The results show that important diagenetic processes that have affected the Asmari Formation carbonates includ micritization, cementation (marine, meteoric, and burial cements), dissolution (meteoric and burial dissolution), neomorphism, mechanical and chemical compactions, fracturing, dolomitization (dolomicrite, dolomicrosparite, dolosparite and dolomite cement) and anhydritization (in different types). Dissolution and fracturing have enhanced porosity and permeability values, while cementation and compaction have decreased the reservoir potential of the Asmari Formation by occluding the pore spaces. Dolomitization has had a dual impact on the reservoir quality of the Asmari Formation.Keywords: Diagenesis, Microfacies, Reservoir quality, Asmari Formation, Khesht Oil Field. Introduction:Carbonate rocks host about 50% of the global hydrocarbon accumulations. Therefore, they are still the main subject of many studies (Adabi et al. 2016; Jafarian et al. 2017; Omidpour et al. 2021). Carbonate reservoirs are difficult to describe and produce a realistic picture of reservoir properties due to the vertical and lateral heterogeneity in various categories, including lateral distribution of facies (Alsharhan 2006; Dou et al. 2011) and complex diagenetic evolution of carbonates (Lucia 2007; Moore 2013). Heterogeneity in the petrophysical properties of a reservoir is a combination of the primary depositional environmental factors (physical, chemical, and biological) and diagenetic processes (Nabawy et al. 2018; Tavakoli 2019).Carbonates of the Asmari Formation form the main part of reservoirs in SW Iran. So far, no study has been conducted to investigate the reservoir characteristics of the Asmari Formation in the Khesht Oil Field. These carbonates are generally deposited in a shallow marine environment (Aqrawi et al. 2006; Omidpour et al. 2021). Based on previous studies, the age of this formation is Oligocene (Rupelian) to Early Miocene (Burdigalian) (Richardson 1924; Thomas 1948; Ehrenberg et al. 2007). Based on biostratigraphic studies conducted by the oil company in the Khesht Oil Field, the Asmari Formation in the Khesht Oil Field was deposited during the Early Miocene (Aquitanian).The estimated porosity from thin section petrographic studies shows that due to the abundance of lime mud and low textural maturity, their reservoir capacity was low in the time of deposition (Hassanvand 2016; Esrafili‐Dizaji and Rahimpour‐Bonab 2019). Therefore, it seems that the reservoir quality of this formation largely depends on the development of secondary porosity as a result of the performance of various diagenetic processes such as dolomitization, fracturing, and dissolution (McQuillan 1985; Aqrawi et al. 2006; Azomani et al. 2013). Due to the importance of the Asmari Formation as the most known reservoir in the Zagros region, the combination of facies analysis and diagenetic characteristics of the Asmari Formation samples in the framework of porosity and permeability was used for reservoir quality evaluation. Material & MethodsThis study is based on a petrographic analysis of 183 thin sections from core samples of Khesht-02 and Khesht-03 wells drilled in the Asmari Formation at the Khesht Oil Field. In this way, 53.5 m of cores and 116 half-stained thin sections from the KH-02 well and 28 m of cores and 67 half-stained thin sections from the KH-03 well, as well as porosity and permeability data were used. All thin sections were stained with potassium ferricyanide and Alizarin Red-S to distinguish carbonate minerals (Dickson 1965). Thin sections were then examined under a microscope using a plane and polarized light to investigate facies distribution and diagenetic processes in the studied interval. Carbonates were classified based on the schemes of Dunham (1962) for limestones, and Sibley and Gregg (1987), Warren (2000), and Adabi (2009) for dolomites. Facies analysis and interpretation of the depositional environment was performed using the standard microfacies classification by Wilson (1975) and Flügel (2010). Helium porosity and air permeability (measured on core plugs) were used for the evaluation of reservoir potential of the studied intervals. Discussion of Results & ConclusionThe Early Miocene Asmari Formation in the Khesht Oil Field, SW Iran, is mainly composed of dolomitic lithology. Petrographical studies led to identifying six carbonate microfacies in the Asmari succession deposited on a carbonate ramp platform. These microfacies consist of MF1) Anhydrite - inner ramp (supratidal); MF2) Sandy dolomudstone - inner ramp (intertidal); MF3) Dolomitized peloidal bioclastic wackestone - inner ramp (restricted lagoon); MF4) Dolomitized peloidal bioclastic imperforate foraminifer wackestone/ packstone - inner ramp (restricted lagoon); MF5) Dolomitized peloidal bioclastic packstone/ grainstone - inner ramp (platform margin); and MF6) Coral framestone – inner ramp (platform margin). These microfacies have been subjected to a variety of diagenetic processes in the three diagenetic realms, including marine, meteoric, and shallow to deep burial. The wide range of porosity and permeability values in most facies of the Asmari Formation shows that diagenetic features changed many other primary properties of the Asmari carbonates. The main diagenetic features that improved the reservoir quality were dissolution, dolomitization, and fracturing. Occlusion of pores and pore throats as a result of various calcite and anhydride cementation processes especially in wackestone and packstone textures, pervasive dolomitization and of mechanical and chemical compactions decreased the reservoir quality.

Keywords

• diagenesis
• microfacies
• reservoir quality
• asmari formation
• khesht oil field