Elsevier

Marine and Petroleum Geology

Volume 77, November 2016, Pages 898-915
Marine and Petroleum Geology

Research paper
Diagenesis and its impact on the reservoir quality of Miocene sandstones (Surma Group) from the Bengal Basin, Bangladesh

https://doi.org/10.1016/j.marpetgeo.2016.07.027Get rights and content

Highlights

  • Reservoir quality of Miocene deltaic-marine sandstones from Bangladesh buried up to 3200 m and 115 °C was studied.

  • Depth and ductile grain content control compaction and porosity-loss.

  • Calcite is the dominant cement, growing from meteoric water at low temperature.

  • Quartz cement is minor due to limited time for growth and chlorite grain coats.

  • Rapid burial (150 m/myr) and mineralogical immaturity of primary sediment are the master controls on reservoir quality.

Abstract

Rapid supply and deposition of 1000's of meters of Miocene and Pliocene sediment tend to lead to a different set of controls on reservoir quality than older, more slowly buried sandstones. Here we have studied Miocene fluvial-deltaic Bhuban Formation sandstones, from the Surma Group, Bengal Basin, buried to >3,000 m and >110 °C, using a combination of petrographic, geochemical and petrophysical methods in order to understand the controls on Miocene sandstone reservoir quality to facilitate improved prediction of porosity and permeability. The main conclusions of the study are that mechanical compaction processes are the dominant control on porosity-loss although early calcite growth has led to locally-negligible porosity in some sandstones. Mechanical compaction occurred by grain rearrangement, ductile grain compaction and brittle grain fracturing. Calcite cement, occupying up to 41% intergranular volume, was derived from a combination of dissolved and recrystallized bioclasts, an influx of organic-derived carbon dioxide and plagioclase alteration. Clay minerals present include smectite-illite, kaolinite and chlorite. The smectitic clay was probably restricted to low energy depositional environments and it locally diminishes permeability disproportionate to the degree of porosity-loss. Kaolinite is probably the result of feldspar alteration resulting from the influx of organic-derived carbon dioxide. Quartz cement is present in small amounts, despite the relatively high temperature, due to a combination of limited time available in these young sandstones, grain-coating chlorite and low water saturations in these gas-bearing reservoir sandstones. Reservoir quality can now be predicted by considering primary sediment supply and primary depositional environment, the magnitude of the detrital bioclast fraction and the influx of organic-derived carbon dioxide.

Introduction

The Bengal Basin in Southeast Asia covers most of Bangladesh and is known as a prolific petroleum-bearing basin. It contains up to 22,000 m of Cretaceous to Holocene sedimentary fill (Alam et al., 2003). This huge succession includes about ∼4000 to 5000 m of Neogene sediment of the petroliferous Surma Group (Table 1) buried to 2300 to 3100 m. So far, twenty-five economically-viable fields have been discovered in Bangladesh. Predominantly, these are gas fields in the Miocene Surma Group sandstones. These recently-discovered gas fields have become a significant source of hydrocarbon in the Bengal Basin and promise to serve as an engine of economic growth for Bangladesh. There are several publications that have dealt with the regional geology, sedimentology, tectonic evolution and petroleum prospectivity of the Surma Basin, especially for the north-eastern petroleum province (Hiller and Elahi, 1984, Johnson and Alam, 1991, Khan et al., 1988, Lietz and Kabir, 1982, Rahman et al., 2009, Shamsuddin et al., 2001). However, relatively few publications focus on the reservoir quality and diagenesis of the sandstone units (Imam and Shaw, 1987, Islam, 2009, Rahman and McCann, 2012, Rahman et al., 2011).

Reservoir quality (porosity and permeability) is a key control on success during petroleum exploration, along with source presence, maturation, migration, trap and seal. Reservoir quality is a function of primary sand texture and composition and the secondary diagenetic processes of compaction, mineral cementation, mineral replacement and mineral dissolution (Worden and Burley, 2003). The necessarily limited time available to bury Miocene sediment to >2000 m requires either a very large river system spewing sediment into a basin with a restricted dimensions, or a major tectonic event (e.g. the Himalayan orogeny) in the sediment's hinterland (or a combination of both reasons). The Bengal Basin has accumulated sediment at about 150 m/myr, a value that is approximately ten times greater than, for example, the rate of sediment accumulation for the Brent Group reservoirs in the North Sea. There are some notable differences in the controls on reservoir quality in Neogene sandstones at ∼2000 to 3500 m compared to Paleogene or older sandstones, at equivalent depths, due to the accelerated rate of sediment supply and burial. The rapid burial and consequent heating of Miocene sediments to >2300 m suggests that kinetically-controlled diagenetic processes, for example carbonate neoformation, clay mineral transformations or the growth of quartz cement, will be less advanced than in older basins at the same depth and temperature (Dutton et al., 2012, Gier et al., 2008). Furthermore if a major Miocene tectonic event led to the supply of a vast amount of sediment from the surrounding mountain belts, it is likely that the supplied sediment will be mineralogically immature compared to sediment supplied and accumulated more slowly (Worden et al., 1997, Worden et al., 2000). Therefore, it is important to have a detailed understanding of sandstone diagenesis during petroleum exploration in young, e.g. Miocene, basins. Previous studies on diagenetic cements in the Bengal Basin revealed a dominant presence of calcite cement in the Surma Group (Rahman and McCann, 2012). The present investigation is a petrographic and geochemical study of Surma Group sandstones dominantly from the central Bengal Basin. It builds on earlier work (Imam and Shaw, 1987, Islam, 2009, Rahman and McCann, 2012, Rahman et al., 2011) by undertaking a full assessment of all the possible controls on reservoir quality, extending the study to a great range of depths (2303 m–3178 m; Fig. 2), using stable isotope data from calcite cement from the central Bengal Basin and, for the first time, incorporating core analysis data. Samples have been collected from six exploration wells from four gas fields (Jalalabad, Meghna, Narsingdi, SaldaNadi and Titas; Fig. 1).

This paper specifically seeks to address the following research questions:

  • 1)

    Is compaction or cementation the dominant control on reservoir quality in young (Miocene) sandstones buried to more than 3000 m?

  • 2)

    What are the main sources of carbonate cement in these young and deeply buried sandstones and can we predict this control on reservoir quality?

  • 3)

    Is quartz cement common in these young sandstones heated to more than 100C°?

  • 4)

    What are the key aspects of diagenesis to consider in an assessment and prediction of reservoir quality of young sandstones buried to more than 3000 m and heated to more than 100C°?

Section snippets

Geological setting

The Cretaceous to Holocene Bengal Basin lies on the eastern side of the Indian subcontinent between the Shillong Plateau to the north, and the Indo-Burman Ranges to the east. The Bengal Basin occupies most of Bangladesh and West Bengal (India) as well as part of the Bay of Bengal (Fig. 1). Basin development is concluded to have started in the Early Cretaceous epoch (ca. 127 Ma) when the Indian plate rifted away from Antarctica, although there is ongoing debate about the precise timing of

Samples and methods

Thin section petrographic analysis was performed on 85 sandstone core samples collected at a range of depths between 2303 m and 3178 m from six exploratory wells from four gas fields: Jalalabad (JL-2, JL-3, both drilled in 1989), Meghna (BK-9, 1990), Narshingdi (BK-10, 1990), and Titas (TT-11, 1990; TT-15, 2006). Samples for thin-section study were impregnated with blue epoxy to facilitate petrographic recognition of porosity. Thin sections were stained with Alizarin-Red S and

Detrital composition and rock fabric

The Surma Group sandstones are predominantly fine-grained and moderately sorted, with minor amounts of very fine-grained and very well sorted sandstones. Grain-contacts are dominated by long, concavo-convex surfaces with some sutured contacts (Fig. 4a). Some grains have undergone brittle fracturing while others have undergone ductile compaction as shown by (Fig. 4b, c, d).

Petrographic compositions of the Surma Group sandstones is reported in Table 2. They are predominantly subarkosic to

Sequence of diagenetic events

The presence of framboidal pyrite (Fig. 9f) requires near-surface, low temperature, sulphate reducing bacteria in the presence of sulphate-rich marine pore waters (Berner, 1980); pyrite was probably one of the first minerals to grow in these sandstones, confirming the marine influence on these sandstones.

Grain-contacts are dominated by long, concavo-convex surfaces with some suture contacts. This suggests that the sandstones might have been subjected to moderate to high degree of mechanical

Conclusions

  • 1)

    The Miocene Surma Group in the Bengal Basin, buried to 2300 m and 3200 m, contains sub-arkosic to sub-litharenitic, tide-dominated, deltaic sandstones.

  • 2)

    The main reservoir quality control in these young, but relatively deeply buried, sandstones is mechanical compaction. Depth of burial and the detrital ductile grain content had important controls on the extent of mechanical compaction. Lithic ductile-rich sandstones have undergone more compaction than ductile-poor sandstones.

  • 3)

    Cement growth was

Acknowledgements

First author would like to thank Commonwealth Scholarship Commission (CSC) United Kingdom for granting a Commonwealth Academic Fellowship (2012) to carry out this research project. This work was partly sponsored by Alexander von Humboldt Foundation (AvH), Germany. We are grateful to BAPEX (Bangladesh Petroleum Exploration and Production Company) for giving permission to analyze core samples. We are thankful to Prof. Dr. Andreas Mackensen, Alfred Wegener Institute, Germany and Dr Steve Crowley,

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